Offshore Heavy Oil Polymerflooding Pilot Reveals Alternative Paths

2021 ◽  
Vol 73 (04) ◽  
pp. 49-50
Author(s):  
Chris Carpenter
Keyword(s):  
Heavy Oil ◽  
High Viscosity ◽  
Oil Field ◽  
Oil Fields ◽  
Tube Length ◽  
Polymer Injection ◽  
Injection Mode ◽  
Offshore Technology ◽  
Water Cut ◽  
Continuous Injection

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30277, “Twelve-Year Field Applications of Offshore Heavy Oil Polymerflooding From Continuous Injection to Alternating Injection of Polymer and Water,” by Guangming Pan, Lei Zhang, and Jianting Huang, CNOOC, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2-6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Polymerflooding has been considered a suitable method for reservoirs with viscosities up to 150 mPa·s. The authors of the complete paper verify that alternating injection of polymer and water in the Bohai Bay of China proved effective and economical for heavy oil fields, even offshore. This polymerflooding pilot of initially continuous, and then alternating, injection can provide a useful technical reference for similar reservoirs. Introduction Heavy oil reserves are abundant in the Bohai oil field of China. The development of the field has proved that the field with lower viscosity (less than 350 mPa·s) can be developed effectively by water-flooding, while the unconventional heavy oil reservoir with high viscosity has not formed a mature development mode. To better use interwell reserves, a pilot polymerflooding test has been conducted in the NN field since 2008. The cumulative production of nine wells in the surrounding area reached 10.80×104 m3, which confirmed that polymer fluid injection had a good displacement effect on unconventional high-viscosity crude oil. However, with the extension of continuous injection time, the pilot test area faced various problems. In order to explore the applicability of polymerflooding technology used in offshore unconventional heavy oil fields, the polymer-injection mode was studied on the basis of laboratory experimental data and field practice, and the polymer/water alternating injection mode was analyzed. Experimental Continuous Polymerflooding. Experimental Equipment and Materials. The experimental device is composed of a driving system, an experimental model, a pressure-measurement system, a produced-liquid-collection system, and a temperature-control system. According to the distribution of reservoir physical properties in the NN field, a parallel double-tube displacement experiment with a permeability ratio of 5 was designed. The experimental cores are artificial, with a tube length of 30 cm and an inner diameter of 2.54 cm. The low-permeability tube has 1624×10-3 µm2 permeability, and the high-permeability tube has 8488×10-3 µm2 permeability. The experimental temperature is 55°C, which is consistent with the formation temperature of the NN field. The polymer is partially hydrolyzed polyacrylamide. Experimental Procedure. The experimental process includes vacuum pumping, saturating formation water, obtaining core pore volume, saturating simulated oil, calculating oil saturation water drive to a specified water cut, continuously injecting polymer solution, and measuring data. The experimental injection rate is 0.2 mL/min, and the multiple of injected pore volumes (PV) is 0.6 PV. The NN field has weak edge water, and the water cut of the well group was 60 to 90% when polymerflooding was performed. Therefore, the design scheme mainly includes waterflooding and polymerflooding stages. The polymer- injection concentration was 3000 mg/L, and the injection mode is continuous, consistent with the field test.

Overcoming Challenges in ESP Operation in Ultradeepwater Heavy-Oil Atlanta Field

2021 ◽  
Vol 73 (03) ◽  
pp. 46-47
Author(s):  
Chris Carpenter
Keyword(s):  
Heavy Oil ◽  
Oil Field ◽  
Primary System ◽  
Artificial Lift ◽  
Short Period ◽  
Production History ◽  
Electrical Submersible Pump ◽  
Water Cut ◽  
Available Information ◽  
Offshore Oil

