Remaining Oil Potential Research Articles

Infill Well Location Optimization Method Based on Recoverable Potential Evaluation of Remaining Oil

Infill well location optimization poses significant challenges due to its complexity and time-consuming nature. Currently, determining the scope of infill wells relies heavily on field engineers’ experience, often using single indices such as the remaining oil saturation or abundance of remaining oil reserves to evaluate the potential of remaining oil. However, this approach lacks effectiveness in guiding the precise tapping of remaining oil in ultra-high water cut reservoirs. To address this, our study comprehensively considers the factors influencing the recoverable potential of remaining oil in such reservoirs. We characterize the differences in reservoir heterogeneity, scale of recoverable remaining oil reserves, water flooding conditions, and oil–water flow capacity to construct a quantitative evaluation index system for the recoverable potential of remaining oil. Recognizing the varying degrees of influence of different indices on the recoverable potential of remaining oil, we determine the objective weight of each evaluation index by combining an accelerated genetic algorithm with the projection pursuit model. This approach enables the construction of a recoverable potential index for remaining oil and forms a quantitative evaluation method for the recoverable potential of remaining oil in ultra-high water cut reservoirs. Subsequently, we establish a mathematical model for infill well location optimization, integrating and optimizing the infill well location coordinates, well length, well inclination angle, and azimuth angle. Using the main layer sand body of an oilfield in Bohai as a case study, we conducted evaluations of the remaining oil potential and infill well location optimization. Our results demonstrate that the assessment of the remaining oil potential comprehensively characterizes the influence of the reservoir’s physical properties and oil–water diversion capacity on the remaining oil potential across different regional positions. This evaluation can effectively guide the determination of infill well location ranges based on the evaluation results. Furthermore, infill well location optimization can effectively enhance reservoir development outcomes.

Remaining oil potential and adjustment countermeasures in fault X well area of Lamadian Oilfield

The distribution characteristics of remaining oil in fault well area X of Lamadian oilfield are studied by numerical simulation, and adjustment countermeasures are formulated. Through the establishment of numerical model, the geological reserves and residual reserves of each small layer are analyzed, and the oil saturation distribution diagram output by the model is calculated, and the distribution characteristics of different types of remaining oil are summarized. The results are as follows :(1) the residual reserves are mainly distributed in the channel, accounting for 57.0 % of the total residual reserves, followed by the main sheet sand; (2) The remaining oil is mainly affected by imperfect injection-production relationship, fault occlusion and plane interference, accounting for 95 % of the total reserves of the type. Imperfect injection-production relationship accounted for 73.58 % of remaining oil types. The second is the enrichment of remaining oil from plane disturbance, accounting for 12.3 %. Residual oil of fault occlusion accounted for 9.16 %. The optimal well spacing was 200m, and the final recovery was 2.84 % higher than the original well pattern.

Vector well pattern optimization of horizontal well in offshore edge water reservoirs

The L30up reservoir is a strongly heterogeneous edge water reservoir with obvious provenance direction and channel direction. It is developed by horizontal wells, and the traditional well pattern adjustment is not suitable for tapping the remaining oil potential of this type of reservoirs, while vector well pattern adjustment is one of the important measures to enhance oil recovery. In this paper, aiming at maximizing the economic net present value, taking the characteristic parameter matrix of well pattern reconfiguration (well position, azimuth angle, horizontal section length) as variables, an optimization model of horizontal well pattern vector adjustment is established. Furthermore, the PSO-MADS algorithm is proposed to solve the above optimization model. Thus, a vector well pattern adjustment technology that can realize the distribution matching of reservoir heterogeneity and remaining oil has been formed. On the basis of the deployment strategy of vector well pattern in L30up reservoir, according to the direction of sediment source, reservoir heterogeneity, distribution of remaining oil, etc., we determined the best vector well pattern adjustment scheme, and applied the above optimization method to optimize the infill well locations. Through the optimal deployment of the vector well pattern, the oil recovery factor after the vector well pattern adjustment is 5.21% percentage points higher than the original well pattern conditions, which precisely matches the well pattern parameters and the geological vector parameters, such as sand body distribution, remaining oil distribution, and edge waters in L30up reservoir.

