Статті в журналах з теми "Abandoned hydrocarbon well"

Summary In the next decades, tens of thousands of well plugging and abandonment (P&A) operations are expected to be executed worldwide. Decommissioning activities in the North Sea alone are forecasted to require 2,624 wells to be plugged and abandoned during the 10-year period starting from 2019 (Oil&Gas_UK 2019). This increase in decommissioning activity level and the associated high costs of permanent P&A operations require new, fit-for-purpose, P&A design tools and operational technologies to ensure safe and cost-effective decommissioning of hydrocarbon production wells. This paper introduces a novel modeling framework to support risk-based evaluation of well P&A designs using a fluid-flow simulation methodology combined with probabilistic estimation techniques. The developed well-centric modeling framework covers the full range of North Sea P&A well designs and allows for quantification of the long-term (thousands of years) evolution of hydrocarbon movement in the plugged and abandoned well. The framework is complemented by an in-house visualization tool for identification of the dominant hydrocarbon flow-paths. Monte Carlo methods are used to account for uncertainties in the modeling inputs, allowing for robust comparison of various P&A design options, which can be ranked on the basis of hydrocarbon leakage risks. The proposed framework is able to model transient conditions within the well P&A system, allowing for the development of new key performance indicators (e.g., time until hydrocarbons reach surface and changes in hydrocarbon saturation within the P&A well). Such key performance indicators are not commonly used, because most published work in this area relies on steady-state P&A models. The developed framework was used in the assessment of several P&A design cases. The results obtained, which are presented in this paper, demonstrate its value for supporting risk-based decision-making by allowing for quantitative comparison of the expected performance of multiple P&A design options for given well/reservoir conditions. The framework can be used for identifying cost-effective, fit-for-purpose P&A designs, for example by optimizing the number, location, and length of wellbore barriers and evaluating the effectiveness of annular cement sheath remedial operations. Additionally, this framework can be used as a sensitivity analysis tool to identify the critical parameters that have the greatest impact on the modeled leakage risks, to guide data acquisition plans and model refinement steps aimed at reducing the uncertainties in key model parameters.

There are various types of extraction and utilization possibilities of geothermal energy, of which a large group is energy recovery. The development of this sector is slow mainly due to its high initial investment demand and the long planning phase. The overall goal of the present research is cutting the cost of the drilling phase as the most expensive part of the establishment by repurposing unused and abandoned hydrocarbon wells. The article assesses the feasibility of a geothermal well-triplet system chosen to be the most promising technique amongst several utilization possibilities depending on the characteristics of both the geological media and the method itself. From the 14 examined abandoned wells three were found to be suitable based on their current condition and distance from each other. The mentioned technique requires an adequately porous and permeable media which was not provided by the initial depth of the wells, thus the considerable option left was to overdrill the existing wells till they reach the target geology, the known fractured karstic aquifer below. The current study summarizes the final results of a long going research, from the geographical-, lithological surveys till the potential heat-transport modeling. This article supports the final aspirations of a further going research project as an integral part of it carried out by the University of Miskolc.

The aim of our research is to use abandoned deep-hydrocarbon reservoirs and dry wells in the Croatian part of the Pannonian Basin as a geothermal energy source. Croatia has been exploring and exploiting hydrocarbon reserves in the Pannonian Basin from the mid-20th century. Therefore, many oil and gas wells are reaching the end of their production phase and many are already abandoned. These wells could be considered for geothermal energy production through the coaxial heat exchanger principle, which is usually used in shallow geothermal energy extraction. Using the abandoned deep well Pčelić located in the Drava subbasin as a case study, we have derived the available energy and fluid temperature changes during 20 years of operation for two cases: one with a constant base heat load throughout the year and the second as a variable heat load depending on outside air temperatures. We determined that the maximum potential heat extraction in a variable system is 1750 MWh per year, with 1.5 MW of peak heating power in winter, depending on the sink temperature, climate, and consumer input data. The maximum theoretical constant heat extraction for possible industrial direct heating could be 400 kW during the entire period of 20 years, with fluid temperature reaching steady state at a favorable 50°C. To define steady-state ratio between extracted heat and consumed energy at the circulating pump, we evaluated seasonal performance factor (SPF) analysis similar to heat pump systems. Lower values of SPF linked to a higher flow rate implies higher energy extraction. Our results show that when using a lower flow, steady-state SPF ratio is as high as 280, and for a higher flow, steady-state SPF ratio drops to only 25.

To date, many developing countries such as Iran have almost completely abandoned the idea of decontaminating oil-polluted soils due to the high costs of conventional (physical/chemical) soil remediation methods. Phytoremediation is an emerging green technology that can become a promising solution to the problem of decontaminating hydrocarbon-polluted soils. Screening the capacity of native tolerant plant species to grow on aged, petroleum hydrocarbon-contaminated soils is a key factor for successful phytoremediation. This study investigated the effect of hydrocarbon pollution with an initial concentration of 40 000 ppm on growth characteristics of sorghum (Sorghum bicolor) and common flax (Linum usitatissumum). At the end of the experiment, soil samples in which plant species had grown well were analyzed for total petroleum hydrocarbons (TPHs) removal by GC-FID. Common flax was used for the first time in the history of phytoremediation of oil-contaminated soil. Both species showed promising remediation efficiency in highly contaminated soil; however, petroleum hydrocarbon contamination reduced the growth of the surveyed plants significantly. Sorghum and common flax reduced TPHs concentration by 9500 and 18500 mg kg‑1, respectively, compared with the control treatment.

There are many oil and gas fields around the world where the vast number of wells have been abandoned or suspended, mainly due to the depletion of reserves. Those abandoned oil and gas wells (AOGWs) are often located in areas with a prospective geothermal potential and might be retrofitted to a geothermal system without high-cost drilling. In Poland, there are thousands of wells, either operating, abandoned or negative, that might be used for different geothermal applications. Thus, the aim of this paper is not only to review geothermal and petroleum facts about the Eastern Carpathian Foredeep, but also to find out the areas, geological structures or just AOGWs, which are the most prospective in case of geothermal utilization. Due to the inseparability of geological settings with both oil and gas, as well as geothermal conditionings, firstly, the geological background of the analyzed region was performed, considering mainly the autochthonous Miocene formation. Then, geothermal and petroleum detailed characteristics were made. In the case of geothermal parameters, such as formation’s thickness, temperatures, water-bearing horizons, wells’ capacities, mineralization and others were extensively examined. Considering oil and gas settings, insights into reservoir rocks, hydrocarbon traps and migration paths issues were created. Then, for evaluating geothermal parameters for specific hydrocarbon reservoirs, their depths were established based on publicly available wells data. Thereafter, the average temperatures for selected reservoirs were set. As the effect, it turned out that most of the deposits have average temperatures of 40/50 °C, nonetheless, there are a few characterized by higher (even around 80 °C) temperatures at reasonable depths.

To explore, delineate, and produce hydrocarbon reserves, holes must be drilled into geologic formations. During the course of production, wells may become inactive because of diminished economic returns or technical problems, and be shut-in or temporarily abandoned. At the end of the life of every well, the well will be permanently plugged and abandoned (P&A). The P&A process is the first stage of a decommissioning program in which a site is returned to its original greenfield status in accord with regulatory requirements. The purpose of this paper is to describe the factors that influence P&A operations and summarize cost statistics from a sample of 118 jobs and 390 wells performed by Tetra Applied Technologies in the Gulf of Mexico from 2002-2003. Descriptive statistics are summarized and the impact of learning and scale economies are examined. Regression models are derived that estimate the cost of P&A activities based on job characteristics.

There are several hundred of abandoned oil wells in Jianghan oil field now. They were mainly started to be used in 70-80`s of last century, and mainly closed around 2000. After closure, the soil around the oil wells left uncultivated because of oil pollution, which caused serious waste of soil resource. In the present paper, 135 soil samples were collected from 15 oil well areas. Salinity, pH, petroleum hydrocarbon, heavy metals and some other elements were analyzed. According to the investigation, the soil of Jianghan oilfield showed high salinity, and tended to alkali. Petroleum hydrocarbon is dotted distribution, and some sites showed extremely high content as 24.67%. Some elements containing some heavy metals in Jianghan oilfield exceeded standard values and control samples, which may also be caused by oil exploitation.

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22348, “Scrutinizing Well Integrity for Determining Long-Term Fate of a CO2 Sequestration Project: An Improved and Rigorous Risk-Assessment Strategy,” by Parimal A. Patil, SPE, Asyraf M. Hamimi, and M. Azuan B. Abu Bakar, Petronas, et al. The paper has not been peer reviewed. Copyright 2022 International Petroleum Technology Conference. Reproduced by permission. _ Depleted hydrocarbon reservoirs are considered inherently safe for carbon sequestration, but a high density of wells penetrating the carbon dioxide (CO2) storage reservoir could compromise containment performance in a carbon capture and sequestration (CCS) project. A risk-management methodology can be incorporated to evaluate primary and secondary barriers in existing plugged and abandoned (P&A) and development wells to ensure long-term viability of CO2 sequestration projects. The complete paper evaluates well-integrity and CO2 leakage risks along the wells in a depleted field that penetrates the CO2 storage reservoir. Background The identified CO2 storage site offshore Malaysia is a depleted hydrocarbon field discovered in the early 1980s. Subsequently, two appraisal wells were drilled to further assess the field’s development potential. The structure is a north/south anticline with an aerial extent of approximately 35 km2 and a vertical closure of 100 m on top of the reservoirs. Eighteen major and minor gas-bearing reservoirs exist in the field. The hydrocarbons from deeply buried reservoirs were produced over a period of approximately 15 to 25 years through deviated wellbores. In total, 24 wells are in the targeted field; of these, three are abandoned exploration and appraisal wells and 21 are development wells drilled from the platform. All exploration and appraisal wells are P&A, while 21 development wells are still accessible from the platform. High uncertainties are associated with the P&A wells because the well sites were restored per a regulatory requirement in which the casings were cut below mudline and a surface cement plug was placed with no intention of re-entering these wells. Development wells, on the other hand, were assessed and screened for reuse by conversion into CO2 injectors. Understanding Well Integrity for CO2 Storage Potential leakages that may occur through various mechanisms during geological storage of CO2 in the storage field include failed caprock and trap integrity and leakage along existing wellbores. Parameters that could cause leakage of CO2 because of failed caprock include existing faults or fractures, reactivation of faults, development of new fractures during injection, and caprock failure caused by pressures exceeding fracture pressure during or after injection. The geological analysis of the depleted field for potential development as a future CO2 storage site must understand and mitigate associated risks by integrating information from various databases. However, the integrity of wells in the storage project must be ensured over very long time scales, in the thousands of years.

Abstract Under Colombian petroleum legislation, certain procedures must be applied when an oil well that has been drilled turns out to be dry or must be abandoned due to mechanical problems. In these cases the steps of physical abandonment, dismantling of facilities and restoration must be fulfilled, a situation that can occur in any of the phases of the contract, leading to a variation in the obligations by the concessionaire according to the activities that must be performed in each phase. The Agencia Nacional de Hidrocarburos (ANH by its acronym in Spanish) is the administrator of the hydrocarbon resource in Colombia and within its functions is the concession aire of the areas for the exploration and exploitation of hydrocarbons. This document highlights the role of the ANH as a contractual subject and responsible for compliance with the contractual obligations between the Agency and the concessionaires as well as the rules and regulations established by law. Liabilities may arise in relation to non-fulfilment of these obligations, which have led to a series of solution mechanisms being devised, according to the special nature of the concession.

At the beginning of petroleum industry evolving the regulation did not focus on environmental issues, it was, mainly, looking to natural resources (oil and gas) production and protection. By the time, environmental and safety implications started to be the highest priority, as a result of undesirable impact of oil operations on plant. Huge numbers of dry wells were abandoned according to environmental regulations to prevent side effects which involved contamination of shallow water aquifers, surface seepage of hydrocarbon (whether oil or gas) or salty water, potential hazardous of explosion or soil contaminations, and water contamination at offshore unplugged wells. Based on the hazards above, the main objectives of plugging and abandonment operations is to achieve isolation and protection of all fresh and near fresh water zones, and all future commercial zones, as well as prevent leaks in perpetuity from or into the well and remove surface equipment and cut pipe to a mandated level below the surface. In this paper, an Iraqi oil well was studied as a case study of abandonment processes. The well represents a danger to people, environment and subsurface fresh water; due to unusual raised pressure in different annuluses and copious surface leak from wellhead components while production. Worthily to say that, it is seldom in Iraq to abandon the wells in current time, according to good reservoirs situation. The reasons and justifications of this well plugging, depending on economic analysis and investigation were studied, and explained, according to international practices and procedures of such treatments. The workover option is most economic option, but it was eliminated due to failure in ensuring the well safety and severe environmental impact which expected. According to investigation, pressure and laboratory tests were revealed that P&A is mandatory for this well as soon as possible.

Diesel is a fuel commonly used in Antarctica to supply vessels and domestic applications on site. The increasing human activities in the continent consequently have generated high fuel demand, which in turn has increased the occurrence of oil pollution due to accidental events during refueling. A related study received growing interest as more detrimental effects have been reported on Antarctic ecosystems. By adopting the bibliometric analysis, the research on diesel pollution in Antarctica collected in the Scopus database was systematically analysed. An increment in annual publication growth from 1980 to 2019 was observed and two research clusters were illustrated with “hydrocarbons” as the core keyword. Several attempts have been conducted over the past decades to remove anthropogenic hydrocarbon from previous abandoned whaling sites as well as recent oil spill incidents. However, the remote and polar conditions of Antarctica constrained the installation and operation of clean-up infrastructure. This review also briefly encompasses the approaches from past to present on the management of fuel pollution in Antarctica and highlights the potential of phytoremediation as a new bioremediation prospect.