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201135, “Challenges in ESP Operation in Ultradeepwater Heavy-Oil Atlanta Field,” by Alexandre Tavares, Paulo Sérgio Rocha, SPE, and Marcelo Paulino Santos, Enauta, et al., prepared for the 2020 SPE Virtual Artificial Lift Conference and Exhibition - Americas, 10-12 November. The paper has not been peer reviewed. Atlanta is a post-salt offshore oil field in the Santos Basin, 185 km southeast of Rio de Janeiro. The combination of ultradeep water (1550 m) and heavy, viscous oil creates a challenging scenario for electrical submersible pump (ESP) applications. The complete paper discusses the performance of an ESP system using field data and software simulations. Introduction From initial screening to define the best artificial-lift method for the Atlanta Field’s requirements, options such as hydraulic pumps, hydraulic submersible pumps, multiphase pumps, ESPs, and gas lift (GL) were considered. Analysis determined that the best primary system was one using an in-well ESP with GL as backup. After an initial successful drillstem test (DST) with an in-well ESP, the decision was made, for the second DST, to install the test pump inside the riser, near seabed depth. It showed good results; comparison of oil-production potential between the pump installed inside a structure at the seabed—called an artificial lift skid (ALS)—and GL suggested that the latter would prove uneconomical. The artificial lift development concept is shown in Fig. 1. ESP Design ESP sizing was performed with a commercial software and considered available information on reservoir, completion, subsea, and topsides. To ensure that the ESP chosen would meet production and pressure boosts required in the field, base cases were built and analyzed for different moments of the field’s life. The cases considered different productivity indexes (PI), reservoir pressures, and water production [and consequently water cut (WC)] as their inputs. The design considers using pumps with a best efficiency point (BEP) for water set at high flow rates (17,500 B/D for in-well and 34,000 B/D for ALS). Thus, when the pumps deal with viscous fluid, the curve will have a BEP closer to the current operating point. Design boundaries of the in-well ESP and the ALS are provided in the complete paper, as are some of the operational requirements to be implemented in the ESP design to minimize risk. Field Production History In 2014, two wells were drilled, tested, and completed with in-well ESP as the primary artificial lift method. Because of delays in delivery of a floating production, storage, and offloading vessel (FPSO), the backup (ALS) was not installed until January 2018. In May 2018, Atlanta Field’s first oil was achieved through ATL-2’s in-well ESP. After a few hours operating through the in-well ESP, it prematurely failed, and the ALS of this well was successfully started up. Fifteen days after first oil, ATL-3’s in-well ESP was started up, but, as occurred with ATL-2, failed after a short period. Its ALS was successfully started up, and both wells produced slightly more than 1 year in that condition.

Indoor Study of Viscosity Reducer for Thickened Oil of Huancai

2012 ◽  
Vol 268-270 ◽  
pp. 547-550
Author(s):  
Qing Wang Liu ◽  
Xin Wang ◽  
Zhen Zhong Fan ◽  
Jiao Wang ◽  
Rui Gao ◽  
...  
Keyword(s):  
Interfacial Tension ◽  
Oil Recovery ◽  
Heavy Oil ◽  
High Viscosity ◽  
Oil Field ◽  
Viscosity Reduction ◽  
Oil Viscosity ◽  
Low Viscosity ◽  
Viscosity Reducer ◽  
Oil Water

Liaohe oil field block 58 for Huancai, the efficiency of production of thickened oil is low, and the efficiency of displacement is worse, likely to cause other issues. Researching and developing an type of Heavy Oil Viscosity Reducer for exploiting. The high viscosity of W/O emulsion changed into low viscosity O/W emulsion to facilitate recovery, enhanced oil recovery. Through the experiment determine the viscosity properties of Heavy Oil Viscosity Reducer. The oil/water interfacial tension is lower than 0.0031mN•m-1, salt-resisting is good. The efficiency of viscosity reduction is higher than 90%, and also good at 180°C.

Barrow Island enhanced oil recovery polymer pilot—part two: progress and way forward

2011 ◽  
Vol 51 (2) ◽  
pp. 672
Author(s):  
Daniel León ◽  
John Scott ◽  
Steven Saul ◽  
Lina Hartanto ◽  
Shannon Gardner ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Injection Pressure ◽  
Fracture Network ◽  
Oil Field ◽  
High Porosity ◽  
Polymer Injection ◽  
Fine Grained ◽  
Successful Design ◽  
Fit For Purpose ◽  
Water Cut