The influence of permeability and heterogeneity on chemical flooding efficiency and remaining oil distribution—based on NMR displacement imaging

To investigate the impact of permeability and heterogeneity on oil displacement efficiency and remaining oil distribution of chemical flooding, three groups of high and ultrahigh permeability core samples from an ultrahigh water-cut oilfield in western China were selected as the research objects in this study. High-pressure mercury injection, scanning electron microscopy, wettability test, and other methods were used to characterize the reservoir properties of core samples. Six groups of experiments were performed using the nuclear magnetic resonance (NMR) displacement imaging technology to simulate the oilfield development process considering the economic benefits. The displacement stage with the best oil displacement effect in the process of waterflooding, chemical flooding and then waterflooding was defined, and the control effect of permeability and heterogeneity on the improvement of oil displacement efficiency by polymer-surfactant binary flooding was discussed. The distribution position of remaining oil in different displacement stages was quantitatively and visually displayed, and its control factors were revealed. The research shows that during the simulation process of first waterflooding followed by chemical flooding and then waterflooding in the oilfield, the T2 spectrum signal amplitude increases the most in the two stages, one is from saturated oil flooding to 50% water cut and the other one is from 95% water cut to the end of 1 PV polymer flooding. The oil displacement efficiency increases the most, and the oil is primarily discharged from pore throats larger than 90 ms (or with pore throat radius of 8.37 μm). Compared with heterogeneity, permeability plays a more obvious controlling role in improving the oil displacement efficiency of polymer-surfactant binary flooding. The influence of fingering phenomenon on the distribution of remaining oil is most obvious in the second waterflooding, and the distribution of remaining oil with polymer slug is more obviously affected by the fingering phenomenon than that with polymer-surfactant slug. The study results provide theoretical guidance for tapping the remaining oil potential of old oilfields with high to ultrahigh permeabilities.

Study on Class 3 reservoirs infill adjustment methods

The exploitation object of the Class 3 reservoirs of infill adjustment well pattern is SaPu thin and poor oil reservoir and Gaotaizi oil reservoir. The remaining oil potential of thin and poor oil reservoir and untabulated reservoir is brought into full play to the maximum extent, which is the focus of this infill adjustment. Therefore, it is necessary to carry out effective research on the formulation of mining plan, the dynamic change law of new and old wells from plane connection to vertical sedimentary units, and the tracking and adjustment of surrounding wells. First, according to the change law of sand body control degree in different oil layers and different well spacing, combined with the remaining oil distribution characteristics of Class 3 reservoirs of Sapugao oil layers, the well pattern and well spacing are optimized. The second is to study the complex well pattern, well location relationship and its matching adjustment timing. Through the structural adjustment of the infill well pattern of the Class 3 reservoirs in plane and vertical combination, A set of adjustment and tapping technology of the infill well area of the Class 3 reservoirs is formed, which gives full play to the remaining oil potential. Compared with the expected single well daily oil production of the typical region increases by 1.2t, water cut decreases by 2.8 percentage points, and the natural decline is - 10.22%. The research results of this innovative well pattern infill combination method and potential tapping method of matching adjustment have certain reference significance for guiding the adjustment and potential tapping of infill well area of Class 3 reservoirs in water drive.

