Performance testing of improved method for oil/water sample mixing, handling and analysis in high water cut samples

The Midale field, located in Saskatchewan, Canada, is one of the largest water-alternate-gas (WAG) injection operations in the world for enhanced oil recovery (EOR). Wells are normally completed across the three main oil horizons of the Marly formation (M1, M2, and M3), with production from all three zones being commingled. Horizontal producers and injectors are openhole wells, whereas vertical wells are usually casedhole. After years of operation, the WAG injected fluids started to communicate from injectors toward producers, resulting in high water and CO2 cuts and making oil production optimization and recovery more challenging. A new completion was envisioned to improve the oil producers’ rates and overall EOR performance. A casedhole vertical well was selected for upgrading into a new adaptable multiport completion, designed to give independent control of each zone. This new completion was designed considering the challenges of the produced fluids, as well as the interaction between each port, the nozzle size of each inflow control devices (ICD), and the financial impact of producing higher rates under the current (2015–2016) market, which is challenged by low oil prices. The engineering analyses used a steady-state hydraulic well model and a compositional fluid model to consider the impact of the CO2 operating in near critical conditions. Production well tests and laboratory analysis were used to tune the hydraulic well model and the fluid model, respectively. The optimization workflow used the ICD nozzle sizes as decision variables for each port of the new completion, and the financial function, which used reference prices for oil and handling costs for gas and water as coefficients, was maximized by a numerical mixed integer nonlinear programming (MINLP) solver for each case of study. The ICD nozzle sizes were selected for each port of the new completion, based on the hydraulic performance of a series of possible production scenarios, the optimization of the financial function, and the available settings of the ports. This paper presents the results of an integration of production test separator data, production logging test (PLT) surveys, fluid pressure/volume/temperature (PVT) data, equation of state (EOS) fluid models, hydraulic models, and optimization solvers. These data and models enabled engineers to analyze several possible ICD designs to maximize financial gain.

Dealing with mature offshore oilfield has complicated problems both surface and subsurface. In the reservoir condition high water cut wells make some bad impact in the production stages. Liquid handling facilities, tubing pipeline erosion, broken sand control, and high power consumption are several problem caused by high water cut wells. WW is an offshore oil field which has developed since 1990s with OOIP 758 MMBO. This reservoir was divided into several layer, 33 series is depleted reservoir with water injection since year 2000s (RF 23%) and 35 Series has strong water drive as its driving mechanism (RF 56%). Almost 85% of the oil wells is producing with water cut more than 97%. Increasing water cut or even watered out phenomenon was frequently happen during production stage, some of this problem was happen after well intervention such as after pump replacement. This paper will show the successful case of decreasing water cut significantly from WW D-29, WW H-12, II A-22. Laboratory test was firstly done to check the compatibility test of the rock with modified completion fluid. This chemical was mainly works as phase change water control and oil stabilize well for completion fluid. It was pumped simultaneously with regular completion fluid (filtered drill water and additives). Killing well was mandatory procedure when shut in wells will be repaired. GGR team supported by Production and Workover Team did integrated study to choose the chemical and well selection based on some criteria. WW D-29, WW H-12, and II A-22 are wells which have implemented modified completion fluid treatment. Those wells are produced from sandstone reservoir and drilled more than 10 years ago. During production period, water cut was significantly jumped due to several reason, such as pump replacement job, re-start up after the well trip off, etc. The result of the project were very excellent, WW D-29 (from 98% to 86%, gain +/− 180 bopd), WW H-12 (from 80% to 40%, gain +/− 250 bopd) and II A-22 (96% to 75%, gain +/− 130 bopd). These result give a lot of impact of increasing oil production in WW Field. This paper will elaborate how to solve the problem in offshore mature oil field special case for high water cut wells using modification of completion fluid treatment. We have succeeded increasing oil reserves.

In view of the problems of rapid rise of water cut and intensified sand production in the high water cut development stage of unconsolidated sandstone oilfield. A consolidation water reduce particles with dual functions of water reduce and sand control were developed and evaluated in laboratory from the aspects of consolidation temperature, strength, permeability and oil-water displacement of artificial core. The experiment showed that the particles can be used in reservoir temperature is 30−80 ℃, the compressive strength of artificial core is higher than 8 MPa, the liquid phase permeability is 0.1−1.2 μm2 which is adjusted according to particle size combination), and the average oil-water permeability ratio is 13.1. The combination of water reduce particles and mechanical gravel packing sand control technology forms an integrated technology of water cut sand control in unconsolidated sandstone oil field with high water cut. At the depth of the oil layer and the dominant channel of water flow, the barrier of oil seepage, water and sand retention is established to achieve the purpose of water reduce, oil seepage and sand control, which provides a strong support for the efficient and stable production development of unconsolidated sandstone oilfield in high water cut period. The technology has been successfully implemented on 76 Wells in the Dagang, Qinghai and South Sudan Moleeta oil fields. The success rate of sand control construction is 100%, the effective rate of sand control is 95.6%, the average water reduce rate is 16.71% points, and the better sand control and water reduce effect has been achieved.KeywordsUnconsolidated sandstoneHigh water cutWater reduces particlesSand control and water reduceWater reduce rate

