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Journal articles on the topic 'Mature oilfield'

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Published: 14 March 2023

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1

Prasetyo, Joko Nugroho, Noor Akhmad Setiawan, and Teguh Bharata Adji. "Forecasting Oil Production Flowrate Based on an Improved Backpropagation High-Order Neural Network with Empirical Mode Decomposition." Processes 10, no. 6 (June 6, 2022): 1137. http://dx.doi.org/10.3390/pr10061137.

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Developing a forecasting model for oilfield well production plays a significant role in managing mature oilfields as it can help to identify production loss earlier. It is very common that mature fields need more frequent production measurements to detect declining production. This study proposes a machine learning system based on a hybrid empirical mode decomposition backpropagation higher-order neural network (EMD-BP-HONN) for oilfields with less frequent measurement. With the individual well characteristic of stationary and non-stationary data, it creates a unique challenge. By utilizing historical well production measurement as a time series feature and then decomposing it using empirical mode decomposition, it generates a simpler pattern to be learned by the model. In this paper, various algorithms were deployed as a benchmark, and the proposed method was eventually completed to forecast well production. With proper feature engineering, it shows that the proposed method can be a potentially effective method to improve forecasting obtained by the traditional method.
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2

Malahov, Aleksei O., Emil R. Saifullin, Mikhail A. Varfolomeev, Sergey A. Nazarychev, Aidar Z. Mustafin, Chengdong Yuan, Igor P. Novikov, Dmitrii A. Zharkov, Rustam N. Sagirov, and Rail I. Kadyrov. "Screening of Surfactants for Flooding at High-Mineralization Conditions: Two Production Zones of Carbonate Reservoir." Energies 15, no. 2 (January 6, 2022): 411. http://dx.doi.org/10.3390/en15020411.

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The selection of effective surfactants potentially can mobilize oil up to 50% of residuals in mature carbonate oilfields. Surfactants’ screening for such oilfields usually is complicated by the high salinity of water, high lipophilicity of the rock surface, and the heterogeneous structure. A consideration of features of the oilfield properties, as well as separate production zones, can increase the deep insight of surfactants’ influence and increase the effectiveness of surfactant flooding. This article is devoted to the screening of surfactants for two production zones (Bashkirian and Vereian) of the Ivinskoe carbonate oilfield with high water salinity and heterogeneity. The standard core study of both production zones revealed no significant differences in permeability and porosity. On the other hand, an X-ray study of core samples showed differences in their structure and the presence of microporosity in the Bashkirian stage. The effectiveness of four different types of surfactants and surfactant blends were evaluated for both production zones by two different oil displacement mechanisms: spontaneous imbibition and filtration experiments. Results showed the higher effect of surfactants on wettability alteration and imbibition mechanisms for the Bashkirian cores with microporosity and a higher oil displacement factor in the flooding experiments for the Vereian homogeneous cores with lower oil viscosity.
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3

Li, Hong Jun. "Water Testing Technology Research and Application in Horizontal Well." Advanced Materials Research 1010-1012 (August 2014): 1754–57. http://dx.doi.org/10.4028/www.scientific.net/amr.1010-1012.1754.

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Now, water testing in horizontal well is still a worldwide problem, has not yet been mature and reliable technology is widely used in oil fields. Liaohe oilfield test center after three years of scientific research, has made some progress, developed a set of suitable technology for water testing in Liaohe oilfield horizontal wells, and to apply this technology to the water testing in oil wells, a good test results have been achieved.
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4

Wu, Run Tong, Kao Ping Song, and Er Long Yang. "The Research of the Dynamic Model of Oil Film in Pores." Applied Mechanics and Materials 448-453 (October 2013): 3046–49. http://dx.doi.org/10.4028/www.scientific.net/amm.448-453.3046.

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As a mature tertiary oil recovery technology, polymer flooding has been widely used in domestic oilfields, especially in Daqing oilfield, its polymer flooding production has reached more than 25% of total output. Therefore, there are important theoretical significance and application value to do further research of polymer flooding mechanism and use to guide the production. In order to understand the mechanism of polymer flooding, polymer flooding oil film based on the decrease of residual oil range is the biggest, established the dynamics model of polymer solution displacement of rock wall oil film under the condition of tensile and shear flow. In addition, this paper discussed the effect of the oil film thickness, tensile index, dimensionless tensile coefficient as well as the power-law coefficient on oil film start, and pointed out macroeconomic conditions which is the oil film start required.
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5

Liu, Chen, Wensheng Zhou, Junzhe Jiang, Fanjie Shang, Hong He, and Sen Wang. "Remaining Oil Distribution and Development Strategy for Offshore Unconsolidated Sandstone Reservoir at Ultrahigh Water-Cut Stage." Geofluids 2022 (September 6, 2022): 1–11. http://dx.doi.org/10.1155/2022/6856298.

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Due to the influence of long-term waterflooding, the reservoir physical properties and percolation characteristics tend to change greatly in offshore unconsolidated sandstone reservoirs at ultrahigh water-cut stage, which can affect the remaining oil distribution. Remaining oil characterization and proper development strategy-making are of vital importance to achieve high-efficiency development of mature reservoirs. The present numerical simulation method is difficult to apply in reservoir development due to the problems of noncontinuous characterization and low computational efficiency. Based on the extended function of commercial numerical simulator, the time-varying equivalent numerical simulation method of reservoir physical properties was established, and the research of numerical simulation of X offshore oilfield with 350,000 effective grids was completed. The results show that the time-varying reservoir properties have a significant impact on the distribution of remaining oil in ultrahigh water-cut reservoir. Compared with the conventional numerical simulation, the remaining oil at the top of main thick reservoir in X oilfield has increased by 18.5% and the remaining oil in the low-permeability zone at the edge of the nonmain reservoir has increased by 27.3%. The data of coring well and the implementation effect of measures in the X oilfield are consistent with the recognition of numerical simulation, which proves the rationality of numerical simulation results. The new method is based on a mature commercial numerical simulator, which is easy to operate and has reliable results.
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6

李, 晓蕾. "Study on Stratified Starting Pressure Prediction Technology for Injection Wells in Dongpu Mature Oilfield." Journal of Oil and Gas Technology 42, no. 03 (2020): 120–26. http://dx.doi.org/10.12677/jogt.2020.423073.

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7

Luo, Dai Liang, Yong Fa Qiu, Wei Bing Xie, and Guo Qiang Dong. "Research on the Key Technology of Exploiting and Waterflooding in One Well with ESP." Advanced Materials Research 655-657 (January 2013): 113–16. http://dx.doi.org/10.4028/www.scientific.net/amr.655-657.113.

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The waterflooding development of Oilfield fringe area and scattered blocks are restricted by the existing pipe network design and pipeline transportation distance and so on. In order to improve the development effect of these blocks, by using advantages of ESP including high head, range capacity and mature technology, technology of exploiting and waterflooding in one well with ESP was discussed. Then, some key problems were settled such as sand prevention, sealing, downhole monitoring of process parameters, structure design and so on, and three process schemes were summarized including exploiting the upper layer and waterflooding the lower layer, exploiting the lower layer and waterflooding the upper layer and downhole pressurized injection. The technology proposed by this article has achieved good results proved by field applications. The success of the technology provides an economical and reliable energy supply technology for oilfield development, and has a broad market prospect.
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8

Gambaro, M., and M. Currie. "The Balmoral, Glamis and Stirling Fields, Block 16/21, UK Central North Sea." Geological Society, London, Memoirs 20, no. 1 (2003): 395–413. http://dx.doi.org/10.1144/gsl.mem.2003.020.01.33.