Study of Fine Management Mode on Improving Potential Benefits of Measures

The oil field has entered the extra high water cut period, the oil well fracturing and oil increment have made great contributions to the fine tapping potential of water flooding. At the same time, the oil well fracturing and oil increment production has become an important part of the stable production of water flooding. Therefore, the fine oil well fracturing management mode and the improvement of oil well fracturing and oil increment effect are particularly important. Focus from the advance potential survey, the implementation of pre-pressure training; fine well selection and layer selection, optimize fracturing design ; strengthen process management, strengthen construction supervision; do well after fracturing management, improve oil increment effect to fine oil well fracturing management mode. The comprehensive application of various technical means to continuously improve the accuracy of residual oil analysis is the basis to ensure the targeted fracturing measures; on the basis of the analysis of remaining oil, it is the prerequisite and necessary guarantee to improve the fracturing effect and prolong the effective period to do well in the preinjection and post-injection recharge. The key to improve the fracturing effect of oil well is to combine the remaining oil potential and fracturing technology closely, design personalized scheme, refine the fracturing interval and expand the construction scale. Doing well in fracturing process management and refining each construction link is an effective guarantee to maximize the benefits of measures. On measures to tap potential, deepen potential research, optimize program design, give full play to the synergistic effect of measures, and strive to improve the pertinence of measures to tap potential in ultra-high water cut period, continuously improve the fracturing effect, improve the benefits of measures to tap potential, and achieve the goal of ' high efficiency, sustainable and guaranteed’ sustainable and stable production.

Scalar and Vector Evaluation Methods for Remaining Oil Potential of Water-Driven Reservoirs

Scalar and Vector Evaluation Methods for Remaining Oil Potential of Water-Driven Reservoirs

The Application of Fuzzy Comprehensive Evaluation Method in Evaluating Remaining Oil Potential of Oil Layer

In this paper, remaining oil saturation, microfacies type, oil layer thickness, structure, permeability variation coefficient, injection-production relationship, injection-production perfection degree, effective perforation thickness, connected thickness, water injection distance, water injection well pattern, water cut of oil well and production measures, these thirteen static and production dynamic indicators constitute the evaluation factor set of remaining oil potential, hierarchy and statistical analysis of weight coefficients are carried out for each factor, taking block A as an example, the multi-level fuzzy comprehensive evaluation method is used to quantitatively evaluate the remaining oil potential of complex heterogeneous reservoir, so as to achieve the purpose of regional governance in accordance with size of remaining oil potential.

The technology of effective reservoir prediction in fault development zone

Reservoir prediction in the middle and late stages of development is not only to predict the sandstone, but also to define the specific location of Petroleum-bearing sandstone. The post-stack seismic data is superimposed on a multi-channel seismic data level, although the signal-to-noise ratio is improved to a certain extent, the average amplitude value is obtained in the superposition process, so that only the effective prediction of the sand body can be realized. However, the pre-stack seismic data can obtain the information of shear wave by the longitudinal wave. The characteristics of the shear wave that cannot propagate in the fluid can effectively predict the reservoir and fluid distribution. In order to further quantify the remaining oil potential in fault area, prestack seismic inversion technology and petrophysical analysis are used to determine the favorable oil-bearing area. On this basis, prestack geostatistical inversion is completed to further clarify sand body with high oil saturation. Combined with numerical simulation, it effectively predicts the residual oil distribution at the edge of fault and the precision of the remaining oil quantitative characterization results is high. The recognition rate of thick layer saturation is more than 90%, and the recognition rate of thin interlayer saturation is more than 70%, which can meet the demand of fine reservoir prediction.

Study on potential and distribution of remaining oil after polymer flooding in XX Oilfield

XX oilfield has been put into polymer flooding development for 24 years, with cumulative oil production reaching XX million tons. Since 2005, the first-class reservoirs of early polymer flooding have been transferred to subsequent water flooding. After long-term water flooding, polymer flooding and subsequent water flooding, these reservoirs are in the development stage of “double extra high”, with high reservoir production degree, serious ineffective circulation and highly dispersed remaining oil, which makes it difficult to further tap potential. Therefore, the remaining oil potential and distribution law are studied in the first class oil layer in XX area of oilfield, which provides geological basis for further development and adjustment of EOR.