After successful design and implementation phases that included both subsurface and facilities components, an EOR polymer injection pilot has been operational for two years in Australia's largest onshore oil field at Barrow Island (816 MMstb OOIP). The pilot's main objective was to identify a suitable EOR technology for the complex, highly heterogeneous, very fine-grained, bioturbated argillaceous sandstone—high in glauconite, high porosity (∼23 %), low permeability (∼5 mD, with 50+ mD streaks)—reservoir that will ultimately increase the recovery of commercial resources past the estimated ultimate recovery factor with waterflooding (∼42 %). This was achieved using the in-depth flow diversion (IFD) methodology to access new unswept oil zones—both vertically and horizontally—by inducing growth in the fracture network. During the pilot operating phase, the main focus has been on surveillance and monitoring activities to assess the effectiveness of the process, including: injection pressure at the wellheads—indicating any increase in resistance to flow; pressure fall off tests at the injectors—to determine fracture growth, if any sampling and lab analysis at the producers—to identify polymer breakthrough; frequent production tests—quantifying reduction in water cut and oil production uplift; and, pressure build up surveys at the producers. These activities provided input data to the fit for purpose simulation model built in Reveal incorporating fractures and polymer as a fourth phase. With more than 96 % compliance to the surveillance plan, this paper will present the present findings and evaluation of the results, which may lead to the continuation of the pilot in other patterns of the reservoir and, possibly, to further expansion in the field.

Key Aspects of Project Design for Polymer Flooding at the Daqing Oilfield

2008 ◽  
Vol 11 (06) ◽  
pp. 1117-1124 ◽  
Author(s):  
Dongmei Wang ◽  
Randall S. Seright ◽  
Zhenbo Shao ◽  
Jinmei Wang
Keyword(s):  
Molecular Weight ◽  
Polymer Concentration ◽  
Oil Production ◽  
Polymer Flooding ◽  
Oil Field ◽  
Polymer Injection ◽  
Polymer Flood ◽  
Daqing Oil Field ◽  
Water Cut ◽  
Injection Rates

Summary This paper describes the design procedures that led to favorable incremental oil production and reduced water production during 12 years of successful polymer flooding in the Daqing oil field. Special emphasis is placed on some new design factors that were found to be important on the basis of extensive experience with polymer flooding. These factors include (1) recognizing when profile modification is needed before polymer injection and when zone isolation is of value during polymer injection, (2) establishing the optimum polymer formulations and injection rates, and (3) time-dependent variation of the molecular weight of the polymer used in the injected slugs. For some Daqing wells, oil recovery can be enhanced by 2 to 4% of original oil in place (OOIP) with profile modification before polymer injection. For some Daqing wells with significant permeability differential between layers and no crossflow, injecting polymer solutions separately into different layers improved flow profiles, reservoir sweep efficiency, and injection rates, and it reduced the water cut in production wells. Experience over time revealed that larger polymer-bank sizes are preferred. Bank sizes grew from 240-380 mg/L·PV during the initial pilots to 640 to 700 mg/L·PV in the most recent large-scale industrial sites [pore volume (PV)]. Economics and injectivity behavior can favor changing the polymer molecular weight and polymer concentration during the course of injecting the polymer slug. Polymers with molecular weights from 12 to 35 million Daltons were designed and supplied to meet the requirements for different reservoir geological conditions. The optimum polymer-injection volume varied around 0.7 PV, depending on the water cut in the different flooding units. The average polymer concentration was designed approximately 1000 mg/L, but for an individual injection station, it could be 2000 mg/L or more. At Daqing, the injection rates should be less than 0.14-0.20 PV/year, depending on well spacing. Introduction Many elements have long been recognized as important during the design of a polymer flood (Li and Niu 2002; Jewett and Schurz 1970; Sorbie 1991; Vela et al. 1976; Taber et al. 1997; Maitin 1992; Koning et al. 1988; Wang et al. 1995; Wang and Qian 2002; Wang et al. 2008). This paper spells out some of those elements, using examples from the Daqing oil field. The Daqing oil field is located in northeast China and is a large river-delta/lacustrine-facies, multilayer, heterogeneous sandstone in an inland basin. The reservoir is buried at a depth of approximately 1000 m, with a temperature of 45°C. The main formation under polymer flood (i.e., the Saertu formation) has a net thickness ranging from from 2.3 to 11.6 m with an average of 6.1 m. The average air permeability is 1.1 µm2, and the Dykstra-Parsons permeability coefficient averages 0.7. Oil viscosity at reservoir temperature averages approximately 9 mPa·s, and the total salinity of the formation water varies from 3000 to 7000 mg/L. The field was discovered in 1959, and a waterflood was initiated in 1960. The world's largest polymer flood was implemented at Daqing, beginning in December 1995. By 2007, 22.3% of total production from the Daqing oil field was attributed to polymer flooding. Polymer flooding should boost the ultimate recovery for the field to more than 50% OOIP--10 to 12% OOIP more than from waterflooding. At the end of 2007, oil production from polymer flooding at the Daqing oil field was more than 11.6 million m3 (73 million bbl) per year (sustained for 6 years). The polymers used at Daqing are high-molecular-weight partially hydrolyzed polyacrylamides (HPAMs). During design of a polymer flood, critical reservoir factors that traditionally receive consideration are the reservoir lithology, stratigraphy, important heterogeneities (such as fractures), distribution of remaining oil, well pattern, and well distance. Critical polymer properties include cost-effectiveness (e.g., cost per unit of viscosity), resistance to degradation (mechanical or shear, oxidative, thermal, microbial), tolerance of reservoir salinity and hardness, retention by rock, inaccessible pore volume, permeability dependence of performance, rheology, and compatibility with other chemicals that might be used. Issues long recognized as important for polymer-bank design include bank size (volume), polymer concentration and salinity (affecting bank viscosity and mobility), and whether (and how) to grade polymer concentrations in the chase water. This paper describes the design procedures that led to favorable incremental oil production and reduced water production during 12 years of successful polymer flooding in the Daqing oil field.