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AbstractThe Balmoral Oilfield is a mature asset in its final phase of production. Associated with the Balmoral development have been the less significant Glamis and Stirling Fields. Each field is different from the perspective of geology and many other issues. Balmoral is a typical Paleocene oilfield with good water drive from a large regional aquifer. Interestingly this was not recognized at the start of the development when water injection facilities were commissioned. Glamis is a smaller field of Late Jurassic age containing somewhat lighter oil than Balmoral. Water injection has been necessary to maximize recovery in this field. Stirling is one of the few fields in the North Sea to produce commercially from the naturally fractured Devonian Sandstone. This field is developed by a single horizontal well.Balmoral oil recovery has significantly exceeded original expectations, whilst Glamis and Stirling have produced as much as expected.
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9

Mahdi1, Adnan Q., Fawzi M. Al-Beyati2, A. M. Al Tarif, El-Arabi H. Shendi4, and Mohamed I. .Abdel-fattah4. "Palynofacies and Paleoenvironment investigation of the Hauterivian – Early Aptian Ratawi and Zubair formations, Balad oilfield, Central Iraq." Tikrit Journal of Pure Science 24, no. 6 (November 3, 2019): 74. http://dx.doi.org/10.25130/j.v24i6.890.

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This work depends on a detailed optical observation study of sedimentary organic facies from the Hauterivian – early Aptian Ratawi and Zubair formations from the Ba-1 well, Balad oilfield, Central Iraq. This study has manifested the advantages of palynofacies analysis methods for source rock evaluation of the studied formations, twenty five cutting rock samples organic facies data indicate a wide variation of source richness, quality and thermal maturity, the Ratawi Formation samples has the Type-II< I kerogen indicates marine environment in immature stage, while Zubair Formation has the Type-II<< I kerogen (oil-gas prone) reflect the marine environment with terrigenous influx in early mature to mature stage (early oil window). http://dx.doi.org/10.25130/tjps.24.2019.111
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10

Nuttall, Carson. "Mature Oilfield Facilities Enhancement: Use of Two-Screw Multiphase Pumps To Stimulate Increased Well Production." Oil and Gas Facilities 5, no. 02 (April 1, 2016): 29–32. http://dx.doi.org/10.2118/0416-0029-ogf.

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11

Yu, Qin, Xiang guo Lu, Baoyan Zhang, and Yubao Jin. "Investigation of semi-interpenetrated networks gel for water production control in a mature offshore oilfield." International Journal of Oil, Gas and Coal Technology 20, no. 2 (2019): 127. http://dx.doi.org/10.1504/ijogct.2019.097447.

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12

Yu, Qin, Xiang guo Lu, Baoyan Zhang, and Yubao Jin. "Investigation of semi-interpenetrated networks gel for water production control in a mature offshore oilfield." International Journal of Oil, Gas and Coal Technology 20, no. 2 (2019): 127. http://dx.doi.org/10.1504/ijogct.2019.10018661.

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13

Ji, Hong, Guanghui Huang, Wenjie Xiao, and Min Zhang. "Geochemical characteristics and genetic families of crude oil in DWQ oilfield, Kuqa Depression, NW China." Journal of Petroleum Exploration and Production Technology 11, no. 6 (June 2021): 2585–97. http://dx.doi.org/10.1007/s13202-021-01197-z.

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AbstractAs one of the most petroliferous oil producing area in Kuqa depression, Dawanqi (DWQ) oilfield is supplying with great attention. In this regard, the geochemical characteristics and oil families from DWQ field were investigated using molecular compounds analysis of GC, GC–MS techniques. The bulk geochemistry of oils from DWQ oilfield displays complicated molecular composition characteristics, including relative higher indices of Pr/Ph (1.4 ~ 4.26, with an average of 2.4), high concentration of light hydrocarbons and certain abundant pentacyclic triterpene and steranes. The C7 light hydrocarbon and isoprenoids ratios indicate the oils were derived from terrestrial and higher plant input in weak oxidizing and reducing environment. Most of the oils are among the mature oils in the study area, except a few samples that are identified as slightly biodegraded by C7 hydrocarbon. Three oil families are identified in DWQ oilfield of Kuqa depression by biomarker analysis and geochemical parameters. The family A shares the attributes with higher amount of tricyclic terpanes, such as C19- C20 tricyclic terpane, higher C24-tercyclic terpane, lower concentration of gammacerane (< 0.6) but poor diasteranes. Family C is characterized with lower content of C19-tricyclic terpane than C20 tricyclic terpane, low C24-tercyclic terpane than C23-tricycli terpane, relative high concentration of gammacerane (> 0.6) but poor diasteranes. The oils of family B are mixed from the two types, showing mixed features of family A and C. The results can shed light for the exploration of the studied area.
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14

Gilbert, Robert B., Larry W. Lake, Christopher J. Jablonowski, James W. Jennings, and Emilio Nunez. "A Procedure for Assessing the Value of Oilfield Sensors." SPE Reservoir Evaluation & Engineering 12, no. 04 (July 30, 2009): 618–29. http://dx.doi.org/10.2118/109628-pa.

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Summary Spurred by improvements in reliability, cost, and accuracy, sensors offer a means of increasing expected ultimate hydrocarbon recovery in producing assets as well as in planned and prospective projects. Ultimate hydrocarbon recoveries larger than those currently achieved are possible, especially when sensors are used with advanced recovery methods. However, it is often unclear if the incremental recovery justifies the cost of installing the sensors. This paper proposes a method for estimating incremental values attributable to real-time sensors and provides a demonstration of the method for several production technologies and reservoir settings. The method offers a transparent and practical means of making value of information (VOI) computations to be implemented readily by project teams. An additional benefit of this method is that the process of specifying the inputs to the analysis facilitates a systematic discussion of strengths and weaknesses, and builds consensus regarding assumptions. The method is applied to four scenarios developed by a panel of industry experts to represent generic, but yet realistic reservoirs. The results for these scenarios indicate the value of sensors depends on the market price for product and the type of reservoir and production technology. The greatest absolute economic value for the use of sensors is obtained for a deepwater reservoir, while the greatest economic value per equivalent barrel of oil produced is obtained for a mature onshore reservoir. These expected economic values are intended to be compared to the cost required to implement the sensors to assess whether or not there is an expected net benefit. Introduction Formal methods of valuing information (sometimes called monetizing information) have existed in the research and professional literature for many years. Most publications on VOI have appeared in financial, economic, operations research, or decision analysis journals (Roberts and Weitzman 1981); little has appeared in engineering publications, especially petroleum engineering publications. Recently, a review of VOI in the oil and gas industry was presented by Bratvold et al. (2007). VOI methods are simple at the highest conceptual level: the values for courses of action with and without sensors are estimated and compared. The difference between the expected values with and without sensors is the expected value of the sensors and therefore represents the maximum willingness to pay (WTP) for the sensors. If the WTP for the sensors is greater than the cost of installation (e.g., sensor cost, installation costs, and deferred production) and operation of the sensors, their installation is expected to provide a net benefit. VOI assessments have the following components:They account for uncertainty in the outcome of decisions. The existence of uncertainty is the reason the valuation is based on expected values.They capture the ability of the sensors to change a decision. Typical decisions are an optimization of the current technology, immediate changes in technology, or the nature and timing of future technology changes.They allow for the sensors to change the monetary outcome of a course of action even when a decision is not changed by the information. This paper proposes a method for VOI assessment of real-time sensors and demonstrates the method for four different combinations of hydrocarbon recovery technologies and reservoir settings:CO2 injection in mature oil reservoirs,steam-assisted gravity drainage in heavy oil reservoirs,hydraulic fracturing in tight gas reservoirs, andwaterflooding in deepwater sandstone reservoirs. Drawing on industry experts, significant effort was made to make the cases as realistic as possible so the results can be used to inform the development of project- and corporate-level plans regarding the use of sensors. But, because of project and portfolio idiosyncrasies, the results are not to be viewed as definitive or totally generalizable.
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15

Ye, Chen, Wang Kelin, Sun Xiaofeng, Qu Jingyu, and Cao lihu. "Simulation on Incipient Particle Motion in Highly-Inclined Annulus." Recent Patents on Engineering 14, no. 1 (June 21, 2020): 103–12. http://dx.doi.org/10.2174/1872212113666190329234115.