Analytical Work Flows Enable Continuous Waterflooding Optimization for a Mature Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 198586, “A New Continuous Waterflood Operations Optimization for a Mature Oil Field by Use of Analytical Work Flows That Improve Reservoir Characterization,” by Atul Yadav and Anton Malkov, SPE, Wintershall, and Essam Omara, Suez Oil Company, et al., prepared for the 2019 SPE Gas and Oil Technology Showcase and Conference, Dubai, 21–23 October. The paper has not been peer reviewed. In the complete paper, the authors present a novel approach that uses data-mining techniques on operations data of a complex mature oil field in the Gulf of Suez that is currently being waterflooded. Evidence is presented about how salinity data can be used to further justify the linkages between different wells obtained from cross-correlation analysis. The results presented in this research can be adapted to any waterflooded field to optimize recovery at frequent intervals where injection and production data are available continuously. Introduction Mature oil fields typically present challenges of increased water production and water handling. Considering the geological complexity and associated field-performance behavior, reservoir characterization to optimize water flooding is a major challenge. An integrated reservoir study was con ducted to minimize reservoir uncertainties and increase understanding of the field’s performance behavior. The acceptable history-matched model was used to estimate remaining oil potential, maintain and increase current production levels, and optimize the water-injection rate. Generally, history-matched models need to be updated throughout the life of producing fields as new subsurface data are acquired. Such integrated reservoir modeling studies, however, can be time-consuming and do not necessarily enable quicker decision-making around operational activities. The continuous recording of production and injection data presents new opportunities to apply novel analytical techniques to understand interwell connectivity in the reservoir. The current ability to store and analyze data, coupled with advances in the ability to interpret big data sets, has helped create an independent toolkit that provides analysis without the geological model. In addition, geological information such as pre-existing faults and the commingled or disconnected nature of production between different layers can be integrated to obtain and improve analyses from the analytical models. The authors analyze the results using Pearson’s cross-correlation analysis measure to obtain a qualitative analysis of the field. They also apply Spearman’s rank correlation analysis for the discussed field (henceforth named GOS for purposes of this paper) that helps compare injection and production data. The objective is to present a comparison between the analytical and the stream-lined approach to show consistency in reservoir characterization. The effective injector/producer pairs identified form an important component of the field development.

Effects of oil viscosity on waterflooding: A case study of high water-cut sandstone oilfield in Kazakhstan

AbstractAfter a sandstone oilfield enters the high water-cut period, the viscosity of crude oil has an important influence on remaining oil distribution and waterflooding characteristics under the same factors of, e.g., reservoir quality and development methods. Based on a comprehensive interpretation of the waterflooded layers in new oil wells, physical simulation experiments, and reservoir numerical simulations, we analyzed the waterflooding laws of a high water-cut sandstone reservoir with different oil viscosities in Kazakhstan under the same oil production speed, and we clarified the remaining oil potential of reservoirs with different viscosities and proposed corresponding development measures. The results show that low-viscosity oil reservoirs (1 mPa s) have uniform waterflooding, thick streamlines, small waterflooding areas, and low overall waterflooding degrees because of their homogeneous oil–water viscosities. However, within waterflooded areas, the reservoirs have high oil displacement efficiencies and high waterflooding degrees, and the remaining oil is mainly concentrated in the unwaterflooded areas; therefore, the initial production and water cut in new oil wells vary significantly. High-viscosity oil reservoirs (200 mPa s) have severe waterflooding fingering, large waterflooding areas, and high overall waterflooded degrees because of their high oil–water mobility ratios. However, within waterflooded areas, the reservoirs have low oil displacement efficiencies and low waterflooding degrees, and the remaining oil is mainly concentrated in both the waterflooded areas and the unwaterflooded areas; therefore, the differences in the initial production and water cut of new oil wells are small. Moderate-viscosity oil reservoirs (20 mPa s) are characterized by remaining oil distributions that are somewhere in between those of the former two reservoirs. Therefore, in the high water-cut period, as the viscosity of crude oil increases, the efficiency of waterflooding gradually deteriorates and the remaining oil potential increases. In the later development, it is suggested to implement the local well pattern thickening in the remaining oil enrichment area for reservoirs with low viscosity, whereas a gradual overall well pattern thickening strategy is recommended for whole reservoirs with moderate and high viscosity. The findings of this study can aid better understanding of waterflooding law and the remaining oil potential of reservoirs with different viscosities and proposed corresponding development measures. The research results have important guidance and reference significance for the secondary development of high water-cut sandstone oilfields.