scholarly journals Two-Stage Geothermal Well Clustering for Oil-to-Water Conversion on Mature Oil Fields

Geosciences ◽  
2021 ◽  
Vol 11 (11) ◽  
pp. 470
Author(s):  
Josipa Hranić ◽  
Sara Raos ◽  
Eric Leoutre ◽  
Ivan Rajšl
Keyword(s):  
Spatial Arrangement ◽  
Oil Wells ◽  
Oil Field ◽  
Oil Fields ◽  
Two Stage ◽  
Oil Companies ◽  
Geothermal Potential ◽  
Clustering Approach ◽  
Water Cut

There are numerous oil fields that are approaching the end of their lifetime and that have great geothermal potential considering temperature and water cut. On the other hand, the oil industry is facing challenges due to increasingly stringent environmental regulations. An example of this is the case of France where oil extraction will be forbidden starting from the year 2035. Therefore, some oil companies are considering switching from the oil business to investing in geothermal projects conducted on existing oil wells. The proposed methodology and developed conversions present the evaluation of existing geothermal potentials for each oil field in terms of water temperature and flow rate. An additional important aspect is also the spatial distribution of existing oil wells related to the specific oil field. This paper proposes a two-stage clustering approach for grouping similar wells in terms of their temperature properties. Once grouped on a temperature basis, these clusters should be clustered once more with respect to their spatial arrangement in order to optimize the location of production facilities. The outputs regarding production quantities and economic and environmental aspects will provide insight into the optimal scenario for oil-to-water conversion. The scenarios differ in terms of produced energy and technology used. A case study has been developed where the comparison of overall fields and clustered fields is shown, together with the formed scenarios that can further determine the possible conversion of petroleum assets to a geothermal assets.

Polymer-Flooding-Pilot Learning Curve: Five-Plus Years' Experience To Reduce Cost per Incremental Barrel of Oil

2014 ◽  
Vol 18 (01) ◽  
pp. 11-19 ◽  
Author(s):  
J.. Buciak ◽  
G.. Fondevila Sancet ◽  
L.. Del Pozo
Keyword(s):  
Learning Curve ◽  
Produced Water ◽  
Water Injection ◽  
Oil Production ◽  
Polymer Flooding ◽  
Oil Field ◽  
High Porosity ◽  
Polymer Injection ◽  
Injection Pump ◽  
Water Cut