The Arquebus-1 well was drilled in 1991 on exploration permit WA-206-P located in the southern portion of the Browse Basin. The Browse Basin is one of the least explored offshore basins in Australia and although two major gas discoveries have been made, no significant oil accumulations have been found. The Arquebus-1 well tested Middle to Upper Jurassic sandstones in a large three-way dip closed structure along the main Jurassic basin margin fault system, which has subsequently been inverted by Tertiary wrench faulting. The well was plugged and abandoned despite the presence of numerous shows and pay indicated by wireline logs. Five formation tests were performed and despite a long 12-hour test, only mud filtrate was recovered, suggesting that significant fluid invasion had occurred. The pressure data indicate a good water gradient with a 51 m gross column of light oil and gas. This is supported by detailed analysis of fluid inclusions, capillary pressure analysis, wireline logs and sidewall cores. The total gross hydrocarbon column may be as great as 105 m. The extremely low clay content, the uniform pore throat size, the slow drilling rate and the overbalanced drill mud made the sandstones prone to the nearly complete flushing of formation fluids and associated formation damage. The presence of an inferred oil column in the Jurassic sandstones at Arquebus-1, indicates that oil has been generated in the Browse Basin and that three-way dip closed structures are potentially viable traps in the area.

AbstractThe Nelson Field is located in Blocks 22/11, 22/6a, 22/7 and 22/12a in the UK Central North Sea. Nelson is a simple dip closed structure and is one of a series of Palaeocene Forties Sandstone Member oil accumulations situated on the Forties-Montrose High. The first exploration well on the prospect, 22/11-1, was drilled by Gulf Oil in 1967. Although hydrocarbon shows were encountered in a heterolithic section of Forties Sandstone Member, the well failed to flow on test and was abandoned. 3D seismic data were first acquired in 1985 and led to the discovery of Nelson in 1988 when the 22/11-5 well was drilled by Enterprise Oil plc. Following appraisal drilling, Nelson was granted production consent and the field came on-stream in February 1994. The hydrocarbon type is a light 40° API crude with a GOR of 555 SCF/BBL and is believed to be sourced from the East Forties Basin. The Nelson Field is developed from a 36 slot minimum facilities platform. Currently there are 23 platform producers, four sub-sea producers and four platform water injectors. Oil export is via the Forties Pipeline System and gas export is via the Fulmar Gas System. Oil originally in place is estimated at 790 million barrels of oil (MMBBL). Up to end-1999, the field had produced 261 MMBBL. Since the field was described by Whyatt et al. (1992), a further 28 wells have been drilled resulting in the collection of a considerable amount of new geological and geophysical data. This now includes a total of 6500 ft of Palaeocene core and 4D seismic data. This has enabled a more detailed understanding of the structure and sequence stratigraphy of the Nelson Field. This paper illustrates the importance of seismic mapping, high resolution biostratigraphy and sedimentology in developing the Nelson Field model.

Collapsed tubing occurs when external pressure outside the casing is greater than the pressure inside. There are several circumstances which can lead to a collapse, including high pressure outside the casing during operations such as cement squeeze, pressure testing in the annulus, and when the mud level inside the casing drops due to a loss of circulation. The well location within the rock formation can also have an impact on the potential for collapsed tubing. Seismic activity can cause significant damage to the casing and tubing so careful well design and strict operating procedures are essential to reduce the risk. When the issue does occur, it can create a significantly restricted area in the wellbore and often results in failure to gain access below the collapsed area in a wellbore. This, in turn, can cause extensive nonproductive time (NPT) to remediate the issue. Planned drilling or intervention work is halted, and production may be deferred. In the most severe instances when the casing collapses the well is completely abandoned. While the industry continues to focus on enhancing hydrocarbon recovery from existing wells, these operations must remain economically viable. Therefore, preventing and resolving well integrity and access issues have never been more important. With advancements in expandable technology, it is now possible to reform the restriction in a tubular, enabling the inner diameter (ID) to be opened. This allows for either reinstatement of production back to surface or access to equipment below, permitting operators to resume operations with minimal NPT.Coretrax recently deployed its ReForm wellbore repair tool when an international oil company experienced collapsed tubing in a remote well off the coast of Papua New Guinea. The solution uses hydraulic pressure applied at surface to reform collapsed, oval, or restricted tubulars. Overcoming Traditional Limitations During drilling and production activity, tubing and casing are exposed to a range of axial loads and temperatures as the operator utilizes various methods to reach, and then extract, hydrocarbons from the well. In drilling activity, mud losses can often be encountered through thief zones which leads to a lower mud level. With the consistent pressure outside the casing, the collapse resistance can be affected, resulting in full collapse in the wellbore. Swaging is a conventional and widely used method of repairing collapsed tubing. The process involves a series of swages run downhole to gradually open the collapsed area. It can be done with specialized swage packers or with a hydraulic expandable swage. Both methods provide a bond to the existing casing once properly prepped. The technique can take a significant amount of time to open the area due to the number of different swages required. Each time a larger size is needed, the operator must use significant rig time to trip out of hole. While it can have successful outcomes for repairing damaged areas of well casing or screens for example, due to the weight required in the pipe to swage, this procedure is not suitable for shallow or lateral wells.

The Harriet Oilfield, discovered in November 1988, is situated within offshore permit WA-192-P in the Barrow Sub-basin. Following the Harriet 1 discovery well, detailed seismic surveys were recorded and a further ten wells were drilled on the structure between 1988 and 1985. Nine of the wells were completed as producers and one was plugged and abandoned as a dry hole.The oil accumulation occurs in a low relief, fault-dependent closure on the upthrown side of the Lowendal Fault. The trap is mainly structurally controlled but stratigraphic barriers are believed to be locally present, based on differing oil-water contacts in Harriet B-3 and Harriet A-5. These indicate the presence of three hydrocarbon pools separated by permeability barriers.The massive Flag Sandstone reservoir of Lower Cretaceous (Neocomian) age was deposited in a submarine fan environment, northward of the advancing Barrow Group delta. Reservoir quality is very good, with average core porosity of 22 per cent and permeabilities mainly in the range 800-2 000 md. However, a broad oil-water transition zone is developed above the oil-water contact. A residual oil zone is present below the oil-water contact in the northeastern area of the field, suggesting tilting of the structure after initial accumulation of the oil. The gross oil column in the main, Central Pool is 19-21 m with a gas cap up to 10 m thick. The 37° API crude is a relatively unaltered, high quality, paraffinic oil probably sourced from the Jurassic Dingo Claystone.The Harriet Field is the first commercial development of a Barrow Group hydrocarbon accumulation. Recoverable oil reserves are currently estimated at 21 million barrels. The field came on stream in January 1986 and by October 1986 oil production was averaging 10 000 barrels/day.

The Manatokan Field in east-central Alberta offers a unique opportunity to characterize paralic sandstone reservoirs in 3D using a dense network of well data (approximately [Formula: see text]). Within the [Formula: see text] study area, the 100-m thick Lower Cretaceous Grand Rapids Formation is dominantly composed of sediment deposited in two depositional environments: river-dominated deltas and marine-influenced fluvial rivers. Up to 33 individual fluvial bodies, occurring at five stratigraphic levels and eroding into deltaic parasequences, are identified in the oil-charged upper part of the formation. The width and thickness of fluvial bodies typically range from 50 to 9000 m and from 5 to 50 m, respectively. Examination of cores, wireline logs, and strategically located 3D seismic data indicates that fluvial bodies are dominantly filled by inclined heterolithic deposits emplaced as downflow translation point bars (PBs) separated by mud-filled abandoned channels. Although individual PBs are relatively small ([Formula: see text]), the dense subsurface data set provides the means to build facies maps that illustrate their internal architecture and the distribution of reservoir heterogeneities. Reservoir-quality sandstone occurs on the upstream portion of PBs and usually forms continuous beds along the base of fluvial bodies that extend underneath abandoned channel deposits. High reservoir connectivity along the base of these heterolithic fluvial bodies constitutes a major advantage for heavy oil reservoir production driven by gravity. Core evidences also indicate potential communication between fluvial bodies and surrounding deltaic sandstones or older underlying fluvial reservoirs, which may lead to unexpected results during field development. The Grand Rapids Formation provides a good subsurface analogue of complex marginal-marine clastic reservoirs, and its study may help to explain unanticipated production results in similar hydrocarbon areas.

Hydrocarbon exploration in Angola commenced in 1910 with its first oil recovered in 1955. The proven reserves in Angola are estimated to reach up to 13 billion barrels (2.1 billion m3). Most of the Angolan oil fields are mature or maturing and some are or may be abandoned due to unprofitable recovery limit beyond the conventional type of oil production. The oil recovery is mainly by primary and secondary recovery methods. Apart from the issue of maturity, there is increasing energy demand due to population growth and difficulties in discovering and developing new fields as alternatives to the current oil fields. For incremental and sustained production rate of these fields and in addition to instability of oil prices and concerns about future oil supply, Angola has started to work towards developing affordable and efficient technologies capable of recovering residual oil in reservoirs as well as extend the life of many current fields which can be achieved through the implementation of enhanced oil recovery (EOR). Therefore, this paper discusses the EOR planning strategy from project selection, project implementation and optimization, and field abandonment. It further highlights the mutual benefits that may be derived from a cross-collaboration between the government and other stakeholders in Angola.

Hydrocarbon exploration in Angola commenced in 1910 with its first oil recovered in 1955. The proven reserves in Angola are estimated to reach up to 13 billion barrels (2.1 billion m3). Most of the Angolan oil fields are mature or maturing and some are or may be abandoned due to unprofitable recovery limit beyond the conventional type of oil production. The oil recovery is mainly by primary and secondary recovery methods. Apart from the issue of maturity, there is increasing energy demand due to population growth and difficulties in discovering and developing new fields as alternatives to the current oil fields. For incremental and sustained production rate of these fields and in addition to instability of oil prices and concerns about future oil supply, Angola has started to work towards developing affordable and efficient technologies capable of recovering residual oil in reservoirs as well as extend the life of many current fields which can be achieved through the implementation of enhanced oil recovery (EOR). Therefore, this paper discusses the EOR planning strategy from project selection, project implementation and optimization, and field abandonment. It further highlights the mutual benefits that may be derived from a cross-collaboration between the government and other stakeholders in Angola.

The study area is the Thriassion Plain, an important area, in antiquity, surrounding the famous ancient town of Eleusis, 20 km west of Athens. The modern town and port and the entire area were heavily industrialized (1965–1995) coupled with unregulated urban and agricultural development. The presence of two crude oil refineries and other oil-related industries have strongly impacted the entire environment, including soils, waters and sediments of the broader area. The purpose of this work is to better understand how a multi-layered groundwater system affects the potential underground spread of certain fuel volatile compounds, namely the BTEX (benzene, toluene, ethylbenzene and total xylenes) as well as their attenuation after their direct or indirect release into the aquifer system. The spatial distribution of BTEX in groundwaters show that they were concentrated mainly in four rather restricted locations. Three of them were spotted, as expected, in the close vicinity of known pollution sources (a military airfield and two crude oil refineries). The other one corresponds to an abandoned site with no outstanding pollution sources where wells exist, eventually used for illegal dumping of oily wastes. It is important that the concentrations decrease significantly from autumn to spring. This decline could be characterized as natural attenuation, related to natural dilution phenomena and a flushing out of pollutants discharging through underwater springs to the sea during the rainy period (October to April). This, in turn, could be associated to the specific geological conditions affecting the hydrology, such as the unconsolidated non-permeable deposits and the multi layered formations of the area’s aquifers.

The Gwydion-1 oil and gas discovery well is located in exploration permit WA-239-P on the sparsely explored Yampi Shelf area of the Browse Basin. The Gwydion feature was first recognised as a series of stacked seismic amplitude anomalies, which were interpreted to represent hydrocarbon-bearing Barremian to Albian age shallow marine sandstones draped over a prominent basement high. Amplitude versus offset analysis and modelling supported this interpretation.Gwydion-1 was spudded on 4th June, 1995, and discovered three gas bearing zones and one oil and gas bearing zone. The lowermost zone is Barremian to Hauterivian in age and consists of 12.6 m of net gas-filled glauconitic sand overlying a 9.5 m net oil-filled quartz sand. The three overlying hydrocarbon zones consist of glauconitic reservoirs of Barremian to Albian age.The play fairway for Gwydion-style traps has been named as the Echuca/Swan-Bathurst Island Group/Shelfal Play Fairway. It comprises mature Swan Group and Echuca Shoals Formation source rocks, and Bathurst Island Group reservoirs and seals. The limits of the play fairway on the shelf are controlled by the existence of topographic relief in the underlying basement metasediments. Migration pathway analysis suggests that the eastern margin of the Browse Basin is favourably situated to receive charge from the mature source rocks within the basin.The dominant northwesterly dip of the strata on the Yampi Shelf limits the potential for structural traps. Accordingly, a thorough understanding of the sequence stratigraphic architecture of the succession is necessary in order to generate the stratigraphic play concepts which hold the bulk of the prospectivity in the area.Gwydion-1 was plugged and abandoned as an uneconomic oil and gas discovery. It was, however, significant as it validated a new play type and generated renewed interest in the eastern margin of the Browse Basin for the first time since the mid 1970s; an area previously thought to be too shallow, too far from mature source and lacking reliable seal.