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Background: Highly-inclined and horizontal wells have been widely used for the development of mature oilfield, marine oilfield, and low permeable oilfield. During drilling operations, cutting particles will accumulate in the low side of wellbore and cuttings bed may be formed, which may lead to high drag and torque, stuck pipe, and other drilling problems. We reviewed the patents about cutting bed cleaning tool. Objective: The goal of this work is to determine the incipient motion velocity or rate to re-suspend and remove the cutting particles. Methods: In this study, the random distribution function of particles is introduced to determine the percentage of incipient particle motion, and the mechanical models for rolling and lifting method considering the net gravity, drag force, lift force, additional mass force, adhesive force and flow pressure gradient force are developed to predict the incipient motion velocity or rate. Also, the model has been verified by published experimental data. Results: The critical particle size of incipient motion rate is approximately 1 mm. The incipient motion rate decreases as the height of cuttings bed decreases, and the minimum flow rate that prevents the bed formation may be estimated when bed height is small enough. Also, increasing wellbore inclination or fluid density has a positive effect on incipient motion rate, but increasing particle density or percentage of incipient particle motion has an adverse effect. Conclusion: This study may provide a guideline for designing hydraulic parameters and sand washing in the highly-inclined and horizontal wells, thereby contributingin economic production.
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Liang, Zhang, Wang Shu, Zhang Li, Ren Shaoran, and Guo Qing. "Assessment of CO 2 EOR and its geo-storage potential in mature oil reservoirs, Shengli Oilfield, China." Petroleum Exploration and Development 36, no. 6 (December 2009): 737–42. http://dx.doi.org/10.1016/s1876-3804(10)60006-7.

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17

Li, Jintan, Christopher Liner, and Robert Stewart. "Time-lapse seismic modeling for CO2 sequestration at the Dickman Oilfield, Kansas." GEOPHYSICS 79, no. 2 (March 1, 2014): B81—B95. http://dx.doi.org/10.1190/geo2012-0479.1.

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Carbon dioxide capture and injection into the subsurface has aroused great interest in the past few years as a method to enhance oil recovery and mitigate [Formula: see text] emissions. The Dickman Oilfield located in Kansas provides two possible [Formula: see text] sequestration targets: a regional deep saline reservoir (the primary objective) and a shallower mature depleted oil reservoir (secondary). We focused on the shallower depleted oil reservoir through a 250-year flow-simulation scenario and a fault leakage test. Seismic responses at various time intervals were simulated to help monitor [Formula: see text] flow paths and injection stability. A complex and realistic geologic model with unconformity was embedded in the flow-simulation model. A regridding technique was used that assigned geologic values to a regular seismic grid that allowed 2D acoustic and elastic finite-difference simulation. Gassmann fluid substitution theory was used to obtain the reservoir properties with different [Formula: see text] saturations, and the vertical seismic profile was used to assist in identifying geologic layers. A [Formula: see text] plume and flow path from the leakage test can be detected from the differences in seismic data (5 to 10 ms time shift) from the first year of injection and the last year of monitoring. This was supported by comparison with the prestack field data available in the Dickman Oilfield. [Formula: see text]-induced reflectivity changes are relatively larger for PS events than for PP events, implying that multicomponent data acquisition and processing may give added value to characterization and monitoring of carbon capture and storage projects. We assessed 4D seismic monitoring in the evaluation of long-term [Formula: see text] containment stability for the Dickman Oilfield and suggested that time-lapse surveys will be useful.
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18

Nugroho, Susanto B., Bambang S. Murti, and Budianto M. Toha. "Implementation of volume interpretation in revealing upside potential in a mature field, the sangatta oilfield: A case study." ASEG Extended Abstracts 2004, no. 1 (December 2004): 1–6. http://dx.doi.org/10.1071/aseg2004ab109.

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19

Carpenter, Chris. "Fracturing With Height Control Extends the Life of Mature Reservoirs in the Pannonian Basin." Journal of Petroleum Technology 73, no. 01 (January 1, 2021): 53–54. http://dx.doi.org/10.2118/0121-0053-jpt.

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200588, “Fracturing With Height Control Extends the Life of Mature Reservoirs: Case Studies From the Pannonian Basin,” by Ruslan Malon, SPE, Independent, and Jonathan Abbott, SPE, and Ludmila Belyakova, SPE, Schlumberger, et al., prepared for the 2020 SPE Europec featured at the 82nd EAGE Conference and Exhibition, originally scheduled to be held in Amsterdam, 1-3 December. The paper has not been peer reviewed. Hydraulic proppant fracturing is an effective tool in mature, low-permeability reservoirs found in the Pannonian Basin. However, for wells already producing with high water cut, even a small fracture extension into a water-bearing zone offsets the gains in hydrocarbon production. Fracture-geometry-control (FGC) techniques limit increases in water cut. The complete paper describes the first implementation of a solution to control fracture height for conventional wells in the Pannonian Basin. An integrated engineering approach was applied, including a new proppant-transport model to predict fracture geometry improvement using the FGC solution. Decreased Recovery in A and B Fields Oilfield A began producing in 1984. In addition to an interruption by the war in Yugoslavia in the 1990s, production has been in decline, and most wells are at risk of being shut in because of low production rates. During the last 10 years, propped fracturing was integrated into the production strategy for this mature field. Field A comprises Lower Pontian (Miocene) sandstones. Another sandstone formation exists between 5 and 15 m below the production target reservoir, with high water saturation as confirmed by log analysis and well testing. The proximity of the oil target to the water-bearing interval still presents a risk to production considering that hydraulic fracturing is required to extend field life. An impermeable shale streak that may act as a geomechanical barrier exists below the target formation. With a lower risk of fracture propagation into the water zone, Field A was one of the first candidate fields for propped fracturing and was later considered for advanced fracture-height-control techniques to prevent the increase of water cut after stimulation. Hydraulic fracturing would not be trialed in Field B—the characteristics of which are provided in the complete paper—until the advanced height-control techniques had been proved on the basis of experience with Field A. Oilfield A: Early Fracturing Results Early campaigns proved the economic feasibility of propped fracturing, resulting in a 2.1-fold average increase in oil production during the first 6 months of production. Unfortunately, production after this early period declined rapidly. Increases in water cut, seen in several fracturing campaigns, clearly were related to hydraulic fracture growth. Although the resulting uplift in oil production warranted continued fracturing, avoiding water was a key issue to address before expansion of propped fracturing further in this field and to other fields with an even higher risk of water.
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20

Ings, R. J., D. Davids, P. Shotton, and C. Agnew. "The Donan, Lochranza and Balloch fields, Blocks 15/20a and 15/20b, UK North Sea." Geological Society, London, Memoirs 52, no. 1 (2020): 717–39. http://dx.doi.org/10.1144/m52-2019-32.