Performance prediction is one of the important contents of oilfield development. It is also an important content affecting investment decision-making, especially for offshore oilfields with large investment. At present, most oilfields in China have entered high water cut stage or even extra high water cut stage, which requires higher prediction accuracy. Water drive curve is an important method for predicting performance. Traditional methods are based on exponential formulas, but these methods have poor adaptability in high water cut period. Because traditional methods deviate from straight line in high water cut period. In this paper, a robust method for predicting performance of offshore oilfield in high water cut period based on big data and artificial intelligence is proposed. Firstly, the reasons for the "upward warping" phenomenon of traditional methods deviating from the straight line are analyzed. It is found that the main reason for the deviation is that the relationship between the relative permeability ratio of oil to water and the water saturation curve no longer conforms to the exponential relationship. So a new percolation characteristic characterization equation with stronger adaptability is proposed, which focuses on the limit of high water flooding development. On this basis, the equation of the new water drive characteristic curve is deduced theoretically, and the dynamic prediction method is established. What's more, the solution of the method is based on large data and AI algorithm. This method has been applied to many high water flooding phase permeability curves, and the coincidence rate is more than 95.6%. The new water drive characteristic curve can better reflect the percolation characteristics of high water cut reservoirs. At the same time, the performance of adjustment wells and measures on the curve of development dynamic image is analyzed. Curve warping indicates that adjustment wells or measures are effective. Field application shows that the prediction error of the new method is less than 6%, which is more in line with the needs of oilfield development. Because of the application of artificial intelligence algorithm, the application is more convenient and saves a lot of time and money. This is a process of self-learning and self-improvement. As the oil field continues over time, each actual data will be recalculated into the database. Then the fitting and correction are carried out, and then the solution is learned again. This method has been applied to several oil fields in Bohai. And the effect is remarkable, which provides a good reference for the development of other oil fields.

Methods commonly used to measure the wettability of unconsolidated porous media are quick and easy to perform, but these tests do not provide reproducible results. This paper outlines the use of low-field nuclear magnetic resonance (NMR) as an alternative method of wettability assessment due to this tool's ability to discriminate bound fluid from bulk fluid. Water bound to the grain surfaces of water-wet samples relaxes quickly and produces signal amplitude peaks at low transverse relaxation (T2) values. Bulk water, on the other hand, relaxes much more slowly and signal amplitude peaks consequently appear at higher T2 values. It is expected that the contribution of surface-bound water in water-repellent samples is lower than in water-wet samples. NMR measurements performed on water-wet sand and on the same sand coated with organic matter clearly show significant differences in solid-fluid interactions between water and sands of different wettabilities. Numerous NMR measurements were obtained over time to monitor relaxation shifts because it was expected that the resulting spectra would provide insight into the rate of fluid uptake in sands of varying wettability. Water uptake appears to be spontaneous in water-wet samples and much slower in water-repellent samples, however all samples will eventually reach the same equilibrium endpoint regardless of wettability. NMR spectra also show that the results from water in uncoated and coated sands closely resemble that from water in wettable and water-repellent soils. Consequently, uncoated and coated sands can be used to analyze wettability mechanisms in unconsolidated porous media. The results also show that causative agents of soil water repellency include asphaltenes that are insoluble to n-pentane. Introduction Wettability is defined as "the tendency of one fluid to spread on or adhere to a solid surface in the presence of other immiscible fluids(1)." This parameter is not a fixed and constant property(2) due to factors such as saturation and climate history, as well as sample handling(3). Wetting and non-wetting fluids interact with a porous medium differently and these differences can be detected by low-field nuclear magnetic resonance (NMR)(4–6). One can infer the state of fluids within a porous medium from looking at NMR spectra based on type-specific transverse relaxation time (T2) cutoffs(7–9). Relaxation time is the time that a hydrogen-bearing molecule needs to revert to its original state, after it is excited by an oscillating magnetic field pulse sequence. Contributions to spectra at values of T2 that are lower than the cutoff are considered due to bound water while contributions at higher T2 values are considered due to water in the bulk phase(7, 10). Amplitude peaks at progressively lower T2 values indicate the presence of fluid in progressively smaller pores. The location of the amplitude peaks in NMR spectra can be used to infer sample wettability(9). While this has been done in porous media such as sandstones, carbonates, and chalk(11–14), no work has been done on soils. NMR can be a viable tool for assessing soils wettability because other wettability measurements such as the contact angle are impossible to make in unconsolidated porous media.