Since 1995 the Tarbat-Ipundu Field has developed from a marginal 200 BOPD (31.8 kL/d) field with perceived limited growth potential to a developing resource with production up to 3,000 BOPD (476.9 kL/d). This increase was achieved through the efforts of a dedicated multidisciplinary team and an aggressive 'fit for purpose' drilling and evaluation program.The Tarbat-Ipundu Field is located in PL 52 of ATP 299P in southwestern Queensland, approximately 115 km to the northeast of the Jackson Oil Field. The field was discovered by Hartogen Energy Ltd in 1986 with the drilling of Ipundu 1 which came on-line at 100 BOPD (15.9 kL/d) from the Wyandra Sandstone and the Murta Member. The discovery well was followed by the drilling of Tarbat-1 in 1988 on a subculmination to the north. Tarbat-1 encountered oil in the Wyandra Sandstone but watered out after producing 17 KSTB (2,702 kL) of oil. During 1991 a further four wells were drilled in the Ipundu Field by the then operator, Ampolex Pty Ltd. Two of these wells were plugged and abandoned. In January 1994 the field was producing at 220 BOPD (34.9 kL/d) after a total production of 350 KSTB.The Santos Group acquired a majority interest and Operatorship of the Tarbat-Ipundu Field in 1994. An integrated geological and engineering evaluation of Tarbat-1, incorporating experience gained in other parts of the Eromanga Basin, indicated the potential for bypassed oil in the Hutton Sandstone. Similarly, additional potential was recognised in the Wyandra Sandstone and Murta Member in the Tarbat-Ipundu wells. To evaluate this potential Tarbat-2 was drilled in August 1995 at a location 315 m to the northwest of Tarbat-1. Drill stem tests in Tarbat-2 resulted in flows of 2,037 BOPD (323.8 kL/d) from a 26 m gross hydrocarbon column in the Hutton Sandstone and 770 BOPD (122.4 kL/d) from a 14 m gross hydrocarbon column in the Wyandra Sandstone.An aggressive appraisal and development program followed the drilling of Tarbat-2 which has resulted in the drilling of an additional 25 wells. Proved and Probable Oil in Place estimates have increased from 5.2 MMSTB (0.826 ML) in 1994 to 44.2 MMSTB (7.02 ML) in 1997. As at June 1997 the field produces oil from the WyandraSandstone, Murta Member and Hutton Sandstone of the Eromanga Basin. A combined oil offtake of up to 3,000 BOPD (476.9 kL/d) has been achieved from the field. Continued field development is planned for 1998.The successful 're-discovery' of the Tarbat-Ipundu Field illustrates the potential benefit of a systematic review and integration of all existing data via a multidisciplinary team. The increasing cost of new data acquisition makes it imperative that the existing data is thoroughly evaluated prior to the investment of further exploration capital. The Tarbat-Ipundu Field demonstrates the potential to add significant new reserves from focussed targeting and evaluation of potential bypassed hydrocarbon accumulations.

Abstract The possibilities of remote sensing techniques in the field of the Earth surface monitoring and protection specifically for the problems caused by petroleum contaminations, for the mapping of insufficiently plugged and abandoned old oil wells and for the analysis of onshore oil seeps are described. Explained is the methodology for analyzing and detection of potential hydrocarbon contaminations using the Earth observation in the area of interest in Slovakia (Korňa) and in Czech Republic (Nesyt), mainly building and calibrating the spectral library for oil seeps. The acquisition of the in-situ field data (ASD, Cropscan spectroradiometers) for this purpose, the successful building and verification of hydrocarbon spectral library, the application of hydrocarbon indexes and use of shift in red-edge part of electromagnetic spectra, the spectral analysis of input data are clarified in the paper. Described is approach which could innovate the routine methods for investigating the occurrence of hydrocarbons and can assist during the mapping and locating the potential oil seep sites. Important outcome is the successful establishment of a spectral library (database with calibration data) suitable for further application in data classification for identifying the occurrence of hydrocarbons.

This Article addresses the intersection of oil and gas law and environmental law on a topic that has profound significance for the nation’s oil industry and for the environment. In this regard, the Permian Basin is experiencing a renaissance that has fundamentally impacted oil production in the United States. Horizontal drilling and hydraulic fracturing now allow the industry to produce in the Permian Basin’s unconventional shale formations in ways that were unimaginable a decade ago. But, the hot shale plays within the Permian Basin exist above conventional fields that are littered with a century’s worth of abandoned wells. Fracturing new wells near improperly abandoned wells creates a risk of environmental pollution as the fracturing of the shale allows hydrocarbons to migrate within the formation, potentially to an improperly abandoned well. The American Petroleum Institute (API) recognizes the environmental pollution risks associated with hydraulically fracturing close to an abandoned well and has set forth a detailed report on the best practices that an operator could employ to mitigate this risk, but that proposal overly relies on operator discretion and judgment and lacks transparency to potentially affected parties. The Environmental Defense Fund has issued a model regulatory framework, but that report overly relies on operator actions and bright-line standards. A growing number of state agencies in oil producing states around the nation have issued regulations, but there is considerable divergence in the adopted standards. The academic work on this topic is sparse to non-existence. Thus, this Article fills an important void in the literature at an important moment. The goal of any regulatory regime should be to ensure sustainable energy development occurs in a manner that adequately addresses the environmental concerns posed by modern development activities. Because contamination and collateral consequences of pollution can have far-reaching impacts, the public has a vital public policy interest that the regulatory regimes that govern this development require the industry to utilize best practices. The Article proposes that the regulatory agency should use its expertise and operator supplied information to make a fact-based determination of the area of fracturing interest as part of the permitting process for any new well that will be hydraulically fractured. The regulatory agency then would utilize its existing data on well locations to determine what existing wells are sufficiently close to the new well that will be hydraulically fractured and then will set forth requirements for the operator to investigate that well. The regulatory agency can then set forth a remediation proposal for the operator to perform. The Article uses the State of Texas as a model for its suggestions. The framework set forth in this Article also affords operators with an opportunity to provide their solutions to any regulatory concerns, and also provides other affected parties an opportunity to participate in the well permit process. Thus, the proposed regulatory framework sets forth a transparent and objective regime that does not solely rely on the business judgment of operators. Moreover, by requiring this analysis to be done in a scientific manner and by providing an opportunity for notice to be given to affected parties, the proposal also provides an opportunity for potentially affected parties to take precautionary steps on their own wells. Currently, Texas does not have any explicit requirements with respect to investigation of close proximity abandoned wells in its well permitting process, and the failure to require an upfront investigation creates an unnecessary environmental risk that could be mitigated if addressed upfront.

Transocean Harsh-Environment Rig Scoops Contract Extension Equinor extended Transocean’s contract for use of the harsh-environment semisubmersible Transocean Spitsbergen. The additional nine wells plus two, one-well options extension is valued at $181 million and is expected to begin in October 2023. The work will keep the rig busy off Norway until April 2025. In the fall of next year, the rig is scheduled to start drilling a trio of production wells for the Haltenbanken Vest Unit, which is part of the Kristin South area in the Norwegian Sea. Transocean Spitsbergen has been working consistently for Equinor since 2019. Equinor Wildcat Comes Up Empty Equinor will plug and abandon its Cambozola exploration well in License PL1049 offshore Norway after failing to encounter commercial hydrocarbons. Exploration well 34/9-1S was targeting Lower Cretaceous turbidite sand lobes in the northern North Sea and had the potential to be a play opener, according to well partner Longboat Energy. The exploration will continue with the Oswig and Copernicus wells, both expected to spud this summer. The Cambozola well was drilled to a total vertical depth of 4393 m using Odjfell Drilling semisubmersible Deepsea Stavanger. Background gas readings were recorded throughout the overlying section, but the well failed to encounter effective reservoir. Equinor is analyzing the data collected to understand the observed bright seismic amplitude anomaly and any remaining Lower Cretaceous prospectivity in the area. Longboat had previously referred to Cambozola as a potential play opener and one of the largest gas prospects to be drilled in Norway in 2022. Gross unrisked mean prospective resources for the entire Cambozola prospect have been estimated at 159 million BOE. Western Gas’ Sasanof-1 Exploration Well Disappoints Western Gas failed to encounter hydrocarbons with its Sasanof-1 exploration well offshore Western Australia. The well was drilled to a total depth of 2390 m by semisubmersible Valaris MS-1, but no gas reservoirs were intersected. The well will be permanently plugged and abandoned. The Sasanof prospect was estimated to hold 7.2 Tcf gas and 176 million bbl of condensate. The prospect was seen as potential supply for the NW Shelf LNG project. Vaalco Adds Reserves at Etame off Gabon Vaalco Energy encountered multiple hydrocarbon-bearing sands with its South Tchibala 1HB-ST well drilled from the Avouma platform in the Etame field offshore Gabon. The well struck 18 m of hydrocarbons in the Dentale D1 sand, which is analogous to the Deep Dentale producing field in North Tchibala with similar porosity and permeability. Another 15 m of hydrocarbons was intersected in the Dentale D9. The well will be completed in the D1 sand and was scheduled to be online in June, while the D9 will be cased for future completion. The well also penetrated a thin section of Gamba sand which will not be economically feasible to complete. Current Etame production is fed through the recently extended FPSO Petroleo Nautipa. Success with the South Tchibala 1HB-ST potentially adds new future drilling locations in the Deep Dentale trend across the Etame block. Eni, TotalEnergies Begin Drilling Off Cyprus Partners Eni and TotalEnergies have begun drilling a natural gas wildcat dubbed Cronos-1 in Block 6 offshore Cyprus. The well, originally planned for 2020, was derailed by the COVID-19 pandemic. Vantage Drilling drillship Tungsten Explorer is on location and is conducting the drilling operations. In 2018, the partnership struck gas at the Calypso well in another part of Block 6. That well proved that the carbonate play present in Eni’s Zoar field off Egypt extended to the Cypress exclusive economic zone. Zoar was discovered in 2015 and is the biggest gas discovery to date in the Mediterranean Sea. Calypso-1 was drilled to a total depth of 3827 m and encountered an extended gas column in Miocene- and Cretaceous-aged sands. Eni operates Block 6 with a 50% participation interest. TotalEnergies holds the remaining 50% stake. ADNOC Makes Three Onshore Discoveries Abu Dhabi National Oil Company (ADNOC) has unveiled three new oil discoveries including one at Bu Hasa, Abu Dhabi’s biggest onshore field, with a crude oil production capacity of 650,000 B/D. The discovery in Bu Hasa includes 500 million bbl of oil from an exploration well in the field. The second oil find was in Abu Dhabi’s Onshore Block 3, operated by Occidental, and is estimated to be around 100 million bbl of oil in place. The onshore Al Dhafra Petroleum Concession yielded the third discovery—around 50 million bbl of light sweet Murban-quality crude. Ecopetrol, Oxy Prep Development Quartet Ecopetrol has an agreement in place to develop four deepwater blocks with a subsidiary of Occidental. The four blocks are located in deep waters some 150 km off Colombia’s northern Caribbean coast. Ecopetrol will take a 40% stake in the blocks while Occidental subsidiary Anadarko Colombia will hold the remaining 60% stake and will serve as the blocks’ operator. The deal remains subject to approval from Colombia’s Ministry of Mines and Energy. Equinor, ExxonMobil Plan Bacalhau Expansion off Brazil Equinor and partner ExxonMobil are considering adding a second drilling rig and a second floating production platform for the next phase of the Bacalhau development in the Santos basin, along with a 100-mile-long gas pipeline, according to Reuters. The companies want to boost future production from Bacalhau, Equinor’s largest project outside of Norway. A new appraisal well is planned in the north of the field next year “to better understand the reserves base for the Phase 2 development,” according to Equinor, and the partners are assessing awarding a contract for a second drilling rig. The partners sanctioned the $8-billion project a year ago. The field is situated across two licenses, BM-S-8 and Norte de Carcará. The resource is a high-quality carbonate reservoir containing light oil. The development will comprise 19 subsea wells tied back to an FPSO located at the field. The planned FPSO be one of the largest in Brazil with a production capacity of 220,000 B/D and 2 million bbl in storage capacity. The stabilized oil will be offloaded to shuttle tankers, and the gas from Phase 1 will be reinjected in the reservoir. First oil is expected in 2024. Equinor Transfers Krafla Operatorship to Aker BP Equinor and Aker BP have signed a memorandum of understanding (MoU) for transfer of the Krafla operatorship from Equinor to Aker BP, making Aker BP the operator of all discoveries in the NOAKA area: Krafla, Fulla, and North of Alvheim. Equinor and Aker BP are operators of one field development project each in the area and have agreed that one operator will be the best solution for further development. The MoU states that the owners of the relevant licenses will apply to the ministry for change of operator. A transfer of operatorship will be carried out when the investment decision has been approved by the license partners and the plan for development and operation has been submitted to the authorities. Equinor will still be a major license partner in the area and will retain its existing share of 50% in Krafla and 40% in the Fulla license. The companies will jointly submit the PDOs for NOA Fulla and Krafla as planned by the end of the year. Energean Strikes Gas at Athena off Israel UK-based Energean has discovered gas with its Athena probe in Block 12, 20 km from Tanin A in 1769 m of water. The probe was drilled in 51 days and encountered a gross hydrocarbon column of 156 m in the primary target. Preliminary analysis indicates that the Athena discovery contains recoverable gas volumes of 8 Bcm on a standalone basis. Energean will conduct analysis to refine the full resource potential (including volumes contained within thinner sands between the main reservoir units) and to confirm the liquids content of the discovery. The Athena well has been suspended as a future production well. Commercial hydrocarbons were not discovered in the deeper secondary target. Athena can be commercialized in the near term via tieback to the Energean Power FPSO, enhancing the profitability of the Karish-Tanin development. Alternatively, it could form part of a new development called the Olympus Area which consists of Block 12 and additional prospects on the Tanin lease. The discoveries and prospects in this area lie along the same geological trend; Athena was drilled on the same direct hydrocarbon indicator as Tanin. Energean is confident that the Athena discovery has de-risked the A, B, and C sands in the remaining prospects of the Olympus Area, estimated to be 50 Bcm of mean unrisked prospective resources. This estimate excludes the liquids component as well as any gas upside in the thinner sands between the main reservoir units. Drillship Stena IceMAX has moved to the Karish Main-04 appraisal well and will complete the Karish North development well.