Analysis of the index change laws of the B and C strips of Block A after well pattern infilling

After entering the ultra-high water cut stage, it is more and more difficult to tap the remaining oil potential, especially in the B and C strips because of the prominent contradictions between injection and production. It is difficult to adjust a injection well and get a good effect of well stimulation, so oil recovery is low. The index change laws are analyzed and summarized in two test areas of well pattern infilling, which can be used as a reference for the well pattern infilling and efficient development in the B and C strips.

Study on the relationship between internal heterogeneity of single sand body and remaining oil distribution in Pubei Oil Field

According to the distribution characteristics of remaining oil in narrow thin sandstone reservoir of Pubei oilfield, the influence parameters such as sedimentary microfacies, structural morphology, effective thickness, rhythm, superposition relation, permeability and variation coefficient are selected, the relationship between Heterogeneous Composite Index and remaining oil distribution is studied by using analytic hierarchy process (AHP). The results show that the area where the heterogeneity index is larger is the main enrichment area of remaining oil. Based on the characteristics of injection and production of single sand body, the cause of remaining oil and the distribution of remaining oil potential, 6 sets of typical well groups and 19 kinds of single sand body injection and production potential countermeasures are optimized to provide a strong basis for fine injection and production of single sand body.

Eromanga oil traps – a multi field post-mortem

SummaryThe purpose of this paper is to examine the remaining oil potential of the Eromanga Basin, specifically in the Cooper region.The key factor is the timing of dominant oil charge. If the oil moved after the late compression and anticlinal structures are critical for commercial success, then the potential is low since almost all these features have been identified and drilled. If the oil moved before the late structuring then except for a few mappable paleostructures, the oil must have been trapped stratigraphically. The late structuring role would then tilt or remobilize the oil locally. If this is the case, then the large unexplored areas of the basin with little or no late structure are just as prospective as the explored structural areas. Additionally, even the discovered oil fields may not be fully appraised as the stratigraphic variability in reservoir has not been fully accounted for.The examination method chosen was to map and postmortem a semi-regional 9000 sq km area with 6 anticlines with numerous oil fields, near successes and dry holes. The area also has extensive 3D seismic.It was found that a strong case could be made that all the oil discoveries were stratigraphically trapped and the late structure only rearranged some of the already trapped oil.This conclusion not only upgrades the future exploration potential of the Basin but points the way to a fundamentally different way of mapping and high grading prospects.

The research and application of compound flooding system in the block L of Huabei oilfield

In the three rounds of gel flooding of the block L in Huabei oilfield, better effect of watercut decreasing and oil increasing had been achieved. In order to further develop the remaining oil potential, an oil-displacement slug was added on the basis of the gel slug, to form a compound flooding system in order to improve the oil displacement efficiency. Two types of oil displacement agents were optimized through basic performance evaluation. NO.I is surfactant. When the concentration was 0.3 percent, the oil-water interfacial tension could reach 1.15 ×10−3mn/m and still remain within the ultra-low interfacial tension range after 150 days under formation temperature but the static adsorption loss was only 3.4mg/g. NO.II is a kind of granular oil displacement agent with certain sealing ability.The initial particle size was 189nm and the size reached 520nm after hydration for 30 days and remained stable. In the sand filled tube with a permeability of 550×10−3μm2, the plugging rate was up to 70.88 percent. Through the double tube with high-low permeability core experiments, the oil displacement effect of movable gel, movable gel with oil displacement agent I and movable gel with oil displacement agent II were further compared. The results showed that movable gel with oil displacement agent II could improve oil recovery by 20.95 percent compared with water flooding, 7.88 percent compared with movable gel and 5.92 percent compared with movable gel with oil displacement agent I.The composite flooding system was applied in the block L with 6 wells and the effect of watercut decreasing and oil increasing was significant. The daily oil increase in peak period was 10t, and the watercut was decreased by 5.3 percent. The accumulative oil increase was 2736 tons with 13 months validity and will continue to be effective.