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AbstractThe Donan Field is a mature asset in the final phase of production, following the redevelopment facilitated by various advances in technology and subsurface understanding. The original development utilized an ingenious single-well oil production system vessel which made small hydrocarbon accumulations economic, while the use of a floating production, storage and offloading vessel to redevelop the Donan Field as the ‘Dumbarton Project’ allowed the previously stranded Lochranza and undiscovered Balloch fields to be developed.Donan and Lochranza are typical Paleocene oilfields with excellent water drive from a large regional aquifer. Balloch is an Upper Jurassic oilfield of equivalent size to Lochranza supported by a large regional aquifer but has a considerably higher recovery factor on account of excellent reservoir properties combined with a more optimal geometry to effectively sweep the reservoir. Most of the fields have exceeded pre-development expectations, particularly Balloch on account of it being developed whilst considerable subsurface uncertainties remained.Recognition of a seismic amplitude v. offset response across the Donan Field was key to redevelopment, significantly increasing the oil in place and guiding the locations of development wells. This was supplemented by the ability to geosteer the horizontal development wells in the shallowest possible reservoir sand to maximize the recoverable resources. The use of horizontal development wells facilitated the development of short, areally extensive, oil columns; while the design of the production facilities and wells to include permanent artificial lift and capacity to process large water volumes was essential.
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21

Hartanto, Lina, Wisnu Widjanarko, and Diala Muna. "The success story of Windalia waterflood optimisation through integrated asset management in a mature field." APPEA Journal 51, no. 2 (2011): 726. http://dx.doi.org/10.1071/aj10106.

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Australia’s Barrow Island Windalia reservoir—the nation’s largest onshore waterflood—was developed in the late 1960s. The Barrow Island oilfield is Chevron Australia’s only mature waterflood, comprising more than 220 active injectors. The injectors pressurise and increase oil recovery from the geologically complex, low-permeable and heterogeneous Windalia Sand Member. To date it is estimated that the value of waterflooding has effectively reduced the field decline rate from approximately 18 % per annum to less than 2 %—adding millions of barrels in recovery and years on to productive field life. In September of 2008, the Windalia Waterflood achieved full field restitution. This involved the replacement and commissioning of glass-reinforced epoxy injection flow lines, a ring-main network and produced water re-injection facilities. Significant challenges were overcome in the process of realising the restitution’s full potential. Several waterflood optimisation activities have now been executed to achieve oil uplift and to capitalise on Chevron Australia’s investment. Compounded with restitution, the activities have successfully achieved the asset objective of arresting field production decline. This paper highlights the challenges encountered by the waterflood team, providing insights and lessons learned in the dynamic and holistic nature of waterflood management. It also highlights the interplay of considerations and what is crucial to achieving optimum sweep efficiency and pressurisation.
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Li, Jintan, Christopher Liner, Po Geng, and Jianjun Zeng. "Convolutional time-lapse seismic modeling for CO2 sequestration at the Dickman oilfield, Ness County, Kansas." GEOPHYSICS 78, no. 3 (May 1, 2013): B147—B158. http://dx.doi.org/10.1190/geo2012-0159.1.

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Time-lapse seismic modeling is routinely used to detect the state of hydrocarbon reservoirs at periodic time intervals. The Dickman field located in the U. S. midcontinent provides two possible [Formula: see text] sequestration targets: a regional deep saline reservoir is the primary objective, and a shallower, mature, depleted oil reservoir is a secondary objective. The goal of this work is to characterize and simulate monitoring of the [Formula: see text] movement before, during, and after its injection into these sequestration targets, including fluid flow paths, reservoir property changes, [Formula: see text] containment, and postinjection stability. Seismic images before, during, and after injection would improve understanding of the carbonate sequestration process and management. Our seismic simulation for time-lapse [Formula: see text] monitoring was based on flow simulator output over a 250-year injection and simulation period. The seismic response was accomplished via convolutional (1D) forward modeling. This work will provide an evaluation for the effectiveness of 4D seismic monitoring in providing assurance of long-term [Formula: see text] containment.
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23

Li, Na. "Study on wellbore annular sealing technology based on the influence of fracturing operation in low permeability oilfield." E3S Web of Conferences 352 (2022): 01045. http://dx.doi.org/10.1051/e3sconf/202235201045.

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At present, the fracturing technology has been very mature and is widely used in oil and gas field production operation. However, the fracturing operation will cause periodic changes in wellbore internal pressure and generate alternating stress. Due to the material factors of casing and cement sheath, the deformation of the two is inconsistent after stress, and then the damage of cement sheath and the failure of wellbore annulus seal occur. After water injection development, it is easy to produce channeling risk, so the performance of cement sheath is crucial. In view of this problem, through the theoretical analysis, experimental analysis and organic combination analysis of wellbore annulus cement ring sealing, the critical failure threshold of wellbore annulus cement ring under fracturing operation is given, which provides certain guidance for improving wellbore annulus sealing and reducing the risk of channeling after fracturing operation in the future.
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24

Al-Najm, Fahad M., Amer Jassim Al-Khafaji, and Fadhil N. Sadooni. "The Late Cretaceous X Reservoir petrophysics properties and its Oil Geochemistry in the Nameless Oilfield, Mesopotamian Basin, South Iraq." Journal of Petroleum Research and Studies 12, no. 1(Suppl.) (April 21, 2022): 54–67. http://dx.doi.org/10.52716/jprs.v12i1(suppl.).622.

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The X Formation, which dates from the Late Cenomanian to the early Turonian, is the largest carbonate reservoir in Iraq's South Mesopotamian Basin. There are two shallowing-up depositional periods in it, which begin with deep water mudstone associated with wackestone, which gradually shallows into rudist and is dominated by big foraminifera shoals and barriers, which are followed by lagoonal and intertidal facies. The identification of five distinct reservoir rock types, including mB2, mB1, CRII, mA, and CRI, was based on a combination of sediment types and diagenetic processes that influenced porosity types. The formation oil geochemical studies point to a Lower Cretaceous marine carbonate source depositional environment that is early mature and anoxic.
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Feng, Jiu Hong, and Yang Liu. "The Complementary Technologies to Improve Polymer Flooding Efficiency for Class II Reservoirs of Daqing Oilfield." Applied Mechanics and Materials 522-524 (February 2014): 1537–41. http://dx.doi.org/10.4028/www.scientific.net/amm.522-524.1537.

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With the amount of polymer used in oil field increases year by year and the development results turn worse, people started to pay more attention to the technologies which can improve the polymer flooding recovery of class II reservoirs. Polymer flooding efficiency can be enhanced through methods such as detail geologic analysis, project design optimization and strengthen procedure management with applying mature supporting technologies. In this paper, the necessity of improving the polymer flooding effect of class II reservoir is introduced. The technologies to develop polymer flooding efficiency are proposed. The applying results of these technologies show that meticulous reservoir simulation and deepen recognize of structure and reserve and residual oil distribution are the base of improving polymer flooding efficiency. Optimizing polymer injection design to match the oil reserve is the key part of improving polymer flooding efficiency. Deepening technology research and building workflow of different measures and adjustment technologies at different production stages are efficient ways to improve polymer flooding efficiency. Insisting on the comprehensive adjust pattern of normal molecular weight with normal molecular concentration, individual design, scale injection, profile control in time, adjust with time and strengthen procedure management are the predominant guarantee of improving polymer flooding efficiency.
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Zhou, Fangcheng, Tao Wang, Changqing Ma, Pengfei Lei, Xinyi Zhang, and Qingxin Ding. "Review on the Evaluation of Casing Damage Level in Oil and Gas Field." MATEC Web of Conferences 256 (2019): 02008. http://dx.doi.org/10.1051/matecconf/201925602008.