Summary This paper describes an efficient numerical scheme for nonisothermal compositional flow coupled to chemistry. An iterative implicit-pressure/explicit-composition (IMPEC) method is applied to solve the flow problem using a volume-balance-convergence criterion. A backward-Euler mixed finite-element method (FEM) with lowest-order RT0 elements is applied to solve the pressure equation, and a component local mass-preserving explicit scheme is used to update concentrations. Chemical reactions are solved using explicit Runge-Kutta (RK) ordinary-differential-equation (ODE) integration schemes. A higher-order Godunov method and a backward-Euler mixed FEM are applied for thermal advection and conduction, respectively, in a time-split scheme. One of the major applications of the method is in the modeling of field-scale carbon dioxide (CO2) sequestration as an enhanced-oil-recovery (EOR) process or for containment in deep saline aquifers where chemical reactions and temperature variations may have an effect on the flow and transport of CO2. Leakage patterns when CO2 is injected near leaky abandoned wells, the displacement of methane from depleted gas reservoirs, and accurate modeling of geochemical reactions involving injected CO2 are other applications of interest. Results of a benchmark problem in multiphase flow with several hydrocarbon components in formations with highly heterogeneous permeability on very fine grids, as well as a large-scale parallel implementation of modeling CO2 sequestration, are presented to justify the practical use of the model. A parallel efficiency of approximately 80% was observed on up to 512 cores in the benchmark study. Results from a problem simulating injection of CO2 in deep aquifers including nonisothermal and chemical effects are also presented. The results indicate a good agreement of the solutions with published data, where available. Numerical modeling and simulation of CO2 sequestration plays a major role in future site selections and in designing storage facilities for effective CO2 containment. The main contribution of this paper lies in providing a parallel and efficient method of simulating challenging compositional flow problems, such as in the study of CO2 sequestration, as well as flow coupled to thermal and geochemical effects.

The onshore Baram Delta, located in NW Sarawak is the birthplace of petroleum production in Malaysia. The Miri oilfield was first discovered in 1910 and subsequently abandoned in 1972 with intermittent exploration activities in the late 1980’s to early 1990’s. To rejuvenate exploration interest and to identify remaining hydrocarbon potential of the study area, in 2009-2010 JX Nippon acquired gravity, then regional 2D seismic data, followed-by exploration well drilling from 2011-2014. This paper discusses the social-environmental impacts and concerns associated with these petroleum exploration activities, from acquisition of seismic where explosives and vibroseis were used as a source of propagating signals, to exploration drilling with petroleum chemicals such as water-based muds used to facilitate the drilling operations. Overall, the inquiry addresses operational challenges, security of explosive storage and concern for handling explosives in the field, the social-environmental impacts of seismic acquisition operations, as well as removal of drilling fluid chemicals and disposal of contaminated cuttings. Containment procedures and mitigation measures undertaken to alleviate these social-environmental impacts are discussed according to the guidelines and regulatory requirements provided by the Environmental Impact Assessment (EIA), in conjunction with PETRONAS Procedures and Guidelines for Upstream Activities (PPGUA) and the company’s Health, Safety and Environment (HSE) Management System. In the final analysis, significant environmental and social challenges were certainly encountered while planning and conducting petroleum exploration activities in the study area. These challenges include problems related to topographic variabilities, permitting issues, compensations for affected lands and cash crops; layout constraints, drilling operations, well control measures for blowout prevention, traffic controls, potential damage to infra-structures, explosive and equipment transportation. However, with proper planning, effective communication with the local authorities, and awareness sessions conducted for the affected parties and stakeholders; together with the support of the local communities the operations have not only managed to mitigate these social and environmental concerns, the exploration activities also provided economic benefits such as hotel accommodation, logistics and transportation demands for local businesses, and short-term employment opportunities for the local people. Ultimately, the operations successfully acquired nearly 900-line km of seismic across many villages, longhouses, and in the city areas, with four exploration wells were drilled in the exploration block. We are glad to report that both seismic and drilling operations were conducted successfully and safely with minimal interruptions to people and environment, without untoward incidents or spills. With the mitigation measures in place, there were no damages other than land access, which were remediated, where incurred.

Sonadrill Lands Contract for Drillship Seadrill confirmed a new contract has been secured by Sonadrill Holding, Seadrill’s 50:50 joint venture with an affiliate of Sonangol for the drillship West Gemini. Sonadrill has secured a 10‑well contract with options for up to eight additional wells in Angola for an unknown operator. Total contract value for the firm portion of the deal is expected to be around $161 million, with further revenue potential from a performance bonus. The rig is expected to begin the work in the fourth quarter of this year with a firm term of about 18 months, in direct continuation of the West Gemini’s existing contract. The West Gemini is the third drillship to be bareboat chartered into Sonadrill, along with two Sonangol‑owned units, the Sonangol Quenguela and Sonangol Libongos. Seadrill will manage and operate the units on behalf of Sonadrill. Together, the three units position the Seadrill joint venture as an active rig operator in Angola, furthering the goal of building an ultradeepwater franchise in the Golden Triangle and driving efficiencies from rig clustering in the region. Petrobras Receives TotalEnergies, Shell Payments for Atapu TotalEnergies and Shell have formalized payments to Petrobras for separate, minority stakes in the pre‑salt Atapu field in the Santos Basin. TotalEnergies paid $4.7 billion reais ($940 million) while Shell paid closer to $1.1 billion. The Atapu block was acquired by the consortium comprising Petrobras (52.5%), Shell (25%), and TotalEnergies (22.5%) in the Second Bidding Round for the Transfer of Rights auction held 17 December 2021. The payments are compensation for monies spent thus far by Petrobras, which was granted contractual rights to produce 550 million BOE from Atapu in 2010. The partners will now work together to produce additional volumes from the field. Production at Atapu started in June 2020 via the P-70 FPSO. The unit is in about 2000 m of water and has the capacity to produce 150,000 BOED. CNOOC Brings New Bohai Sea Discoveries On Stream CNOOC Limited has kicked off production from its Luda 5‑2 oil field North Phase I project and Kenli 6‑1 oil field 4‑1 Block development project. Luda 5‑2 is in the Liaodong Bay of Bohai Sea, with average water depth of about 32 m and utilizes a thermal recovery wellhead platform and production platform tied into the Suizhong 36‑1 oil field. A total of 28 development wells are planned, including 26 production wells and two water‑source wells. The project is expected to reach its peak production of 8,200 B/D of oil in 2024. Kenli 6‑1 is in the south of Bohai Sea, with average water depth of about 17 m. The resource is being developed by a wellhead platform in addition to fully utilizing the existing processing facilities of the Bozhong 34‑9 oil field. A total of 12 development wells are planned, including seven production wells and five water‑injection wells. The field is expected to reach its peak production of 4,000 B/D of oil later this year. CNOOC Limited is operator and sole owner of the Luda 5‑2 oil field North and the Kenli 6‑1 oil field 4‑1 Block. Stabroek Block Bounty Off Guyana Gets Bigger The partners in the prolific Stabroek Block have again increased the gross discovered recoverable resource estimate for the area offshore Guyana. The owners now believe they have discovered reserves of at least 11 billion BOE, up from the previous estimate of more than 10 billion BOE. The updated resource estimate includes three new discoveries on the block at Barreleye, Lukanani, and Patwa in addition to the Fangtooth and Lau Lau discoveries announced earlier this year. The Barreleye‑1 well encountered approximately 70 m of hydrocarbon‑bearing sandstone reservoirs of which 16 m is high‑quality oil‑bearing. The well was drilled in 1170 m of water and is located 32 km southeast of the Liza field. The Lukanani‑1 well encountered 35 m of hydrocarbon‑bearing sandstone reservoirs of which approximately 23 m is high‑quality oil‑ bearing. The well was drilled in water depth of 1240 m and is in the southeastern part of the block, approximately 3 km west of the Pluma discovery. The Patwa‑1 well encountered 33 m of hydrocarbon‑bearing sandstone reservoirs. The well was drilled in 1925 m of water and is located approximately 5 km northwest of the Cataback‑1 discovery. “These new discoveries further demonstrate the extraordinary resource density of the Stabroek Block and will underpin our queue of future development opportunities,” said John Hess, chief executive of Hess and a partner in Stabroek. The co‑venturers have sanctioned four developments to date on Stabroek with both Liza and Liza Phase 2 on stream. The third planned development at Payara is ahead of schedule and is now expected to come on line in late 2023; it will utilize the Prosperity FPSO with a production capacity of 220,000 BOPD. The fourth development, Yellowtail, is expected to come on line in 2025, utilizing the ONE GUYANA FPSO with a production capacity of 250,000 BOPD of oil. At least six FPSOs with a production capacity of more than 1 million gross BOPD are expected to be on line on the Stabroek Block in 2027, with the potential for up to ten FPSOs to develop gross discovered recoverable resources. The Stabroek Block is 6.6 million acres. ExxonMobil affiliate Esso Exploration and Production Guyana Limited is operator and holds 45% interest; Hess Guyana Exploration holds 30% interest; and CNOOC Petroleum Guyana Limited holds 25%. ConocoPhillips Gets Ekofisk License Extension Norway’s Ministry of Petroleum and Energy (MPE) has extended production licenses in the Greater Ekofisk Area from 2028 to 2048 with ConocoPhillips as operator. The company said the license extension provides long‑term operations and resource management aligned with the company’s long‑term perspective on the Norwegian continental shelf. Fields on the shelf are required to operate with a valid production license where the operator and licensees enter into an agreement with the authorities, including relevant field activities. The authorities may require commitments, leading to increased oil recovery. The existing production licenses 018, 018 B, and 275 in the Greater Ekofisk Area were set to expire on 31 December 2028; however, the MPE approved an extension through 2048. The new terms provide a potential for extending Ekofisk’s lifetime to nearly 80 years. The license partners are ConocoPhillips (operator, 35.11%), TotalEnergies EP Norge (39.896%), Vår Energi (12.388%), Equinor (7.604%), and Petoro (5%). BHP’s Wasabi Disappoints in US GOM Australian operator BHP encountered noncommercial hydrocarbons with its Wasabi‑2 well in the US Gulf of Mexico. BHP said the well in Green Canyon Block 124 was plugged and abandoned following the disappointing results. “This completes the Wasabi exploration program, with results under evaluation to determine next steps,” the company said. The well was targeting oil in an early Miocene reservoir. Transocean drillship Deepwater Invictus spudded the well in 764 m of water in November 2021. The previous Wasabi‑1 well had a mechanical problem and was plugged and abandoned 4 days earlier, prior to reaching its prospective targets. BHP operates Wasabi with a 75% interest. Lukoil Says Titonskaya Holds 150 Million BOE Russia’s Lukoil believes it has discovered around 150 million BOE following analysis of the two wells it drilled at the Titonskaya structure on the Caspian Sea shelf. Work is now underway to refine the seismic models of productive deposits and study deep samples of formation fluids. The results of the assessment will be submitted to the State Reserves Commission of the Russian Federation. The structure is in the central part of the Caspian Sea, not far from the Khazri field. Lukoil drilled the first well at the Titonskaya structure in 2020 and announced the new discovery in April 2021. According to that assessment, the probable geological resources of the Titonskaya are 130.4 million tons. In 2021, drilling of the second prospecting and appraisal well began to identify oil and gas deposits in the terrigenous‑carbonate deposits of the Jurassic‑ Cretaceous age. The well was drilled using the Neptune jackup drilling rig. The new find at Titonskaya will likely be tied into Khazri infrastructure. Petrobras’ Roncador IOR Project Comes On Line Petrobras has successfully started production from the first two wells of the improved oil recovery (IOR) project at the Roncador field in the Campos Basin offshore Brazil. The two wells are the first of a series of IOR wells to reach production. Startup is almost 5 months ahead of schedule and at half of the planned cost, according to partner Equinor. The wells will add a combined 20,000 BOED to Roncador, bringing daily production to around 150,000 bbl and reducing the carbon intensity (emissions per barrel produced) of the field. Through this first IOR project, the partnership will drill 18 wells that are expected to provide additional recoverable resources of 160 million bbl. Improvements in well design and the partners’ combined technological experience are the main drivers behind the 50% cost reduction across the first six wells, including the two in production. Roncador is Brazil’s fifth‑largest producing asset and has been in production since 1999. Petrobras operates the field and holds a 75% stake. In 2018, Equinor entered the project as a strategic partner with the remaining 25% interest. In addition to the planned 18 IOR wells, the partnership believes it can further improve recovery and aims to increase recoverable resources by a total of 1 billion BOE. The field has more than 10 billion BOE in place under a license lasting until 2052. The strategic alliance agreement also includes an energy‑efficiency and CO2‑emissions‑reduction program for Roncador. Gazania-1 To Spud Off South Africa Africa Energy will move ahead with its planned Gazania‑1 wildcat well offshore South Africa after securing partner Eco Atlantic’s $20 million in capital requirements for its portion of the probe. The well will be drilled in Block 2B. Island Drilling semisubmersible Island Innovator has been contracted for the work and is expected to mobilize from its current location in the North Sea for the 45‑day trip to South Africa. The Block 2B joint venture plans to spud the well by October with drilling expected to last 30 days, including a full set of logs if the well is successful. The block has significant contingent and prospective resources in relatively shallow water and contains the A‑J1 discovery that flowed light sweet crude oil to surface. Gazania‑1 will target two large prospects 7 km updip from A‑J1 in the same region as the recent Venus and Graff discoveries. Block 2B is located offshore South Africa in the Orange Basin where both TotalEnergies and Shell recently announced significant oil and gas discoveries offshore Namibia. The block covers 3062 km2 approximately 25 km off the west coast of South Africa near the border with Namibia in water depths ranging from 50 m to 200 m. The Southern Oil Exploration Corp. (Soekor) discovered and tested oil on Block 2B in 1988 with the A‑J1 borehole, which intersected thick reservoir sandstones between 2985 m and 3350 m. The well flowed 191 B/D of 36 °API oil from a 10‑m sandstone interval at around 3250 m. Africa Energy has a 27.5% interest in Block 2B offshore South Africa. The block is operated by a subsidiary of Eco Atlantic which holds a 50% interest. A subsidiary of Panoro Energy holds a 12.5% stake, and Crown Energy AB indirectly holds the remaining 10%. Brazil Grants New Exploration Blocks Brazil’s National Agency of Petroleum, Natural Gas, and Biofuels (ANP) has granted 59 exploratory blocks of oil and natural gas to 13 companies, including Shell, TotalEnergies, and 3R Petroleum. The awards were part of a permanent bid offer round held in Rio de Janiero in April. The auction totaled 422.4 million reais in signature bonuses with leases granted in six Brazilian states: Rio Grande do Norte, Alagoas, Bahia, Espírito Santo, Santa Catarina, and Paraná. The awards will result in investments of 406.3 million reais in the exploratory phase of the contracts. Shell Brazil (70%) was granted six blocks in the Santos Basin in a consortium with the Colombian Ecopetrol (30%). The blocks leases were SM‑1599, SM‑1601, SM‑1713, SM‑1817, SM‑1908, and SM‑1910. TotalEnergies won two areas in the same basin while Brazilian company 3R Petroleum received six areas in the Potiguar Basin. Petro‑Victory was also awarded 19 new blocks in Potiguar, increasing its holdings in Brazil to 38 blocks (37 in Potiguar). The new blocks are nearby Petro‑Victory infrastructure at the Andorinha, Alto Alegre, and Trapia oil fields. Eni Finds More Oil in Egypt’s Western Desert Eni struck new oil and gas reserves with a trio of discoveries in the Meleiha concessions of Egypt’s Western Desert. The finds have already been tied into existing infrastructure in the region and have added around 8,500 BOED to overall production from the area. The operator drilled the Nada E Deep 1X well, which encountered 60 m of net hydrocarbon pay in the Cretaceous‑Jurassic Alam El Bueib and Khatatba formations Meleiha SE Deep 1X well, which found 30 m of net hydrocarbon pay in the Cretaceous‑Jurassic sands of the Matruh Khatatba formations, and the Emry Deep 21 well, which encountered 35 m of net hydrocarbon pay in the massive cretaceous sandstones of Alam El Bueib. The results, added to the discoveries of 2021 for a total of eight exploration wells, give Eni a 75% success rate in the region. The company added that additional exploration activities in the concession are ongoing with “promising indications.” With these discoveries, Eni, through AGIBA, a joint venture between Eni and EGPC, continues to pursue its near‑field strategy in the mature basin of the Western Desert, aimed at maximizing production by containing development costs and minimizing time to market. Eni is planning a new high‑resolution 3D seismic survey in the Meleiha concession this year to investigate the gas potential of the area. Eni is currently the leading producer in Egypt with an equity production of around 360,000 BOED.