Summary This paper deals with the learning curve of a five-plus-year polymer-flooding pilot conducted in a mature waterflood that includes, for example, several works related to injector and producer wells and reservoir management. The scope of this paper is to describe the learning curve during the last 5 years rather than the reservoir response of the polymer-flooding technique; focus is on the aspects related to reduce cost per incremental barrel of oil for a possible extension to other waterflooded areas of the field. Diadema oil field is in the San Jorge Gulf basin in the southern portion of Argentina. The field is operated by CAPSA, an Argentinean oil-producer company; it has 480 producer and 270 injector wells (interwell spacing is 250 m on average). The company has developed waterflooding over more than 18 years (today, this technique represents 82% of oil production in the field) and produces approximately 1600 m3/d of oil and 40 000 m3/d of gross production (96% water cut) with 38 400 m3/d of water injection. The reservoir that is polymer-flooded is characterized by high permeability (average of 500 md), high heterogeneity (10 to 5,000 md), high porosity (30%), very stratified sandstone layers (4 to 12 m of net thickness) with poor lateral continuity (fluvial origin), and 20 °API oil (100 cp at reservoir conditions). Diadema's polymer-flooding pilot started in October 2007 on five water injectors (it includes 13 injectors today) with an injected rate of 1000 m3/d (today, 2000 m3/d). Polymer solution is made with produced water (15,000 ppm brine) and 1,500 ppm of hydrolyzed polyacrylamide polymer reaching 15- to 20-cp fluid-injection viscosity. Oil-production rate from the original “central” producers (wells that are aided with 100% of polymer injection) has increased 100% at the same time as average reduction in water cut is approximately 15%. The main aspects presented in this work are depth profile modification with crosslinked gel injected along with polymer, use of “curlers” to regulate injection in multiple wells with one injection pump without shearing the polymer, and an improved technology on producer wells with progressing-cavity pumps to decrease shut-in time and number of pump failures. The plan for the future is to extend this project to other areas with the acquired knowledge and to improve different aspects, such as water quality and optimization of polymer plant operation. These improvements will allow the company to reduce operating costs per incremental barrel of oil.

Design and Execution of the First Large-Scale Polymer Injection Pilot in Sirikit Oil Field

2021 ◽  
Author(s):  
Weeraya Wuttipittayamongkol ◽  
Pannapon Trinavarat ◽  
Warisa Nuntaprayoon ◽  
Monrawee Pancharoen ◽  
Rapheephan Laochamroonvorapongse
Keyword(s):  
Large Scale ◽  
Oil Field ◽  
Production Performance ◽  
Water Flooding ◽  
Small Scale ◽  
Mechanical Degradation ◽  
Close Monitoring ◽  
Polymer Injection ◽  
Fluid Saturation ◽  
Water Cut

Abstract Becoming more mature with field-wide water flooding implementation for more than 30 years, Sirikit Oil Field (S1) is going forward to the next rejuvenating step of enhanced oil recovery (EOR). Generally, the field contains light oil (40° API) in highly stratified sand-shale sequences with low net-to-gross ratios. High reservoir temperature, low permeability, and high water cut observed from production make it even more challenging for polymer injection projects. Nonetheless, the success from a small-scale field trial has shown a promising future of EOR application in the field and brought an execution of the first large-scale polymer injection pilot. Polymer screening laboratory tests, a reservoir simulation study, data acquisition program and techniques, injectivity tests, polymer injection unit design, and risk assessment were parts of the pilot preparation, in which the key learnings from the previous pilot have been incorporated. The gathering and determination of baseline parameters including production performance, injection profiles, reservoir fluid saturation profiles, etc., were registered for ultimate evaluation. Then, the continuous polymer injection has been started since October 2019 in two separated fault blocks where 12 injectors and 20 producers are located in different injection patterns. During several months of polymer injection, both foreseen and unforeseen changes have enlivened the pilot management. Although the injectivity test with polymer solution prior to the pilot demonstrated no injection difficulty, several wells have shown injectivity deterioration with time. Mechanical degradation is induced in these wells by the installation of flow restriction devices to lessen solution viscosity and, hence, prolong polymer injectivity. Well integrity issues and artificial lift breakdown negatively affect field production and close-in wells make it harder for voidage replacement control. Immediate troubleshooting and close monitoring have been placed and eventually leads to the recognition of encouraging results. Polymer helps improve vertical injection profiles as seen from injection logging. Saturation logging presents a sign of oil saturation decrease around the wellbore area. Reduction of water cut and rise of oil production have pleasantly come after a few months from the start. Intensive surveillance program will be continued over the course of pilot injection. The critical success of the EOR pilot execution depends on the detailed planning, prudent surveillance and comprehensive evaluation. Sirikit oil field is moving to a turning point and the pilot outcome would lead the way to a further milestone, so as to avoid premature end of the field's production.