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The casing damage is a common problem encountered in the oil and gas field, and the casing damage will cause huge losses to the economic benefits of the oil and gas field. Grading the damage degree of the casing damage well can provide theoretical support for the oilfield workover operation and save the cost of workover. The casing damage classification has a strong guiding significance for the economic evaluation of the casing damage repair and the development of appropriate workover technology. After a review research on domestic and foreigner papers on the study of casing damage classification, it can be found that there is no mature theory and method for casing damage classification. After analyzing the entire workover process, the concept of the damage repair evaluation expert system is proposed to complete the entire workover process, evaluate the cost, and help the oil and gas field to obtain the best benefits.
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Menezes, Paulo T. L., Jorlivan L. Correa, Leonardo M. Alvim, Adriano R. Viana, and Rui C. Sansonowski. "Time-Lapse CSEM Monitoring: Correlating the Anomalous Transverse Resistance with SoPhiH Maps." Energies 14, no. 21 (November 1, 2021): 7159. http://dx.doi.org/10.3390/en14217159.

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The CSEM method, which is frequently used as a risk-reduction tool in hydrocarbon exploration, is finally moving to a new frontier: reservoir monitoring and surveillance. In the present work, we present a CSEM time-lapse interpretation workflow. One essential aspect of our workflow is the demonstration of the linear relationship between the anomalous transverse resistance, an attribute extracted from CSEM data inversion, and the SoPhiH attribute, which is estimated from fluid-flow simulators. Consequently, it is possible to reliably estimate SoPhiH maps from CSEM time-lapse surveys using such a relationship. We demonstrate our workflow’s effectiveness in the mature Marlim oilfield by simulating the CSEM time-lapse response after 30 and 40 years of seawater injection and detecting the remaining sweet spots in the reservoir. The Marlim reservoirs are analogous to several turbidite reservoirs worldwide, which can also be appraised with the proposed workflow. The prediction of SoPhiH maps by using CSEM data inversion can significantly improve reservoir time-lapse characterization.
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Wu, Qiong. "Analysis of reducing pressure and increasing injection in high pressure water injection block of low permeability reservoir." E3S Web of Conferences 358 (2022): 02028. http://dx.doi.org/10.1051/e3sconf/202235802028.

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The plugging phenomenon near the well zone of oil injection well will seriously affect the water injection development of oil field, and then affect the exploitation of oil resources. The water injection development of low permeability reservoir is affected by various factors. Due to the large difference between layers and the serious interference between layers, the physical property of oil layer is relatively poor, and the water injection pressure shows a trend of increasing year by year, which has a great impact on the development of oil resources. As the oilfield development benefit is not ideal, it is necessary to take reasonable measures to reduce the pressure of water injection to ensure the effect of water injection to improve the recovery of the reservoir. At present, the technology has been mature, which can reduce the pressure of water injection and ensure the oil recovery rate. The application in several oil Wells has verified the correctness of this conclusion.
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Allawi, Raed H., and Mohammed S. Al-Jawad. "4D Finite element modeling of stress distribution in depleted reservoir of south Iraq oilfield." Journal of Petroleum Exploration and Production Technology 12, no. 3 (October 22, 2021): 679–700. http://dx.doi.org/10.1007/s13202-021-01329-5.

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AbstractThe harvest of hydrocarbon from the depleted reservoir is crucial during field development. Therefore, drilling operations in the depleted reservoir faced several problems like partial and total lost circulation. Continuing production without an active water drive or water injection to support reservoir pressure will decrease the pore and fracture pressure. Moreover, this depletion will affect the distribution of stress and change the mud weight window. This study focused on vertical stress, maximum and minimum horizontal stress redistributions in the depleted reservoirs due to decreases in pore pressure and, consequently, the effect on the mud weight window. 1D and 4D robust geomechanical models are built based on all available data in a mature oil field. The 1D model was used to estimate all mechanical rock properties, stress, and pore pressure. The minimum and maximum horizontal stress were determined using the poroelastic horizontal strain model. Furthermore, the mechanical properties were calibrated using drained triaxial and uniaxial compression tests. The pore pressure was tested using modular dynamic tester log MDT. The Mohr–Coulomb model was applied in the 4D model to calculate the stress distribution in the depleted reservoir. According to study wells, the target area has been classified into four main groups in Mishrif reservoir based on depletion: highly, moderately, slightly, and no depleted region. Also, the results showed that the units had been classified into three main categories based on depletion state (from above to low depleted): L1.1, L1.2, and M1. The mean average reduction in minimum horizontal stress magnitude was 322 psi for L1.1, 183.86 psi for L1.2, and 115.56 psi for M1. Thus, the lower limit of fracture pressure dropped to a high value in L1.1, which is considered a weak point. As a result of changing horizontal stress, the mud weight window became narrow.
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Baban, Dler. "Source Rocks’ Potentiality of the Sargelu Formation (Middle Jurassic) in the Taq Taq Oilfield, Kurdistan Region, Iraq." Iraqi Geological Journal 54, no. 2E (November 30, 2021): 59–85. http://dx.doi.org/10.46717/igj.54.2e.5ms-2021-11-21.

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Thirty rock samples were selected from the well Tq-1 that penetrated the Jurassic beds in the Taq Taq Oilfield to be studied the source rock potentiality of the Sargelu Formation. The formation is characterized by three types of microfacies, namely, foraminiferal packstone, grainstone microfacies, fossiliferous packstone microfacies, and foraminiferal wackestone which were deposited in an environment extending from middle to outer carbonate ramp. An average of 3.03 wt.% of total organic carbon was obtained from a Rock Eval pyrolysis analysis carried out on 24 selected rock samples. The petrographic analysis for such organic matters revealed that they are of kerogen types III and IV and they are currently in a post-mature state. Pyrolysis parameters showed that limited generation potential was remained for these sources to expel generated hydrocarbons. The palynological study showed that Amorphous Organic Matter forms the highest percentage of organic matter components with more than 70%, followed by phytoclasts with 10 – 25 % and palynomorphs of less than 10%. The organic matters within the Sargelu Formation are deposited at the distal part of the basin under suboxic to anoxic condition. The color of the organic matter components, examined under transmitted light, showed Thermal Alteration Index values between 3+ and 4-. Such values may indicate that these organic matters are thermally at the end of the liquid oil generation zone and beginning of condensate-wet gas generation zone. The thermal maturity of the Sargelu Formation depending on the calculated VRo% revealed that the formation in the studied oilfield is currently at the peak of the oil generation zone. The Sargelu Formation in the studied field is considered as an effective source rock, as it has already generated and expelled hydrocarbons.
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Liu, Lin, Lixin Zhao, Yahong Wang, Shuang Zhang, Minhang Song, Xueqiang Huang, and Zhongrun Lu. "Research on the Enhancement of the Separation Efficiency for Discrete Phases Based on Mini Hydrocyclone." Journal of Marine Science and Engineering 10, no. 11 (October 31, 2022): 1606. http://dx.doi.org/10.3390/jmse10111606.