Local natural resources and crime: Evidence from oil price fluctuations in Texas

We exploit plausibly exogenous changes in the value of reserves in Texas's giant oil fields to determine the impact of crime in Texas counties that have reserves. Texas provides an ideal setting for this research strategy. First, Texas has the largest number of giant oil fields. Second, Texas's giant oil fields possess the greatest remaining oil potential. Third, giant oil fields are dispersed throughout the state. We find that a 1% increase in the value of oil reserves increases murder by 0.16%, robbery by 0.55% and larceny by 0.18%. Using the estimated elasticities, an average increase in the value of oil reserves (26% increase in the value of reserves) results in a 4.15% increase in murder rates, 8% increase in robbery and 4.7% increase in larceny. These effects are not trivial. We explore potential mechanisms that could be driving this increase in crime and find that an increase in the value of local oil reserves improves the local economic conditions, increases the share of young males, and increases the share of individuals residing in group quarters (e.g. temporary worker housing) of its county with no effect on the local economic conditions, demographic changes or crime rates of adjacent counties.

The Research and Applications of Remaining Oil Potential Tapping in High Watered Stage for Heavy Oil Reservoir in Bohai

S oil field is a typical of water injection development of heavy oil reservoir in Bohai, and the formation of crude oil viscosity is 42 - 284 mPa⋅s. Due to the formation of crude oil viscosity, the oil field development gradually faces a series of problems as rapid rise of water cut, rapid decline of output, high water cut of oil wells and others. In order to improve the effect of oilfield development, it is necessary to increase the output of the oilfield by adjusting wells for the potential in the oilfield. However, due to the high cost of drilling, operation and testing of offshore oilfields, offshore oilfields require more elaborate description of residual oil and adjustment wells. With the continuous downturn in international oil prices and the lack of new testing data in old oilfields, it is urgent to re-use the existing data in oilfields through innovative methods to achieve a detailed description of the remaining oil in the oilfields and improve the precision research of indexing wells and ensure the reliable implementation of adjustment wells. Based on the existing dynamic data of S oilfield, this paper proposes a new method to quantitatively evaluate water flooding coefficient by using tracer theory to establish tracer data, and quantitatively evaluates the vicinity of the fault by means of image reflection and potential superposition and find the residual oil in the imperfect area of the well network, combined with the numerical simulation method to realize the fine description of remaining oil and improve the research precision of the adjustment well. Through the research in this paper, S oilfield has proposed to location of six adjustment wells which has implemented two. The production confirmed that the method of this paper has some reliability, while the method of heavy oil in the high water cut stage of residual oil fine description. The research of enhanced oil recovery in the stage has certain guiding significance for heavy oil reservoirs.