This study identified the Pleistocene depositional succession of the group (A) (marine, estuarine, and fluvial depositional systems) of the Melor and Inas fields in the central Malay Basin from the seafloor to approximately −507 ms (522 m). During the last few years, hydrocarbon exploration in Malay Basin has moved to focus on stratigraphic traps, specifically those that existed with channel sands. These traps motivate carrying out this research to image and locate these kinds of traps. It can be difficult to determine if closely spaced-out channels and channel belts exist within several seismic sequences in map-view with proper seismic sequence geomorphic elements and stratigraphic surfaces seismic cross lines, or probably reinforce the auto-cyclic aggregational stacking of the avulsing rivers precisely. This analysis overcomes this challenge by combining well-log with three-dimensional (3D) seismic data to resolve the deposition stratigraphic discontinuities’ considerable resolution. Three-dimensional (3D) seismic volume and high-resolution two-dimensional (2D) seismic sections with several wells were utilized. A high-resolution seismic sequence stratigraphy framework of three main seismic sequences (3rd order), four Parasequences sets (4th order), and seven Parasequences (5th order) have been established. The time slice images at consecutive two-way times display single meandering channels ranging in width from 170 to 900 m. Moreover, other geomorphological elements have been perfectly imaged, elements such as interfluves, incised valleys, chute cutoff, point bars, and extinction surfaces, providing proof of rapid growth and transformation of deposits. The high-resolution 2D sections with Cosine of Phase seismic attributes have facilitated identifying the reflection terminations against the stratigraphic amplitude. Several continuous and discontinuous channels, fluvial point bars, and marine sediments through the sequence stratigraphic framework have been addressed. The whole series reveals that almost all fluvial systems lay in the valleys at each depositional sequence’s bottom bars. The degradational stacking patterns are characterized by the fluvial channels with no evidence of fluvial aggradation. Moreover, the aggradation stage is restricted to marine sedimentation incursions. The 3D description of these deposits permits distinguishing seismic facies of the abandoned mud channel and the sand point bar deposits. The continuous meandering channel, which is filled by muddy deposits, may function as horizontal muddy barriers or baffles that might isolate the reservoir body into separate storage containers. The 3rd, 4th, and 5th orders of the seismic sequences were established for the studied succession. The essential geomorphological elements have been imaged utilizing several seismic attributes.

The article presents the results of magnetometric engineering work at the Semakovsky subsoil block within the water area of the Taz Bay of the Kara Sea. The purpose of the work was to determine the coordinates of the exact location of the wellheads of 6 abandoned wells and to examine the wellhead area for the presence of foreign magnetic objects. This paper examines the procedure for finding abandoned wells using marine magnetic surveys and shows their reflection in an abnormal magnetic field. The relevance of the work is related to ensuring the environmental safety of the water area and the requirements of the Safety Rules in the oil and gas industry. To meet the requirements, it is necessary to check the technical condition of the wellheads of abandoned wells for the presence of hydrocarbon omissions. A diving survey of the area in the wellhead zone did not reveal any hydrocarbon passes, however, it confirmed the presence of a number of man-made objects near the wellheads identified by magnetic surveys. When working at shallow depths, the original configuration of the magnetometer was proposed and used.

Queensland contains a number of carbonate-bearing basins which are under-explored for petroleum, but contain the elements of potentially economic petroleum systems. The oldest such basin is the Neoproterozoic to Ordovician Georgina Basin which straddles the Queensland-Northern Territory border and is traversed by the Ballera to Mount Isa gas pipeline.The basin developed across several major crustal blocks resulting in regional variations in deposition and deformation. Thick Neoproterozoic rocks of the Centralian Superbasin form the base of the sequence in apparently fault-bounded, extensional sub-basins. These rocks are generally tight and source rocks are unknown. The Cambrian to Ordovician rocks have the best petroleum potential with the most prospective part of the basin being the Toko Syncline. The Burke River Structural Belt is less prospective, but is worthy of further exploration. Basin fill consists of Cambrian and Early Ordovician rocks which are dominantly carbonates, with both limestones and dolostones present. In the Early to Middle Ordovician, the rocks became predominantly siliciclastic.The main phase of deformation affecting the Georgina Basin occurred in the Devonian as part of the Alice Springs Orogeny. The Toomba Fault, which forms the western boundary of the asymmetric Toko Syncline, is a thrust fault with up to 6.5 km of uplift. The angle of thrusting is between less than 40 degrees and up to 70 degrees. Rich, marine source rocks of Middle Cambrian age in the Toko Syncline are mature for oil except in the deepest part of the syncline where they are mature for dry gas. The deeper part of the Toko Syncline may be gas saturated.Potential hydrocarbon targets include large folds associated with fault rollovers, stratigraphic traps and faultbounded traps. Vugular, secondary porosity in dolostones offers the best chance for commercial reservoirs within the Ninmaroo and Kelly Creek formations and Thorntonia Limestone. There are also oolitic carbonates which may have good primary porosity, as well as interbedded sandstones in the carbonates with preserved porosity. Structurally controlled hydrothermal dolomite facies represent potential reservoirs. The dominantly siliciclastic Ordovician sequence is water flushed. Fracture porosity is another possibility (cf. the Palm Valley gas field in the Amadeus Basin). As the deeper part of the Toko Syncline appears to be gas saturated, there may be potential for basin-centred gas. Fine-grained carbonates and shales provide excellent seals. There has not been a valid structural test; although AOD Ethabuka–1 flowed 7,000 m3/d of dry gas, the well was abandoned short of the target depth.

Since the oil crises in the 1970s, geothermal resources have received much attention and researches aimed at its recognition have been conducted all around the globe. Nevertheless, the investment cost associated mainly with drilling works is a crucial limitation for the successful implementation of new geothermal projects. The radical solution affecting the cost effectiveness of any geothermal investments might be an adaptation of existing un-exploited boreholes of the oil and gas sector for geothermal purposes. Moreover, a few studies on heat and/or energy recovery from oil and gas provinces have indicated that a tremendous amount of geothermal energy co-exists with petroleum fields. Thereby, the article centres on global concepts related to the adaptation of boreholes after the exploitation of hydrocarbon deposits or negative exploratory wells in order to exploit geothermal energy resources. Selected concepts focused on possible electricity production and the space heating sector are discussed. Other potential technologies based on utilization of geothermal energy attained by borehole heat exchangers are also indicated.

Oil and gas well leakage is of public concern primarily due to the perceived risks of aquifer contamination and greenhouse gas (GHG) emissions. This study examined well leakage data from the British Columbia Oil and Gas Commission (BC OGC) to identify leakage pathways and initially quantify incident rates of leakage and GHG emissions from leaking wells. Three types of leakage are distinguished: “surface casing vent flow” (SCVF), “outside the surface casing leakage” (OSCL), and “cap leakage” (CL). In British Columbia (BC), the majority of reported incidents involve SCVF of gases, which does not pose a risk of aquifer contamination but does contribute to GHG emissions. Reported liquid leakage of brines and hydrocarbons is rarer. OSCL and CL of gas are more serious problems due to the risk of long-term leakage from abandoned wells; some were reported to be leaking gas several decades after they were permanently abandoned. According to the requirements of provincial regulation, 21,525 have been tested for leakage. In total, 2,329 wells in BC have had reported leakage during the lifetime of the well. This represents 10.8% of all wells in the assumed test population. However, it seems likely that wells drilled and/or abandoned before 2010 have unreported leakage. In BC, the total GHG emission from gas SCVF is estimated to reach about 75,000 t/y based on the existing inventory calculation; however, this number is likely higher due to underreporting.

The geological storage of CO2 is a critical technique for reducing emissions, which significantly contributes to the mitigation of the greenhouse effect. Currently, CO2 is often geologically stored in coal seams, hydrocarbon reservoirs, and saline aquifers in order to store CO2 and improve the oil and gas recovery simultaneously. Shale formations, as candidates for CO2 storage, are drawing more attention because of their rich volumes. CO2 storage through shale formations in the Sichuan Basin, China, has tremendous potential because of the readily available CO2 injection equipment, such as abandoned shale gas wells. Therefore, we review the potential of using these wells to store CO2 in this paper. Firstly, we review the status of the geological storage of CO2 and discuss the features and filed applications for the most studied storage techniques. Secondly, we investigate the formation properties, shale gas field development process, and characteristics of the abandoned wells in the Sichuan Basin. Additionally, after carefully studying the mechanism and theoretical storage capacity, we evaluate the potential of using these abandoned wells to store CO2. Lastly, recommendations are proposed based on the current technologies and government policies. We hope this paper may provide some insights into the development of geological CO2 storage using unconventional reservoirs.