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The economic and efficient treatment of mixed media in offshore produced fluids is of great significance to oilfield production. Due to the small space and limited load-bearing capacity of offshore platforms, some mature multiphase media separation processes in onshore oilfields are difficult to apply. Therefore, high-efficiency processing methods with small-occupied space are required. Mini hydrocyclones (MHCs) are a potential separation method due to their simple structure, small footprint, and high separation efficiency (especially for fine particles or droplets). However, for discrete phases with different densities and sizes, the enhancement rule of the separation efficiency of MHCs is not yet clear. In this paper, numerical simulation methods were used to study the separation performance of hydrocyclones with different main diameters (including conventional hydrocyclones (CHCs) and MHCs) for discrete phases with different densities and particle sizes. Results show that MHC has the optimal enhancement range for oil–water separation when oil-droplet sizes are 60–300 μm, while the optimal enhancement range for silica particle and water separation is 10–40 μm. For other droplet/particle size ranges, the efficiency enhancement effect of MHC is not obvious compared to conventional hydrocyclones. By calculating the radial force of particles in MHC and CHC, the reasons for the enhanced efficiency of MHC are theoretically analyzed. The pressure drop of MHC is higher than CHC under the same feed velocity, which can be improved by connecting CHC with MHC. Additionally, the fluid velocity test experiments based on particle image velocimetry (PIV) were carried out to verify the accuracy of the numerical simulations. This study clarified the scope of application of MHCs to different discrete phase types, in order to provide a basis for the precise application of MHCs.
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Xu, Anzhu, Fachao Shan, Xiao Yang, Jiaqi Li, Chenggang Wang, and Junjian Li. "Thief zone identification and classification in unconsolidated sandstone reservoirs: A field case study." Journal of Petroleum Exploration and Production Technology 11, no. 9 (July 28, 2021): 3451–62. http://dx.doi.org/10.1007/s13202-021-01239-6.

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AbstractChanneling between injectors and producers leads to bypassed oil left in the reservoir, which is one of most common reasons that wells in mature oil fields experience high water cut after long-term waterflooding. Identification and evaluation of the higher permeable channels (thief zones) are the key to effectively plug these thief zones and improve the conformance of water flood. This study applies three different methods to identify and evaluate the thief zones of a water injection project in North Buzazi Oilfield, a thick-bedded unconsolidated sandstone heavy oil reservoir in Manghestau, Kazakhstan. The thief zones, which evolve as a result of formation erosion and sand production, are identified and classified with respect to four different levels of significance using fuzzy comprehensive evaluation, production/injection profile method and pressure index (PI) methods. Good consistency is observed among the identification results using these methods. Finally, we present two ways to quantitatively evaluate the characteristics of the thief zones using water–oil-ratio as the input, which can be readily applied for future field development design.
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33

Feng, Qihong, Kuankuan Wu, Jiyuan Zhang, Sen Wang, Xianmin Zhang, Daiyu Zhou, and An Zhao. "Optimization of Well Control during Gas Flooding Using the Deep-LSTM-Based Proxy Model: A Case Study in the Baoshaceng Reservoir, Tarim, China." Energies 15, no. 7 (March 24, 2022): 2398. http://dx.doi.org/10.3390/en15072398.

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Gas flooding has proven to be a promising method of enhanced oil recovery (EOR) for mature water-flooding reservoirs. The determination of optimal well control parameters is an essential step for proper and economic development of underground hydrocarbon resources using gas injection. Generally, the optimization of well control parameters in gas flooding requires the use of compositional numerical simulation for forecasting the production dynamics, which is computationally expensive and time-consuming. This paper proposes the use of a deep long-short-term memory neural network (Deep-LSTM) as a proxy model for a compositional numerical simulator in order to accelerate the optimization speed. The Deep-LSTM model was integrated with the classical covariance matrix adaptive evolutionary (CMA-ES) algorithm to conduct well injection and production optimization in gas flooding. The proposed method was applied in the Baoshaceng reservoir of the Tarim oilfield, and shows comparable accuracy (with an error of less than 3%) but significantly improved efficiency (reduced computational duration of ~90%) against the conventional numerical simulation method.
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34

Edwards, C. W. "The Buchan Field, Blocks 20/5a and 21/1a, UK North Sea." Geological Society, London, Memoirs 14, no. 1 (1991): 253–59. http://dx.doi.org/10.1144/gsl.mem.1991.014.01.31.

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AbstractThe Buchan Oilfield is located in Blocks 21/la and 20/5a of the UK North Sea, on the southern side of the Witch Ground Graben. The Buchan structure is a complex tilted and dissected fault block formed during Jurassic extension and rifting. The Upper Devonian-Carboniferous reservoir is composed of fluvial Old Red Sandstone facies sandstones sealed by Lower Cretaceous mudstones and contains a 585m (1919 ft) thick oil column. Poor matrix porosities and permeabilities are enhanced by a pervasive fracture system, although faulting in the reservoir restricts communication between several of the nine producing wells. Hydrocarbon migration has occurred from a mature Upper Jurassic source rock north of the field into the structure across the flank faults. Production of the highly under-saturated oil is by depletion drive with some aquifer sweep to a floating production facility and onward transmission to the Forties Field by pipeline. Production commenced in 1981 and original recoverable reserves are estimated at 90 MMBBL of which 71.5 MMBBL have already been produced.
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35

Merry, Adrian, Julie Cass, Toby Kayes, Steven Helmore, and Helix RDS Aberdeen. "Case History: Arbroath: An Integrated Petrophysical and Seismic Elastic Inversion Process for De-Risking Infill Drilling Targets in a Mature North Sea Oilfield." ASEG Extended Abstracts 2007, no. 1 (December 1, 2007): 1. http://dx.doi.org/10.1071/aseg2007ab196.

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36

Papi, Ali, Amin Sharifi, and Mohammad Reza Abdali. "Simulation of the effect of rock type on recovery plan of a mature carbonate oilfield in the Middle East – Part 2: EOR plan." Petroleum Science and Technology 37, no. 11 (March 23, 2019): 1260–69. http://dx.doi.org/10.1080/10916466.2018.1550511.

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37

Cao, Renyi, Zhihao Jia, Linsong Cheng, Zhikai Wang, Tianming Ye, and Zhenhua Rui. "Using high-intensity water flooding relative permeability curve for predicting mature oilfield performance after long-term water flooding in order to realize sustainable development." Journal of Petroleum Science and Engineering 215 (August 2022): 110629. http://dx.doi.org/10.1016/j.petrol.2022.110629.

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38

Papi, Ali, Amin Sharifi, and Mohammad Reza Abdali. "Simulation of the effect of rock type on recovery plan of a mature carbonate oilfield in the Middle East – Part 1: Waterflooding recovery plan." Petroleum Science and Technology 37, no. 11 (March 23, 2019): 1251–59. http://dx.doi.org/10.1080/10916466.2018.1550510.

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39

Johnson, Gareth, Bernhard Mayer, Maurice Shevalier, Michael Nightingale, and Ian Hutcheon. "Tracing the movement of CO2 injected into a mature oilfield using carbon isotope abundance ratios: The example of the Pembina Cardium CO2 Monitoring project." International Journal of Greenhouse Gas Control 5, no. 4 (July 2011): 933–41. http://dx.doi.org/10.1016/j.ijggc.2011.02.003.

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40

Wynn, T., and E. Saundry. "The Buchan Field, Blocks 20/5a and 21/1a, UK North Sea." Geological Society, London, Memoirs 52, no. 1 (2020): 679–90. http://dx.doi.org/10.1144/m52-2018-11.

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AbstractThe Buchan Oilfield is a large mature field, now suspended, located in the Moray Firth. The field is situated 153 km NE of Aberdeen in water depths of c. 122 m. The reservoir comprises an overpressured and fractured Upper Devonian–Early Carboniferous fluvio-lacustrine sandstone. Production was via high permeability channel sandstones and permeable faults and fractures. The Buchan Field was brought onto production in May 1981 by BP Petroleum Development Ltd via the Buchan Alpha semi-submersible floating production vessel (FPV). The oil column is c. 2000 ft in height with a matrix stock tank oil initially in place (STOIIP) range of 322–471–668 MMbbl. Production from the ten vertical development wells was driven by pressure depletion (over 5000 psi since first oil) coupled with weak aquifer influx. Production from the Buchan Field ceased on 13 May 2017 after having produced 147.8 MMbbl. The Buchan FPV was subsequently taken off-station during August 2017. A new facility or tie-back redevelopment option will be required to access the remaining resources which are in the range of 20–90 MMbbl depending on the STOIIP, the production mechanism and the potential development plan.
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41

Hien, Doan Huy, Hoang Long, and Pham Quy Ngoc. "Screening selection of enhanced oil recovery methods based on analytics of worldwide oilfield data with reference to offshore oil fields in Vietnam." Petrovietnam Journal 6 (June 30, 2021): 4–17. http://dx.doi.org/10.47800/pvj.2021.06-01.