In recent years, the production of tight reservoirs with waterflooding in China has entered a progressively declining phase with unstable oil rate and higher water cut, rising challenges to any further enhancement of oil recovery. Targeting the high water cut and complex pore structure characteristics typical of these reservoirs, this work evaluates the reservoir compatibility of a microspheres-alternating-nanoemulsion flooding process and optimizes its injection strategy. Representative reservoir scenarios were first established; laser-particle-size analyzers and other laboratory instruments were then employed to quantify formulation-reservoir compatibility. A multiscale numerical study has been performed with CMG-STARS v.2022. The core-scale simulations systematically examined the influence of key factors on displacement efficiency improvement and water cut reduction, matched with the experimental results of core flooding tests. The combined experimental/numerical workflow furnishes a theoretical framework for optimizing the injection scheme. Beyond assessing formulation compatibility, the study delivers optimized injection parameters and strategies for microspheres-alternating-nanoemulsion flooding, providing both theoretical analysis and practical technology reference for improving oil recovery in tight reservoirs with higher water cut. Specifically, when the microsphere concentration increased from 0.1% to 0.3%, the minimum water cut was reduced by approximately 5%, while further concentration increases showed no significant additional impact on water content. Compared with water flooding, the relative permeability curve of the microspheres-alternating-nanoemulsion flooding system shifted entirely to the right. Numerical simulation of representative well groups revealed that a slug design with a microsphere-to-nanoemulsion ratio of 1:3 yielded the optimal enhanced oil recovery effect, and after ten years of production, the recovery factor increased by 0.46%.

Water Shut-Off (WSO) actions are remedial activities that are being implemented in the heavy oil N Field, with the objective of reducing the water inflow of the well by closing zones which are major contributor to the high water cut. WSO are commonly executed as a mitigation action in operating wells with previous economic value. The purpose of this study is to develop a thorough knowledge of the rate of success of WSO activities linked to the time of WSO implementation, type of well (either horizontal or vertical) and the presence or lack of PLT (Production Log Test). Success was evaluated by reviewing the net oil production rate before and after WSO activity with the gained net oil rate being converted to US Dollars. There is no significant difference found in the success ratios between horizontal wells and verticals. However, in the horizontal wells, 74% of the successful ones were the heel shut-offs. WSO activities are found to have a success rate of 100% if the activity is implemented within the first year of the start of high water cut. Moreover, wells with WSO implementation within the first three years of observing high water-cut have a success rate of 65%. Noticeably, the success rate decreased dramatically with time, with wells having high water-cut for seven years and up to eleven years to the time of WSO implementation. These wells show success rates of 50% and 33% for seven and eleven years respectively. A numerical sector model and well model were created to explain these findings. During oil production because of a localized decrease in pressure, the water-oil interface may rise up and deform into a conical shape near the well. This phenomenon is known as ‘water coning’. At the time of water breakthrough, the cone is observed to be narrower than more advanced stages when the water cut has risen to higher levels. At these times, the cone has broadened and, depending on spacing between adjacent wells, has lifted the overall level of the oil/water interface, decreasing the distance between the wellbore and the water. As a result, water shutoff becomes less effective with time. It is recommended to start WSO activities on wells within the first three years of high water-cut indications. In case there is no PLT or other data, heel shutoff for the horizontal wells have a better success rate.

This study analyzed the physical and hydrodynamic characteristics of various horizons in the Kumkol and East Kumkol oil fields by special core analysis to integrate strategies for controlling water cuts and well-intervention procedures for a more effective oil flow rate in mature oil fields in Kazakhstan. The results indicated that the recovery factor (RF) for Horizon I is 48.3% (98.7% water cut), while Horizon II has an RF of 45.5% (97.9% water cut). Horizon III has an RF of 52.7% (98.8% water cut), and Horizon IV has an RF of 32.6% (98.6% water cut) in the Kumkol Field. In the East Kumkol Field, Horizon I has an RF of 49.5% (96.7% of water cut), and Horizon II has an RF of 31% (94.9% of water cut). The average increase in oil flow rate from well optimization ranges from 5.3 to 6.4 tons per day in the Kumkol Field and 5.22 tons per day in the East Kumkol Field. The maximum increase in oil flow rate is 10.8 tons/day for Horizon I in the Kumkol Field and 6.9 tons/day for Horizon II in the East Kumkol Field. The well-intervention procedures are more effective in the Kumkol Field than in the East Kumkol Field. Given the high water cut observed in these mature reservoirs, this study also examines polymer flooding as an enhanced oil recovery (EOR) technique to improve oil displacement efficiency and reduce water production. Polymer flooding has been successfully implemented in high water-cut reservoirs, including the Uzen field in Kazakhstan, demonstrating its ability to modify fluid filtration profiles and enhance oil recovery. The feasibility of applying polymer flooding in the Kumkol and East Kumkol fields is analyzed, along with a comparison of its effectiveness against conventional water shut-off and well-intervention methods. Additional research is needed to assess polymer retention, reservoir compatibility, and the economic feasibility of large-scale implementation.