ABSTRACT A video-monitored oil-seep capture tent and an intertidal seep tank were developed and deployed to quantify emissions in shallow (5-m) nearshore waters and at an intertidal location at Summerland Beach, California. At two sites, where bubbles appeared clear, gas to oil ratios were 105:1; at a site where bubbles were dark, gas to oil ratio was 8.4:1. Nearshore oil emissions were conservatively estimated at 0.8 L dy’1. The size distribution of oily bubbles sharply peaked at 1500 µm, and the gas to oil ratio varied between bubbles. Oil affected the bubble's buoyancy and hydrodynamics. Time series of seabed emissions showed oil was mostly released in pulses. Several mechanisms that may cause variability in oil emissions were proposed. Intertidal oil emission were estimated a 12 L dy−1. Also, beach surveys showed less than trace amounts of beached oil and no oiled fauna over a 19-month period.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202683, “Marrying the Static and Dynamic Worlds: Enhancing Saturation and Permeability Interpretation Using a Combination of Multifrequency Dielectric, Nuclear Magnetic Resonance, and Wireline Formation Testers,” by Hassan Mostafa, Ghassan Al-Jefri, SPE, and Tania Felix Menchaca, SPE, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Accurate water saturation evaluation and permeability profiling are crucial factors in determining volumetrics and productivity of multiple, stacked carbonate reservoirs offshore Abu Dhabi and derisking reservoir management. The case study presented in the complete paper illustrates how the integration of static measurements, such as dielectric dispersion and nuclear magnetic resonance (NMR) with dynamic measurements improves understanding of reservoir properties and supports more-accurate reservoir evaluation. Sampling and downhole fluid analysis (DFA) performed by wireline formation tester (WFT) identifies the fluid and rock properties in various flow units. Field Background and Challenges Optimal field development requires accurate estimations of water saturation and permeability. In this greenfield, the hydrocarbon is generally oil (medium to light) with very low asphaltene content. Overall, the reservoir quality is controlled by a combination of depositional environment, sequence stratigraphy, and diagenesis. Some reservoirs have good porosity, but reconciliation of log-based water saturation results with well-test results has been an issue. The objective in this case study was to drill a pilot hole for data gathering in a poorly characterized field location. Phase I included drilling a hole with a 55° deviation to cover all reservoirs for data gathering only, with the openhole reservoir section then being plugged and abandoned. Phase II of the plan was to sidetrack and complete the well as dual water-injector boreholes. In the reservoir section of the pilot borehole, a variety of logs was acquired for evaluation, including both logging-while-drilling and wireline measurements. While drilling, triple- combination data were acquired, consisting of gamma ray, resistivity, and nuclear logs (density neutron) along with resistivity images. The wireline-logging program was carried out in two stages to avoid differential sticking. In the first stage, the WFT was used to acquire 10 pressure points, seven points in the first reservoir and three points in the second. Two DFA stations were also recorded in Zone 1 to confirm whether the oil/water contact was deeper than expected. Logging was conducted using a high-tension wireline cable, which facilitates quicker accessibility to the openhole sections. In the second stage, multiple wireline runs were performed for the formation evaluation of the complete section, followed by the WFT pressure and fluid-sampling run on the drillpipe conveyance. Another critical challenge was to obtain accurate water saturations in the heterogeneous, minor, thin reservoirs, which are bounded by dense layers above and below and cause shoulder-bed effects. The third challenge in this well was to obtain an accurate, continuous, and representative permeability profile for the multiple reservoirs. WFT mini-drillstem test (DST) stations along with NMR logs were used to address this important requirement.

Coal is a readily combustible rock of carbon and hydrocarbons that is found all across the United States. Due to its combustive properties and relative abundance, burning coal has been and still is a substantial fraction of the US energy market. However, also due its combustive properties, coal veins and mines tend to, well, catch fire. Lewis and Clark reported seeing burning veins of coal in 1805 when they were exploring the Missouri River in what is now central North Dakota. Maybe you have heard of the still burning mine fire in Centralia, Pennsylvania where a strip mine has been burning since 1962 and could continue to burn for over 250 years. Abandoned coal mines that catch fire are serious health, safety, and environmental hazards that the US government has been trying to address for decades.

Summary This paper describes a reservoir simulation study of a mature field. The objective of the study was to decide whether to drill an additional well and, if so, to determine its optimum location. An original approach to history-matching the model and accounting for structural uncertainty was adopted and we come to the following conclusions:The structural map can be used as a history matching parameter,Maps with the same original oil in place (OOIP) can lead to quite different productions,The same production can be obtained from different maps having different OOIP,The choice of complementary development schemes must take the nonuniqueness of the history match into account in order to minimize risk,Demonstration of the use of experimental design techniques in accounting for and managing structural uncertainty. Introduction For a developed field, the matching of the production history of the existing wells in a dynamic simulation is done by varying the usual parameters such as aquifer thickness, pore volume, petrophysics, relative permeabilities, fluids, etc. but seldom by making changes to the structural map. The latter is determined during the course of the static study [calculation of original oil in place (OOIP)] of a field and is generally not altered thereafter except, possibly, very locally. In the context of additional development, once a match is obtained, the location of one or more extra wells is determined on the basis of the structural image chosen. But there are nearly always uncertainties outside of the zone calibrated at well locations, and there may affect flow and, consequently, matching and additional reserve estimates. In what follows, consideration of the structural uncertainty led us to generate several possibilities for the top reservoir map and to propose an original approach for managing the multiple cases both for production history matching of the field and for choosing the location of an additional development well. Presentation of the Field The field studied here is a mature field with data available from six wells, three of which are production wells (P1, P2, and P6), the others being abandoned exploration or appraisal wells (Fig. 1) (one of these wells is used for produced water disposal). It has a production history of 11 years and current water cuts of 70%-90%. The hydrocarbon produced is dead oil (no gas) and the extremely thick aquifer provides excellent pressure maintenance (depletion virtually zero). At this stage of the well life, little further information about the reservoir can be expected from future production. The objective of the dynamic simulation of the field was to decide whether or not an additional well should be drilled to the south of the field in an apparently nondrained zone for which a three-dimensional (3D) seismic survey had shown a structural high. The uncertainty on the size of this local structural high was identified during the course of the study as being a major one. The dynamic study undertaken prior to the present work was a conventional one, performed using a structural map considered by the geophysicist as the most probable as a starting point. But satisfactory production history matching was impossible without impairing the consistency of the geological model. Structural Uncertainties After the seismic survey on the field had been interpreted, a study of the uncertainties on the structural map was decided on, in order to:determine statistically the rock volume and measure the impact of the structural uncertainties on dynamics, andmeasure the uncertainty on the structural high to the south of well P-1 so as to quantify the gains to be obtained from a new well. Geological and Geophysical Context. The field is located in a foot-hills basin. The reservoir has an overall almond shape running North-South, limited on its western flank by an extensive, normal fault (Fig. 1). The top reservoir is scarcely visible on the seismic data, and matching proved far from easy owing to static correction problems. The nature of the seismic marker corresponding to the top reservoir ranges from a zero crossing phase to a trough, between the oil zone and the reservoir flanks, rendering picking in this intermediate zone difficult. The time-to-depth conversion was carried out using two intermediate horizons. For calculating interval velocities, seismic time versus well depth regression functions were used. In the three intervals, compaction laws (V=V0+KZ) were used. In each geological unit the V0 values measured in the wells were kriged to form a map while the K coefficient was assumed to be constant. Construction of Uncertainty Maps. Only the errors in picking and depth conversion were taken into account. It was decided that the uncertainties on the preprocessing and migration could be integrated into the uncertainties on depth conversion. The map of uncertainty on picking was determined on the basis of three criteria:the difference between several interpretations,the problems of well-seismic matches, andthe amplitude map of top reservoir. To compute the uncertainty value (2 s) at each point the picking uncertainty map was constructed "by hand" but it can be seen as the root mean square of the sum of the square of the three criteria, i.e., the difference between interpretations, the well seismic mismatch and the quality maps ("inverse" of amplitude). The uncertainty thus determined is generally below 10 m except in the polarity change zone where it may exceed 30 m. Geological and Geophysical Context. The field is located in a foot-hills basin. The reservoir has an overall almond shape running North-South, limited on its western flank by an extensive, normal fault (Fig. 1). The top reservoir is scarcely visible on the seismic data, and matching proved far from easy owing to static correction problems. The nature of the seismic marker corresponding to the top reservoir ranges from a zero crossing phase to a trough, between the oil zone and the reservoir flanks, rendering picking in this intermediate zone difficult. The time-to-depth conversion was carried out using two intermediate horizons. For calculating interval velocities, seismic time versus well depth regression functions were used. In the three intervals, compaction laws (V=V0+KZ) were used. In each geological unit the V0 values measured in the wells were kriged to form a map while the K coefficient was assumed to be constant. Construction of Uncertainty Maps. Only the errors in picking and depth conversion were taken into account. It was decided that the uncertainties on the preprocessing and migration could be integrated into the uncertainties on depth conversion. The map of uncertainty on picking was determined on the basis of three criteria:the difference between several interpretations,the problems of well-seismic matches, andthe amplitude map of top reservoir. To compute the uncertainty value (2 s) at each point the picking uncertainty map was constructed "by hand" but it can be seen as the root mean square of the sum of the square of the three criteria, i.e., the difference between interpretations, the well seismic mismatch and the quality maps ("inverse" of amplitude). The uncertainty thus determined is generally below 10 m except in the polarity change zone where it may exceed 30 m.

The recent decade’s rapid unconventional oil and gas development in the Eagle Ford of south-central Texas has caused increased hydrocarbon emissions, which we have previously analyzed using data from a Texas Commission on Environmental Quality air quality monitoring station located downwind of the shale area. Here, we expand our previous top-down emissions estimate and compare it to an estimated regional emissions maximum based on (i) individual facility permits for volatile organic compound (VOC) emissions, (ii) reported point source emissions of VOCs, (iii) traffic-related emissions, and (iv) upset emissions. This largely permit-based emissions estimate accounted, on average, for 86% of the median calculated emissions of C3-C6-hydrocarbons at the monitor. Since the measurement-based emissions encompass a smaller section of the shale than the calculated maximum permitted emissions, this strongly suggests that the actual emissions from oil and gas operations in this part of the Eagle Ford exceeded their permitted allowance. Possible explanations for the discrepancy include emissions from abandoned wells and high volumes of venting versus flaring. Using other recent observations, such as large fractions of unlit flares in the Permian shale basin, we suggest that the excessive venting of raw gas is a likely explanation. States such as Texas with significant oil gas production will need to require better accounting of emissions if they are to move towards a more sustainable energy economy.

Summary Gas production from the Frontier formation at 18,300-ft depth in the Frewen Deep #4 well, eastern Green River basin (Wyoming), was uneconomic despite the presence of three sets of numerous, partially open, vertical natural fractures. Production dropped from 360 Mcf/D to 140 Mcf/D during a 10-day production test, and the well was abandoned. Examination of the fractures in the core suggests several possible reasons for this poor production. One factor is the presence of mineralization in the fractures. Another more important factor is that the remnant porosity left in the fractures by partial mineralization is commonly plugged with an overmature hydrocarbon residue (pyrobitumen). Reorientation of the in-situ horizontal compressive stress to a trend normal to the main fractures, which now acts to close fracture apertures during reservoir drawdown, is also an important factor. Introduction The Frewen Deep #4 well is located in Sweetwater county, southwestern Wyoming (Section 13 of Township 19 North, Range 95 West). The target of the well was natural gas from sandstones of the Frontier formation (Fig. 1) at a depth of approximately 18,300 ft. The Frontier formation consists of Cretaceous-age sandstones and shales. The main reservoir sandstone is about 40-ft thick at this location, with thick over- and underlying shales. Amoco Production Co. formed the Frewen Deep Unit in 1988. Its purpose was to evaluate the hydrocarbon potential of the Cretaceous sedimentary section in a 16 sq miles area on the south flank of the Wamsutter Arch. This arch trends WNW-ESE and divides the eastern Green River basin into two subbasins, the Great Divide basin to the north and the Washakie basin to the south (Fig. 2A). The Cretaceous sedimentary section is commonly productive in stratigraphic traps along the crestal portion of the Wamsutter Arch, as in the Echo Springs-Standard Draw and Wamsutter fields. The Frewen Deep Unit was formed to explore for deeper production in the Lakota formation. The initial unit well, the Frewen Deep #1, was drilled to a total depth of 19,299 ft on a southward-plunging, fault-related anticline. It was completed in the Lakota formation, but extended production tests from this zone indicated noncommercial rates. Shows had been observed while drilling through the Frontier formation to the deeper horizon, and this zone was targeted for testing. Unfortunately, the wellbore became mechanically unusable during the course of moving uphole to test the Frontier. Mechanical problems associated with the great depth, problems with the completion fluids, as well as problems with the casing integrity in this well were grounds for the decision to evaluate the formation in a completely new well. The Frewen Deep #4 well was drilled as a replacement, offset 600 ft from the #1 well (Fig. 2B). Much of the Frontier formation in the #4 well was cored with good recovery (86 ft), even though the core contains numerous partially mineralized vertical natural fractures. The fractures have obvious open porosity at depth (Fig. 3), with bridgings of mineralization holding open apertures locally up to 5 mm wide. Four fracture sets, based on character and strike, were differentiated in the core. These included three sets of irregular but numerous natural fractures, designated F1, F2, and F3 in order of their formation (based on observed cross-cutting relationships). The 86 ft of core had been slabbed and extensively sampled before our study, and the fractures themselves are commonly multistranded. Both of these factors make exact fracture counts difficult to obtain. Pervasive fracturing of the core suggests that the reservoir must be highly fractured, although the actual data set consists of approximately 10 F1 fractures, eight F2 fractures, and two F3 fractures. Fracture heights along the vertical axis of the core range from a maximum of about 4 ft for the F1 fractures down to several inches for F3 fractures. A fourth set of fractures consists of 30 regularly spaced, coring-induced1 petal fractures striking parallel to each other and to the F3 fractures. Gas in the drilling mud and the presence of open fractures seemed to promise significant gas production, but the initial production rate was not high and declined precipitously to an uneconomic level. We analyzed the natural and coring-induced fractures in the Frewen core during this study to assess the possible reasons for the low and declining production despite the presence of significant natural fracturing in the reservoir. This paper documents the conclusions from the core study and also offers an interpretation for the origin of these unusual fractures. Well History and Reservoir Properties. The Frewen Deep #4 well was spudded on 18 October 1990 and reached a total depth of 18,600 ft on 3 March 1991. Three separate conventional cores (totaling 86 ft recovered) were taken through the Frontier formation. Horizontal Dean Stark air permeabilities were measured at each foot in the sandstone core; 61 measurements yielded an average permeability of 0.007 md (range 0 to 1.23 md), an average porosity of 3.7% (range 0.8 to 7.1%), and a flow capacity of 1.7 md-ft. Geophysical logs were collected over the objective interval, including induction and neutron/density suites. Mud weight at total depth was in excess of 15 ppg, indicating a pressure of approximately 14,489 psi (minimum) at the reservoir level. Shows of gas requiring the use of a gas buster to de-gas the mud began at 18,225 ft and continued during coring operations. Shows periodically supported 10- to 20-ft (estimated) flares. Below 18,380 ft, the mud did not require de-gassing to remain manageable and control the well. Multiple sets of casing were set in anticipation of high pressures: we set 13 3/8-in. surface casing at 2,358 ft, 9 5/8-in. intermediate casing at 10,835 ft, and 51/2-in. casing at 18,114 ft before initiating coring operations. A 5-in. liner set from 18,114 to 18,593 ft completed the casing of the well. Each of the casing and liner strings was cemented in place and an acceptable bond was achieved. Completion operations began on 23 April 1991 when the well was perforated from 18,316 to 18,344 ft with 6 shots per foot, 6,000 psi underbalanced. The well did not flow. Swabbing was required to achieve a 15 to 20 Mcf/D flow rate for 7 days. Subsequently, we performed a CO2 breakdown, with 110 tons CO2 pumped at 8.5 bbl/min into 14,400 psi tubing pressure. The well flowed back CO2 and gas at a rate of 500 Mcf/D (>25% CO2) and was shut in preparatory to flow testing and bottomhole pressure buildup.