New Technology in a Mature East Malaysian Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 176120, “Success Story: A New Development Concept Utilizing New Advanced Technology in a Very Old Complex Mature Field,” by K.F. Ng, T. Afandi, D. Sa’adon, J. Ja’afar, M.A. Omar, and N.A. Latiff, Petronas, and G.I. Santoso, K. Alang, I.D. Roberts, N. Murad, D. Permanasari, and F. Kutty, Schlumberger, prepared for the 2015 SPE Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 20–22 October. The paper has not been peer reviewed. The T Field, located offshore east Malaysia, is a mature oil field that began its development in the 1970s. Conceptual geological models generally illustrated this field as a retrogradational turbidite setting. It is commonly known that the turbidite channel has enormous geological complexity and, therefore, presents great challenges for successful horizontal-well placement. This paper describes the first job in southeast Asia in developing horizontal-well placement in a turbidite environment. Introduction As of 15 years ago, T Field’s remaining oil deposits were present in the relatively thin turbidite channel complex on the steep-sloping flank of the field. Vertical and slanted wells were drilled to produce the targeted reserves, but post-drilling findings always showed inconsistency in sand existence and distribution because of lateral sand discontinuity. Because of the limited infill reservoirs, high reservoir dip angle, and less-prolific productivity, drilling a highly deviated oil producer along the reservoir dip and steering along its productive layer in the oil leg are found to be the optimal drilling approach. However, high well-placement risks were assessed owing to uncertainties in lateral sand distribution, variable formation dip, and fluid contacts. Evaluating Infill/Redevelopment Potential Some reservoirs located within the western area were believed to carry more re-serves; production data indicated that downdip oil remains untapped by existing producers. An average dipping angle of 13 to 20° and gas-cap-dominant drive suggested that remaining-oil potential could be unlocked only through the addition of the drainage point. Material-balance analysis was conducted, which further verified the earlier deduction by showing that the targeted reservoir contains more oil in place compared with existing book figures and has reserves at approximately twice the amount of previous estimates made from decline-curve analysis. A reservoir model was subsequently constructed. Two types of reservoir models were built in this exercise: a simple grid homogeneous model and a heterogeneous model that was created by referring to a geological depositional concept and to reservoir distribution based on a geostatistical method. Reservoir-modeling and -simulation results are consistent with those obtained from material balance. As expected, the secondary-recovery method will result in an incremental recovery because of the pressure maintenance and better sweep efficiency. However, this recovery is not ideal; the reservoir pressure was halved because of historical production, and lateral discontinuity still exists. Infill drilling was recommended as the best way forward. Well-Concept and -Execution Strategy The feasibility of executing the drilling campaign during the early stage of the study was also considered. In past development campaigns, deviated wells were drilled to penetrate and produce from multistacked reservoirs. The replication of such practices may result in missing the reservoir target because of the high potential of reservoir discontinuity.

Characteristics of fault zones and their control on remaining oil distribution at the fault edge: a case study from the northern Xingshugang Anticline in the Daqing Oilfield, China

Most major oil zones in the Daqing Oilfield have reached a later, high water cut stage, but oil recovery is still only approximately 35 %, and 50 % of reserves remain to be recovered. The remaining oil is primarily distributed at the edge of faults, in poor sand bodies, and in insufficiently injected and produced areas. Therefore, the edge of faults is a major target for remaining oil enrichment and potential tapping. Based on the dynamic change of production from development wells determined by the injection–recovery relationship at the edge of faults, we analyzed the control of structural features of faults on remaining oil enrichment at the edge. Our results show that the macroscopic structural features and their geometric relationship with sand bodies controlled remaining oil enrichment zones like the edges of NNE-striking faults, the footwalls of antithetic faults, the hard linkage segments (two faults had linked together with each other to form a bigger through-going fault), the tips of faults, and the oblique anticlines of soft linkages. Fault edges formed two types of forward micro-amplitude structures: (1) the tilted uplift of footwalls controlled by inverse fault sections and (2) the hanging-wall horizontal anticlines controlled by synthetic fault points. The remaining oil distribution was controlled by micro-amplitude structures. Consequently, such zones as the tilted uplift of the footwall of the NNW-striking antithetic faults with a fault throw larger than 40 m, the hard linkage segments, the tips of faults, and the oblique anticlines of soft linkage were favorable for tapping the remaining oil potential. Multi-target directional drilling was used for remaining oil development at fault edges. Reasonable fault spacing was determined on the basis of fault combinations and width of the shattered zone. Well core and log data revealed that the width of the shattered zone on the side of the fault core was less than 15 m in general; therefore, the distance from a fault to the development target should be larger than 15 m. Vertically segmented growth faults should take the separation of the lateral overlap of faults into account. Therefore, the safe distance of remaining oil well deployment at the fault edge should be larger than the sum of the width of shattered zone in faults and the separation of growth faults by vertical segmentation.