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Selecting a proper enhanced oil recovery (EOR) method for a prospective reservoir is a key factor for successful application of EOR techniques. Reservoir engineers usually refer to screening guidelines to identify potential EOR processes for a given reservoir. However, these guidelines are often too general. In this study, we develop an advanced EOR screening technique based on the statistical analyses with boxplot in combination with some initial deep learning analyses to select the most suitable EOR method for a given mature oil field. At first, a database and the screening guidelines were established by compiling the information of 1,098 EOR projects from various publications in different languages, including Oil and Gas Journal (OGJ) biannual EOR surveys, SPE publications, DOE reports, and Chinese publications, etc. Boxplots were used to detect the special cases for each reservoir/fluid property and to present the graphical screening results. A case study was used to demonstrate that with a simple input of reservoir/fluid information, the proposed procedure could effectively give recommendations for EOR method selection. With the inputs (reservoir and fluid properties) from Vietnam offshore oil fields, the EOR methods recommended by this study are mostly chemical, including polymer and surfactant injection.
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42

Zhao, Lun, Jincai Wang, Libing Fu, Li Chen, and Zhihao Jia. "Improve Oil Recovery Mechanism of Multi-Layer Cyclic Alternate Injection and Production for Mature Oilfield at Extra-High Water Cut Stage Using Visual Physical Simulation Experiment." Energies 16, no. 3 (February 3, 2023): 1546. http://dx.doi.org/10.3390/en16031546.

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In order to achieve sustainable development of mature oilfield, a series of adjustment measures should be implemented to improve production performance at the extra-high water cut stage. South Kumkol reservoir is a typical multi-layer low viscosity oil reservoir, which has the characteristics of small sandstone body, high shale volume, and strong heterogeneity. At present, the water cut of the South Kumkol reservoir is about 90%, which is on the verge of being abandoned. Multi-layer cyclic alternate injection and production (MCA-IP) is an ideal adjustment measure for multi-layer oil reservoir to improve oil recovery (IOR) at the extra-high water cut stage. In this paper, we designed the double-plate visual physical device and the MCA-IP experimental program and then calculated the sweep coefficient using image recognition method. Furthermore, the sweep coefficient was quantitatively calculated by image recognition method. The results show that the sweep area extends to both sides of the main streamline and the sweep efficiency is gradually improved after the completion of MCA-IP. In addition, the IOR mechanism of MCA-IP mainly includes reperforation, well-pattern encryption, and asynchronous injection-production. The reperforation and well-pattern encryption increased the sweep coefficient by about 19.52%, while asynchronous injection-production increased the sweep coefficient by about 1.2%, and the overall sweep coefficient increased by about 20.7%. According to the experimental data statistics, the MCA-IP method can increase oil recovery by about 11% and reduce water cut by about 6%.
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43

Teles, Eduardo Oliveira, Ana Paula Maia Tanajura, Francisco Gaudêncio Mendonça Freires, and Ednildo Andrade Torres. "Reactivation of Mature Oilfields: A Multifaceted Production Management." International Journal of Materials, Mechanics and Manufacturing 4, no. 1 (2015): 36–39. http://dx.doi.org/10.7763/ijmmm.2016.v4.221.

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44

Wang, Xiaoyan, Jie Zhang, Guangyu Yuan, Wei Wang, Yanbin Liang, Honggang Wang, and Yiqiang Li. "Effect of Emulsification on Enhanced Oil Recovery during Surfactant/Polymer Flooding in the Homogeneous and Heterogeneous Porous Media." Geofluids 2021 (February 19, 2021): 1–9. http://dx.doi.org/10.1155/2021/6674185.

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Surfactant polymer (SP) flooding has become an important enhanced oil recovery (EOR) technique for the high-water cut mature oilfield. Emulsification in the SP flooding process is regarded as a powerful mark for the successful application of SP flooding in the filed scale. People believe emulsification plays a positive role in EOR. This paper uses one-dimensional homogenous core flooding experiments and parallel core flooding experiments to examine the effect of emulsification on the oil recoveries in the SP flooding process. 0.3 pore volume (PV) of emulsions which are prepared using ultralow interface intension (IFT) SP solution and crude oil with stirring method was injected into core models to mimic the emulsification process in SP flooding, followed by 0.35 PV of SP flooding to flood emulsions and remaining oil. The other experiment was preformed 0.65 PV of SP flooding as a contrast. We found SP flooding can obviously enhance oil recovery factor by 25% after water flooding in both homogeneous and heterogeneous cores. Compared to SP flooding, emulsification can contribute an additional recovery factor of 3.8% in parallel core flooding experiments. But there is no difference on recoveries in homogenous core flooding experiments. It indicates that the role of emulsification during SP flooding will be more significant for oil recoveries in a heterogeneous reservoir rather than a homogeneous reservoir.
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45

Jin, Fayang, Rui Liu, Wanfen Pu, and Cailin Wen. "Preparation and Properties of Polymer/Vermiculite Hybrid Superabsorbent Reinforced by Fiber for Enhanced Oil Recovery." Journal of Chemistry 2014 (2014): 1–9. http://dx.doi.org/10.1155/2014/286091.

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A series of polymer/clay hybrid superabsorbent composites (SACFs) comprising acrylamide, acrylic acid, sodium 2-acrylamido-tetradecyl sulfonate, fiber, and vermiculite byin situintercalation and exfoliated method was successfully synthesized. The structure of SACFs was characterized by IR, SXRD, and SEM measurements. Much notable absorbency for SACF-2 was observed compared to that for SACF-1 in the absence of hydrophobic group in the high cationic solution due to the alkyl carbon chain and sulfonic acid group of hydrophobic moistures protecting the cations from attacking the carboxylate groups. What is more, high temperature fiber which acts as bridge connection for the polymeric network structure enhanced both toughness and strength for SACF-4 in the harsh conditions. At the total dissolved substance of 212000 mg/L for Tarim Basin injected water and the temperature of 120°C, desired absorbency as well as water retaining property for SACF-4 was observed during the long period of thermal ageing. Core flooding experiments demonstrated that SACFs could migrate as amoeba in the porous medium and accumulated in the narrow channel to adjust injection profile, promoting the subsequent water diverting into the unswept zones. Finally, characteristic parameters for SACFs calculated from flooding experiment further confirmed these polymer/clay hybrid composites reinforced by fiber would have robust application in the mature oilfield for profile control.
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46

Wang, Weiyang, Wei Zhu, and Mingzhong Li. "Gas–Liquid Flow Behavior in Condensate Gas Wells under Different Development Stages." Energies 16, no. 2 (January 14, 2023): 950. http://dx.doi.org/10.3390/en16020950.