ABSTRACT Oil spills in the Niger Delta region of Nigeria has occurred frequently since oil extraction started in the 1950's. The oil spills originates from facilities and pipelines, leaks from ageing and abandoned infrastructure and from spills during transport and artisanal refining of stolen oil under primitive conditions. It is estimated that spills in Nigeria amount to 100 000 to 200 000 tons per year and have been doing so for almost 60 years. While a number of reports have been written about the Niger Delta and the civil unrest in this area during the last decades, very few scientific reports with actual data regarding the extent of the contamination has been published. This paper describes the contamination of sediments and water in a part of the Niger Delta, which has been particularly hard to assess for decades: Ogoniland. It does not discuss the origin of the oil spills. During 2010, the United Nations Environment Programme (UNEP) conducted an extensive environmental assessment of Ogoniland. The assessment was conducted at the request of the Nigerian government. During the assessment, drinking water samples were taken in wells and sediment and surface water samples were collected from streams, ponds and wetlands in and around Ogoniland from April to November. The levels found in the more contaminated sites are high enough to cause severe impacts on the ecosystem and human health. Extractable Petroleum Hydrocarbons (EPHs) reached levels of up to 7420 μg/l in surface water and drinking water wells show up to 42 200 μg/l. Benzene levels were measured up to 9000 μg/l, which is more than 900 times the WHO guidelines. EPH concentrations in sediments were up to 17 900 mg/kg. Polycyclic Aromatic Hydrocarbon (PAH) concentrations in sediments reached 8.0 mg/kg in the most contaminated sites. The impacts of this pollution were obvious to be seen, with large slicks of crude oil visible in the water and large areas of mangroves suffocated by oil. However, most sites did not show extremely high levels of EPH and PAH concentrations. Although the natural conditions for degradation of petroleum hydrocarbons are favorable with high temperatures and relatively high rainfall, the recovery of contaminated areas is prevented due to the chronic character of the contamination.

Recent advances in autonomous unmanned aerial vehicle (UAV) technology, along with successful efforts to miniaturize total field magnetometers, offer a unique opportunity to test low-cost UAV-mounted systems for wide-area high-resolution magnetic surveys. Modern UAV platforms capable of flying at low altitudes and collecting dense aerial surveys, coupled with sensitive and compact instruments, allow identification of anthropogenic targets previously identifiable only in ground magnetometer surveys. We present results of a proof-of-concept study focused on developing and field testing a UAV-based magnetometer system to detect and identify abandoned and unmarked oil and gas wells in an area of historical hydrocarbon exploration and development in New York state. Our results indicate that magnetic anomalies associated with metal casing of vertical wells are pronounced considerably above background levels both at the surface and up to 50 m above-ground elevation. We determine that a detection altitude of 40 m is optimal to avoid any canopy interference while recording magnetic data at the highest signal-to-noise ratio. This methodology makes rapid detection and identification of unmarked wells possible and, in turn, allows for future sustainable development of these areas.

Alkenes commonly found in synthetic drilling-fluids were used to identify sources of oil sheens that were first observed in September 2012 close to the Deepwater Horizon (DWH) disaster site more than two years after the Macondo MC-252 well was sealed. Exploration of the sea floor by BP confirmed that the well was capped and sound. BP scientists and engineers identified the likely source as leakage from an 80-ton cofferdam abandoned during a failed attempt to control the Macondo well in May 2010. We acquired and analyzed sheen samples at the sea-surface above the Deepwater Horizon wreckage as well as oil collected directly from the cofferdam using comprehensive two-dimensional gas chromatography (GC×GC). This allowed the identification of drilling-fluid C16- to C18-alkenes in sheen samples that were absent in cofferdam oil. Furthermore, the spatial pattern of evaporative losses of sheen oil alkanes indicated that oil surfaced closer to the Deepwater Horizon wreckage than the abandoned cofferdam site. Lastly, ratios of alkenes and petroleum hydrocarbons pointed to a common source of oil found in both sheen samples and recovered from oil-coated Deepwater Horizon riser pipe buoyancy compensator module debris collected shortly after the explosion. These lines of evidence suggest that the observed sheens do not originate from the Macondo well, cofferdam, or from natural seeps. Rather, the likely source is oil trapped in tanks and pits on the Deepwater Horizon wreckage, representing a finite oil leakage volume.

The proposed paper is a continuation and further development of the geological school of «Glavtiumengeologii » which is using today’s new bases of molecular geology of oil and gas, including regional researches, the influence of cosmic events, search and evaluation of resources, drilling of leading production wells and processing of hydrocarbon raw materials. The main aim of this is not just transfer of accumulated knowledges. Moreover, one of the aims is upbringing of ideology unconventional innovative technologies search via use of the fundamental laws of quantum physics and chemistry for description of discrete geological processes. Their testing on the scientific and industrial landfills in the drilled, idle, mothballed and abandoned wells will involves education of top managers, managers, engineers and other specialists for the development of nontraditional methods of work in the oil and gas production.

ABSTRACT A recent surface fuel spill incident by tank overflow at a 220,000 gal above-ground airport tank farm led to a single monitoring well installed at the request of the state. This well disclosed previously spilled Jet A fuel at the water table, 5 ft below grade. Eight monitoring wells averaging 7 ft deep were completed in 3 days, revealing a surprisingly confined pool of fuel in fine sand estimated at 24,000 ft2 but with over 30 in. of fuel in some wells. Monitoring wells 40 ft away showed a complete absence of fuel. Leaking from underground piping was tested and eliminated as a possible source. Above-ground spills, it was concluded, were insufficient as a source. Inventory records failed to show any losses. Gas chromatic analysis of the product confirmed that it was Jet A, and therefore not JP-4 from an abandoned Air Force fuel main. The source of fuel was concluded as primarily from the practice of daily fuel tank sumping to the ground, which ceased in 1974. Significantly, the spill was 10 years old and had not moved. Initial recovery was by slotted drum, later replaced by a 70 ft by 3 ft trench to the water table, gravel backfilled. Recovery of product only, without water pumping, was by an electrical chemical metering pump, continuously, at the rate of product flow to the trench, averaging 23 gal per day. Investigations of groundwater quality in nearby monitoring wells by the state agency failed to show any hydrocarbons, analyzed down to 5 parts per billion. The closest water well, 1,800 ft away, showed no contamination. Bench scale testing demonstrated that monitoring well fuel thickness overstates fuel thickness in the ground, and that trenches concentrate fuel thicknesses like monitoring wells. Tight cost control was maintained, with monitoring wells costing under $50 each, a recovery trench under $2,000, and recovery pumping under $1,000. By-product recovery revenue has offset some recovery costs.

The effective production of hydrocarbons from the Birkhead Formation, Eromanga Basin, relies heavily on understanding the complex distribution of reservoir and seal rocks deposited in a fluvial environment. To visualise this complexity, sequence stratigraphic concepts applied to non-marine basins were combined with 3D seismic data visualisation in a study of the Birkhead interval over the Merrimelia, Meranji and Pelican fields.Fluvial channel, crevasse splay channel, floodplaincrevasse splay complex and floodplain facies were recognised from the well log motifs in the Birkhead Formation. The interval is interpreted as an alluvial transgressive systems tract bounded by flooding surfaces consisting of shaly or coaly intervals. Lateral discontinuity of the fluvial system can be demonstrated between these surfaces. Seismic amplitude distributions in the 3D seismic data in the upper part of this transgressive systems tract illustrate well developed meandering fluvial channels. Combining the spatial distributions of sedimentary facies from the well logs and the seismic amplitudes results in the interpretation of a fluvial meandering channel belt that includes point bars and abandoned channels.The point bar sandstones in the channel belt should make good reservoirs and the juxtaposition of the point bar and abandoned channel facies can result in a stratigraphic trap component to the reservoir rocks within the channel belt. Although the point bars are known to be wet in the study area, it is still useful to consider their capacity as oil reservoirs, since they may serve as analogues for similar untested point bars elsewhere. Multiple realisations of the distribution of sandstone thickness of the point bars were generated by conditional simulation, using seismic amplitudes to control extrapolation of the well data. This gave a potential reserves distribution with a mean value of 18.8 million bbl in place. The complexity of the fluvial channel systems in the Birkhead Formation described in this paper should aid understanding of the reservoir and seal distribution and help optimise production from this interval in other fields.

To ensure success in exploration and production activities, oil and gas companies rely on subsurface data to gain insights that guide operational decisions over the life of their wells. But as wells near the end of their lives and production slows or stops, wells are subsequently shut and abandoned, and the accompanying subsurface data are set aside. However, these data still hold tremendous value when it comes to evaluating mature, near-end-of-life wells and fields to determine if they are suitable candidates for carbon capture, utilization, and storage (CCUS). Reusing wells and fields for CO2 injection provides an opportunity to reduce the time and cost for developing new CCUS infrastructure required by energy mix diversification efforts while avoiding the steep expenses commonly associated with decommissioning. In most cases, when the production cycle ends and all usable hydrocarbons have been extracted, the topside facilities are dismantled, the wellbore is permanently plugged and abandoned, and the surrounding land or seabed is returned to its natural condition. Historically, this complex, multistep process has been a cost center for oil and gas businesses, requiring monumental investment that grows even higher for offshore and deepwater fields. However, now that the CCUS industry is aggressively expanding, operators are presented with the possibility of turning decommissioned wells into a profit center by selling CO2 storage capacity to others. CO2 storage is a crucial component of the CCUS value chain as permanently storing CO2 is the cornerstone of large-scale emissions reductions. The storage process entails capturing, compressing, and injecting CO2 into a reservoir of porous rock beneath an impermeable layer of caprock, which functions as a seal. The caprock prevents the CO2 from reaching the surface, as do other trapping mechanisms including structural, residual, solubility, and mineral trapping. As a result, CO2 is safely stored in geological formations. This is similar to the unexplored state of oil and gas reserves trapped underground for millions of years. Carbon-storage processes are not a new concept in the oil and gas industry. As part of normal well operations, operators routinely perform the CO2 injection enhanced oil recovery (EOR) technique. If CO2 returns to the surface and is separated and then reinjected to form a closed loop when utilizing this EOR method, this results in permanent CO2 storage, which strongly supports the viability for repurposing mature decommissioned wells. In response to growing interest in CCUS and governments worldwide committing to reach a net-zero target for CO2 emissions in the coming decades, a consortium of 20 organizations including research institutions, operators, and regulatory authorities joined together to create REX-CO2 (ReUsing Existing Wells for CO2 Capture and Storage). As part of the REX-CO2 consortium, Ikon Science collaborated with the British Geological Survey (BGS) in the phases of a study that evaluated the potential for well reuse in the UK Continental Shelf (UKCS). It’s forecast that 1,211 wells across 230 fields will be decommissioned through 2028 in the UKCS to the tune of $60 billion, according to Britain’s Oil & Gas Authority’s 2021 Decommissioning Cost Estimate report.