Challenges, Opportunities and Threats of Deep Bottoms-Up Water Injection in Heavy Oil Reservoir: Lessons Learnt from the G Field, South Oman

2021 ◽  
Author(s):  
Chaitanya Behera ◽  
Sandip Mahajan ◽  
Carlos Annia ◽  
Mahmood Harthi ◽  
Jane-Frances Obilaja ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Water Injection ◽  
Field Performance ◽  
Oil Field ◽  
Oil Fields ◽  
Reservoir Pressure ◽  
Light Oil ◽  
Alternative Water ◽  
Variable Water

Abstract This paper presents the results of a comprehensive study carried out to improve the understanding of deep bottom-up water injection, which enabled optimizing the recovery of a heavy oil field in South Oman. Understanding the variable water injection response and the scale of impact on oil recovery due to reservoir heterogeneity, operating reservoir pressure and liquid offtake management are the main challenges of deep bottoms-up water injection in heavy oil fields. The offtake and throughput management philosophy for heavy oil waterflood is not same as classical light oil. Due to unclear understanding of water injection response, sometimes the operators are tempted to implement alternative water injection trials leading to increase in the risk of losing reserves and unwarranted CAPEX sink. There are several examples of waterflood in heavy oil fields; however, very few examples of deep bottom water injection cases are available globally. The field G is one of the large heavy oil fields in South Oman; the oil viscosity varies between 250cp to 1500cp. The field came on-stream in 1989, but bottoms-up water-injection started in 2015, mainly to supplement the aquifer influx after 40% decline of reservoir pressure. After three years of water injection, the field liquid production was substantially lower than predicted, which implied risk on the incremental reserves. Alternative water injection concepts were tested by implementing multiple water injection trials apprehending the effectiveness of the bottoms-up water injection concept. A comprehensive integrated study including update of geocellular model, full field dynamic simulation, produced water re-injection (PWRI) model and conventional field performance analysis was undertaken for optimizing the field recovery. The Root Cause Analysis (RCA) revealed many reasons for suboptimal field performance including water injection management, productivity impairment due to near wellbore damage, well completion issues, and more importantly the variable water injection response in the field. The dynamic simulation study indicated negligible oil bank development due to frontal displacement and no water cut reversal as initial response to the water injection. Nevertheless, the significance of operating reservoir pressure, liquid offtake and throughput management impact on oil recovery cann't be precluded. The work concludes that the well reservoir management (WRM) strategy for heavy oil field is not same as the classical light oil waterflood. Nevertheless, the reservoir heterogeneity, oil column thickness and saturation history are also important influencing factors for variable water injection response in heavy oil field.

Study on Variation Regular Pattern of Development Indexes in Beierdong Block after Layer Recombination

2012 ◽  
Vol 594-597 ◽  
pp. 2475-2480
Author(s):  
Gui Xue Qi ◽  
Hai Xia Zhang ◽  
Mian Long ◽  
Jun Qin ◽  
Ji Cheng Zhang
Keyword(s):  
Simulation Method ◽  
High Water ◽  
Oil Field ◽  
Oil Fields ◽  
Regular Pattern ◽  
Output Stage ◽  
Dynamic Regulation ◽  
Stratigraphic Position ◽  
High Water Cut ◽  
Water Cut

Nowadays, in China nearly all the produced oil-fields have already entered the period of high water cut, and the six oil-fields of Daqing and Shengli oil-field etc. have exceeded eighty percent water cut. Beierdong Block has produced for nearly fifty years, and now it has entered into the descending output stage and its water cut has reached more than ninety percent. With oil field infill gradually in Beierdong Block, each series of well network production target getting worse gradually, intersecting with old well network stratigraphic position, and polymer flooding well network use part of water driving old well, making the contradictory of layer well network concatenate and dynamic regulation intensely. Especially as the block of infill adjustment proceeded earliest, acquired better developed effect at the beginning of regulation, but with the deep development of the field, after the phase of extra high water cut, exposed gradually some problems such as the perforating interval is too long, the contradiction of interlamination is obvious, the high water cut of multilayer is serious, bringing huge difficulty to dynamic analysis regulation.Basing on layer recombination and using the reservoir simulation method, the paper studied the distribution of remaining oil, forecast variation regular pattern of development indexes. By contrasting these indexes, the paper estimates the effect of layer recombination. It has important significance for the next period’s development.

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