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The phase state prediction methods of condensate gas are relatively mature, but the effect of phase changes on gas–liquid mixture flow behavior and the liquid-carrying capacity of gas has not been researched in detail. This study applied PIPESIM software to predict the fluid phase properties under different development stages of a condensate gas reservoir in Shengli Oilfield and determined the phase diagram and physical properties of the well stream on the basis of the optimized equation of state (EOS). Then the influence of phase change characteristics on wellbore flow behavior and critical liquid-carrying gas velocity was analyzed. The study showed that compared with the early development stage, fewer heavy components are produced and the produced gas–liquid ratio is increased in the late stage of the condensate gas reservoir. In addition, the pressure loss of fluid is decreased, the critical liquid-carrying gas velocity and flow rate are reduced, and the liquid-lifting difficulty is reduced for gas. The reason is that the liquid density decreases obviously due to the phase change, while the gas density is almost unchanged, and the oil–gas surface tension decreases obviously, resulting in a decrease in the critical liquid-carrying gas velocity. At the same time, the variation in the gas compressibility factor is very small, which leads to a decrease in the critical liquid-carrying gas flow rate.
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47

Uzoegbu, U., A. J C Madu, U. Ugwueze, and O. Omang. "Api gravities and geochemical evaluation of crude oils from sapele, niger – delta, nigeria." Global Journal of Geological Sciences 21, no. 1 (February 2, 2023): 69–89. http://dx.doi.org/10.4314/gjgs.v21i1.6.

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The investigation is to provide information on source organic matter input, depositional conditions and the correlation between crude oils recovered from Sapele oilfield in the Niger Delta. A suite of twenty-five crude oils from the Agbada reservoirs (synsedimentary) of the Tertiary Niger Delta (Southern Nigeria) were analysed based on API gravities and geochemically compared with extracts from source rock of the Akata and Agbada Formations. The Sapele shallow reservoirs occur between the depths of 4000ft and 6000ft, containing heavy crudes with API gravities 20 – 22 degrees. The deep reservoirs lie within 7000ft and 12000ft accumulating the light crudes with API gravities of 24.70-35.60 degrees, and viscocity of 1.64cP. The investigated biomarkers indicated that the Sapele oils were derived from mixed marine and terrigenous organic matter and deposited under suboxic conditions. This has been achieved from normal alkane and acyclic isoprenoids distributions, terpane and sterane biomarkers. These oils were also generated from source rock with a wide range of thermal maturity and ranging from early-mature to peak oil window. Based on molecular indicators of organic source input and depositional environment diagnostic biomarkers, one petroleum system operates in the Niger Delta Region; as observed on the source rocks from the Agbada organic – rich shale sediments. Therefore, the hydrocarbon exploration processes should be concentrating on the Akata and Agbada area of the Tertiary strata for determining the source kitchen.
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48

Hatif, Mina. "COMPARATIVE ORGANIC GEOCHEMICAL STUDY OF CRETACEOUS RESERVOIRS OF ZUBAIR OIL FIELD, SOUTHERN IRAQ." Iraqi Geological Journal 53, no. 2D (October 31, 2020): 128–47. http://dx.doi.org/10.46717/igj.53.2d.9ms-2020.10-31.

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Three formations were chosen in the present study, these are Yamamma, Zubair and Mishrif formations, which are considered the main reservoirs at Zubair oilfield southern Iraq, especially during the Cretaceous period. The studied reservoirs are distinguished by different rocks, facies and environmental specifications. Thirteen wells were selected for the present study these are: Zb-44, Zb-202, Zb-10, Zb-294, Zb-81, Zb-233, Zb-329, Zb-49, Zb-9, Zb-156, Zb-8, Zb-256 and Zb-187. To studying the geochemical parameters of crude oils. Geochemical analysis of crude oil was applied. The results of the isotope analyses indicate that the source rock of oil is a mature marine rock that contains a high percentage of sulfur. The American Petroleum Institute values are ​​ranging from 35-20 indicate medium to light hydrocarbons. The results show that the Kerogen type is type II which is derived from marine algae organism. The burial history indicates that the subsidence is high at the late Jurassic - early Cretaceous period and also at the Miocene, and the slow subsidence during the late Cretaceous and moderate subsidence at the Paleogene. The results of the Vitrinite Reflection and Production Index show that the thermal maturity is happened at the early to the main stage, which was represented at the Zb-44 and Zb-202 wells. The transformation ratio of Zubair and Yamamma formations indicates that the possibility of kerogen to yield oil and gas is high in the future with temperature increasing.
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Cather, Martha, Dylan Rose-Coss, Sara Gallagher, Natasha Trujillo, Steven Cather, Robert Spencer Hollingworth, Peter Mozley, and Ryan J. Leary. "Deposition, Diagenesis, and Sequence Stratigraphy of the Pennsylvanian Morrowan and Atokan Intervals at Farnsworth Unit." Energies 14, no. 4 (February 17, 2021): 1057. http://dx.doi.org/10.3390/en14041057.

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Farnsworth Field Unit (FWU), a mature oilfield currently undergoing CO2-enhanced oil recovery (EOR) in the northeastern Texas panhandle, is the study area for an extensive project undertaken by the Southwest Regional Partnership on Carbon Sequestration (SWP). SWP is characterizing the field and monitoring and modeling injection and fluid flow processes with the intent of verifying storage of CO2 in a timeframe of 100–1000 years. Collection of a large set of data including logs, core, and 3D geophysical data has allowed us to build a detailed reservoir model that is well-grounded in observations from the field. This paper presents a geological description of the rocks comprising the reservoir that is a target for both oil production and CO2 storage, as well as the overlying units that make up the primary and secondary seals. Core descriptions and petrographic analyses were used to determine depositional setting, general lithofacies, and a diagenetic sequence for reservoir and caprock at FWU. The reservoir is in the Pennsylvanian-aged Morrow B sandstone, an incised valley fluvial deposit that is encased within marine shales. The Morrow B exhibits several lithofacies with distinct appearance as well as petrophysical characteristics. The lithofacies are typical of incised valley fluvial sequences and vary from a relatively coarse conglomerate base to an upper fine sandstone that grades into the overlying marine-dominated shales and mudstone/limestone cyclical sequences of the Thirteen Finger limestone. Observations ranging from field scale (seismic surveys, well logs) to microscopic (mercury porosimetry, petrographic microscopy, microprobe and isotope data) provide a rich set of data on which we have built our geological and reservoir models.
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Iheaturu, T. C., R. U. Ideozu, S. Abrakasa, and A. E. Jones. "Sequence stratigraphy and tectonic framework of the Gabo Field, Niger Delta, Nigeria." Scientia Africana 21, no. 3 (January 29, 2023): 19–36. http://dx.doi.org/10.4314/sa.v21i3.2.

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Abstract:
This research examines the sequence stratigraphic and structural framework of the Gabo Field Niger Delta, Nigeria. Materials used in this research include 3D seismic volume in Seg-Y, ditch cuttings and wells logs. The methods applied are standard methods in addition to using the Frazier and Galloway approach for genetic sequences. The tectonic framework was interpreted in terms of deformational, depositional and post-depositional structures. The deformational structures are faults F1 and F2 – which are closely spaced normal faults and F3 is a syn-depositional growth fault. The depositional structures are pinchouts and interbedded sand/shale sequences whereas the postdepositional structures are compaction and smearing or flexure of the shales. The well correlation shows the sequences are cyclic and the facies analysis of T4 – T9 sands are very fine to medium grained, light to dark brown, texturally mature and moderate to well sorted. The facies associations are fluvial distributary channel, tide dominated fluvial channels, abandoned channel or switching and flood plain deposits. While the depositional environments are upper delta plain, lower delta plain and delta front. Sequence stratigraphic analysis explained the observed increase in shale thickness in the intermediate sections and showed sediment deposition occurred in three (3) systems tracts- Lowstand Systems Tract (LST), the Transgressive Systems Tract (TST) and Highstand Systems Tract (HST). The sedimentological model showed the environments of deposition had a tidal influence and ranged from fluvial to estuarine. The findings of this research may be applied to similar deltaic basins around the world in planning of oilfield development. In addition it may correlate cyclic successions and predict facies distributions of similar depositional patterns.
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