Coal mining can generate organic and inorganic contaminants that can be disseminated in the surrounding soils by leaching and/or aerial deposition. This study aims to identify and characterize the physicochemical and geochemical changes promoted in soils from the surrounding area of a self-burning waste pile in an abandoned coal mine. A soil sampling campaign was conducted bordering the waste pile, comprising the main drainage areas as well as the areas uphill. The soils were characterized geochemically for major and trace elements and multivariate statistics was used in combination with geostatistical methodologies to study the statistical and spatial relations of the different elements and infer their Potentially Toxic Elements (PTEs) sources. The 16 priority Polycyclic Aromatic Hydrocarbons (PAHs) were identified and quantified in soils according to their spatial distribution, and their pyrogenic/petrogenic sources were inferred. Different sources were identified as contributing to the soil geochemical signature, considering not only the mine but also anthropogenic urban contamination or naturally enhanced regional geochemical background in multiple PTEs. PAHs tend to concentrate downstream of the waste pile, along the runoff areas, presenting a greater variety of the 16 priority PAHs and an increase of High Molecular Weight (HMW) PAHs pointing to its pyrogenic origin, possibly related to the self-combustion phenomenon occurring in the waste pile.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 205537, “Safeguarding CO2 Storage by Restoring Well Integrity Using Leakage Rate Modeling Along the Wellbore in Depleted Gas Fields Offshore Sarawak,” by Parimal Patil, SPE, Prasanna Chidambaram, SPE, and M. Syafeeq B. Ebining Amir, Petronas, et al. The paper has not been peer reviewed. Ensuring the long-term integrity of existing plugged and abandoned (P&A) and active wells that penetrated a studied CO2 storage reservoir was key to reduction of leakage risks along the well path for long-term containment sustainability. With a goal of developing depleted gas fields as carbon dioxide (CO2) storage sites in offshore Sarawak, determining the complexity involved in restoring the integrity of these P&A wells, as well as the development wells, is critical. Leakage-rate modeling (LRM) was performed to identify and evaluate the associated risks for designing the remedial action plan. CO2 Storage Challenges in Central Luconia Storage sites in this study include three major depleted gas reservoirs in the Central Luconia gas field offshore Sarawak. Hydrocarbons from deeply buried reservoirs were produced through drilling of vertical and deviated wells. Thirty-eight wells were drilled in these three depleted gas reservoirs, of which 11 are exploration wells that had been P&A; 27 wells include active producers, water injectors, and idle wells. By estimating the performance of well-barrier elements in the legacy P&A wells and existing development wells, an assessment of well integrity analysis was performed. The casing, as well as the cement, may degrade with time depending on the downhole temperature, pressure, stress conditions, and formation fluids. Degradation of wellbore cement in the presence of carbonized acid fluids poses a risk of creating leakage pathways. Understanding the local stress conditions acting on the cement/casing/formation sheath is important to increase knowledge regarding leakage-pathway creation, together with geochemical and geomechanics processes. CO2 Storage Well Integrity Risk Assessment Once the locations of the existing P&A wells were identified, site-inspection data helped define the preparation required to assess possible gas seepage or the existence of leakage pathways along these wellbores. The measured leakage amount of gas/CO2 could then be used to backfeed the simulation model to identify the leakage system along the wellbore. The method uses desktop modeling studies together with site surveys using a remotely operated vehicle (ROV) or side scan sonar. The modeling helps simulate various leakage scenarios, while actual field measurements for any bubbling at the seabed provide the critical inputs to refine the modeling work to define the risk associated with each well. To gauge the integrity of storage sites for each well, a comprehensive understanding of critical factors and dominant criteria had to be considered as part of the data-evaluation process. Tables 1 and 2 of the complete paper define the risk-assessment elements for the existing P&A exploration and appraisal wells and development wells, respectively, used for the risk-assessment exercise. The risk-assessment process includes identification of risk, risk analysis, and risk evaluation. All wells that penetrated the CO2 storage reservoir were benchmarked as a baseline for a corrosive storage environment. Such data are useful for forecasting the possible leakage rates at the CO2 sequestration site.

CNOOC Turns Taps on Bohai Bay Fields Volumes are flowing from two new CNOOC-operated field developments in the Bohai Sea, offshore China. Production began at the Luda 5-2 oil field north phase 1 project in Liaodong Bay. The field is in an average water depth of around 32 m. CNOOC installed one thermal recovery wellhead platform and one production platform, and connected processing facilities serving the Suizhong 36-1 oil field. The company plans to drill a total of 26 production and two water-source wells, with peak crude oil production of 8,200 B/D targeted for 2024. Oil also is flowing at the Kenli 6-1 oil field 4-1 block development in the southern Bohai Sea. A new wellhead platform in about 17 km of water is connected to processing facilities at the Bozhong 34-9 oil field. CNOOC plans a total of seven producer and five water-injector wells at Kenli 6-1, with peak oil production later this year of around 4,000 B/D. CNOOC holds a 100% stake in both projects. Sailaway for GTA FPSO Expected by Year-End A BP executive told conference goers in Senegal recently that the FPSO destined for that country’s Greater Tortue Ahmeyim (GTA) gas project is expected to leave China prior to year-end. BP Executive Vice President for Production and Operations Gordon Birrell added that the first phase of the GTA project is 80% complete. The main function of the FPSO will be to remove water and condensate and reduce impurities in the gas stream before exporting processed gas to a nearby FLNG facility and domestic gas offtake. BP and Kosmos Energy are leading the development of GTA and Yakaar-Teranga, Senegal’s first natural gas projects. GTA straddles the border between Senegal and Mauritania. Phase 1 of the planned development is expected to start delivering gas by the end of 2023. Birrell added that BP is in discussions with Senegal and Mauritania about GTA’s second phase and other projects in both countries, but did not get into specifics, according to Reuters. Phase two should double expected production from 2.5 to 5.0 mtpa. ReconAfrica, NAMCOR Reach Target Depth on Namibia Well Reconnaissance Energy Africa and its joint venture partner NAMCOR, the state oil company of Namibia, confirmed the third stratigraphic test well in the Kavango basin of northeast Namibia, 1819/8-2, reached target depth. The well was drilled to a total depth of 2056 m reaching all geological targets. However, the duo did not reveal what was found in the well. Instead, the pair said current operations were focused on well data capture and initiating analysis of the data. Company-owned rig Jarvie-1 will remain on site until logging and coring operations are completed. A vertical seismic profile tool will also be run to total depth to tie into the 2D seismic program. Processing of the second phase of 761 km of 2D seismic is near completion, where early results are being used to refine drilling locations for the upcoming stratigraphic wells. The next well of this planned continuous drilling program was scheduled to have the rig on location by the end of last month. Pantheon Resources Alaska Discovery Deemed “World Class” Pantheon Resources has uncovered a “world-class” oil discovery on its Theta West acreage in Alaska, according to independent consultants brought in to assess the area’s potential. Baker Hughes Advanced Hydrocarbon Stratigraphy (AHS) was charged with compiling a report based on data collated after a successful appraisal well drilled early this year. The firm believes there is a continuous column of oil-bearing cuttings of at least 1,360 ft that is host to a light crude in the order of 37–39 °API. The AHS report concluded there are “abundant good-quality reservoirs” with an “ultimate, nonpermeable seal” at 7,070 ft. Pantheon said the results are supportive of analyses of cuttings from previous work on the acreage on Alaska’s prolific North Slope. The company estimated the project, which is close to infrastructure, is host to 17 billion bbl of which 10%, or 1.7 billion bbl, is deemed recoverable. Invictus Well in Zimbabwe a “Game Changer” The Mukuyu-1 exploration well being drilled in Zimbabwe by Australian firm Invictus Energy in partnership with the government is being called “a game changer” for the country by President Emmerson Mnangagwa. The well is in license SG 4571, which covers 250,000 acres located in the most prospective portion of the Cabora Bassa Basin in northern Zimbabwe. The license is currently in the second exploration period which runs to June 2024. Invictus entered into an agreement with the Zimbabwe government in March 2022 to increase the license area sevenfold to 1.77 million acres. Previously explored by Mobil Oil, the project contains the largest undrilled structure in onshore Africa. The Muzarabani anticline feature has more than 200 km2 under closure and up to 1500 m vertical relief at favorable depths for conventional oil and gas. Invictus completed the acquisition of 840 km of high-resolution infill 2D seismic data ahead of spudding the well using Exalo Rig 202 in August. Drilling Results a Mixed Bag for APA Offshore Suriname APA Corporation has made an oil discovery offshore Suriname with its Baja-1 well in Block 53 but came away empty with a probe in Block 58. Baja-1 was drilled to a depth of 5290 m and encountered 34 m of net oil pay in a single interval within the Campanian. Preliminary fluid and log analysis indicates light oil with a gas/oil ratio (GOR) of 1,600 to 2,200 scf/bbl, in good-quality reservoir. The discovery at Baja-1 is a down-dip lobe of the same depositional system as the Krabdagu discovery, 11.5 km to the west in Block 58. Evaluation of openhole well logs, cores, and reservoir fluids is ongoing. The success at Baja marks the sixth oil discovery in which APA has participated in offshore Suriname and the first on Block 53. The company said the result confirms its geologic model for the Campanian in the area and helps to de-risk other prospects in the southern portion of both Blocks 53 and 58. APA recently received regulatory approval regarding an amendment to the Block 53 production-sharing contract, which provides options to extend the exploration period by up to 4 years. The company is currently proceeding with formalizing the first one-year extension, for which all work commitments are complete. APA is operator and holds a 45% working interest in Block 53; partners Petronas and CEPSA hold 30% and 25% stakes, respectively. Baja-1 was drilled using drillship Noble Gerry de Souza in water depths of approximately 1140 m. The rig will mobilize to Block 58 following the completion of current operations, where it will drill the Awari exploration prospect, approximately 27 km north of the Maka Central discovery. APA was not as fortunate with its Dikkop exploration well in Block 58. The well encountered water-bearing sandstones in the targeted interval and has been plugged and abandoned. Operator TotalEnergies holds a 50% working interest, while APA holds the remaining 50% stake. The drillship Maersk Valiant will be moving to the Sapakara field to drill a second appraisal well at Sapakara South, where the joint venture conducted a successful flow test late last year. Helix Energy Solutions Secures Production, P&A Work With Thunder Hawk Buy Helix Energy Solutions Group subsidiary Deepwater Abandonment Alternatives (DAA) acquired all of MP GOM’s 62.5% interest in Mississippi Canyon Block 734, comprising three wells and related subsea infrastructure, collectively known as the Thunder Hawk field. MP GOM is a subsidiary of Murphy Oil. Financial terms of the deal were not disclosed. “This acquisition furthers Helix’s energy transition business model by taking on decommissioning obligations in exchange for production revenues,” said Owen Kratz, president and chief executive of Helix. “We have long communicated our unique position as a qualified offshore field operator that can also assume and efficiently discharge decommissioning obligations. We continue to pursue opportunities that enable us to enhance and extend the life of existing reserves and safely perform the related decommissioning of the infrastructure in transactions that allow producers to remove noncore assets from their balance sheets.” Under the terms of the transaction, Helix receives the benefit of ownership of MP GOM’s interest, with a 1 November 2021 effective date purchase price adjustment resulting in nominal cash paid by MP GOM at closing, in exchange for the assumption of MP GOM’s abandonment obligations at the Thunder Hawk Field. In addition to anticipated future production revenue, DAA will operate the Thunder Hawk field with Helix eventually expected to perform the required plug and abandonment operations. Kolibri Continues Tishamingo Program in Oklahoma Kolibri Global Energy has completed the location work for the Glenn 16-3H and Brock 9-3H wells, which are the third and fourth wells in its 2022 drilling program. A fifth location is also being prepped. All three wells in the Tishamingo area of the SCOOP play are planned to be drilled back-to-back, and the completion operations for the Glenn 16-3H and Brock 9-3H wells have been tentatively scheduled for the first week of October. Neptune Energy Confirms New Discovery in the Gjøa Area Neptune Energy and its partners announced a new commercial discovery at the Ofelia exploration well (PL 929), close to the Gjøa field in the Norwegian sector of the North Sea. Neptune has completed drilling of the Ofelia well, 35/6-3 S, and encountered oil in the Agat formation. The preliminary estimate of recoverable volume is in the range of 16 to 39 million BOE. In addition to the Agat volumes, north of the well there is an upside of around 10 million BOE recoverable gas in the shallower Kyrre formation, which brings the total recoverable volume to approximately 26 to 49 million BOE. Located 15 km north of the operated Gjøa platform, at a water depth of 344 m, Ofelia will be considered for development as a tieback to Gjøa, in parallel with the company’s recent oil and gas discovery at Hamlet. The Ofelia well, drilled by Odfjell-operated semisubmersible Deepsea Yantai, confirmed an oil/water contact at 2639 m total vertical depth. It is the third discovery by Neptune Energy in the Agat formation, a reservoir which until recently was not part of established exploration models on the Norwegian Shelf. The first was at the Duva field, which is now onstream and being operated by Neptune. The second was the company’s discovery at Hamlet, with estimated recoverable volumes between 8 and 24 million BOE.