Carbonate reservoirs in the Middle East occupy an important position in global oil and gas storage and production, which have the characteristics of high single-well production, good development cost-efficiency, strong heterogeneity, complex distribution of barriers, and high permeability layers. For the thick-bedded massive belt edge-bottom water reservoir represented by Halfaya oilfield in southern Iraq, based on the water injection development experience in recent years, development issues such as unbalanced reservoir production and differential water breakthroughs have gradually become prominent, and the proportion of high water-cut wells has been increasing year by year. This severely restricts the overall production and production capacity of the reservoir. Through the integrated static and dynamic analysis, the study shows that water breakthrough in high water-cut wells is controlled by the intrinsic and extrinsic causes. For innate factors, heterogeneity of the oil reservoir is extremely strong, and the thin interbeds of different development strata are superimposed on each other, and the spatial distribution of barriers separated by physical properties and high permeability strips is complicated. The external reason is caused by the unbalanced and unmatched injection-production relationship. The well patterns of different layers are irregular, and the injection-production parameters are difficult to adjust. At the same time, the lower layers developed strong natural edges and bottoms aquifer. In this research, a comprehensive discrimination method integrating seismic-geology-logging-monitoring-dynamics-simulation is established to reveal the internal and external causes of water breakthrough in high water-cut wells and classify three types of water breakthrough, which are strong bottom water coning at the bottom, rapid breakthrough of injected water, and Layered edge water invasion, and preliminary control strategies are proposed.KeywordsCarbonate reservoirWells with high water cutWater breakthrough (WBT) causes and typesRapid injected WBTStrong edge and bottom aquiferStrategies for WBT wells

Excessive water production from hydrocarbon reservoirs is a serious issue faced by the industry, particularly for mature fields. Higher water cut adversely affects the economics of the producing wells, thus it is undesirable. Disposal and reinjection of ever-increasing volumes of produced water poses additional liability. A significant challenge faced in the mature Umm Gudair field is assuring hydrocarbon flow through high water-prone intervals. In recent times, field development strategies have begun to prioritize new well intervention technology because of the advantages of minimized water cut, higher production rates, and improved overall reserve recovery (hydrocarbon in place). This paper discusses the field implementation of a downhole chemical methodology, "first of its kind" designed and applied, that has created a positive impact in overall productivity. To solve these challenges, the treatment was highly modified as fit-for-purpose to address the unique challenges of electric submersible pump (ESP)-driven well operations, formation technical difficulties, high-stakes economics, and high-water potential from these formations. A unique Organically Crosslinked Polymer (OCP) system with a tail-in Rigid Setting Material (RSM) system was implemented as a porosity-fill sealant in a high-water-cut well to selectively reduce water production. A pre-flush was pumped ahead of the treatment to remove deposits that could have prevented the polymer from effective gelation. The treatment was then overdisplaced with brine. The OCP system is injected into the formation as a low viscosity solution using the spot and hesitation squeeze method via bullheading. It activates at a predicted time to form a 3-D rigid hydrogel to completely shut off matrix permeability, fractures, fissures, and channels, thus creating an artificial barrier seal in the reservoir. The tail-in near wellbore RSM system rapidly develops a high compressive strength to avoid any formation loss before setting. This holistic approach helps to create a robust sealant for blocking the unwanted water-producing zone, impeding water flow, and facilitating increased hydrocarbon flow. A direct comparison of the application of this system with conventional cement squeeze treatments is presented to illustrate the advantage of having a deep matrix penetration for a more efficient water shutoff in this field. A direct result of the implemented treatment is that the post-operation well test and production data showed a high-sustained production at lower rate with significantly reduced watercut, confirming this technology is one of successful chemical water shut off techniques this field. This paper summarizes the candidate selection, design processes, challenges encountered, and production response, and can be considered a best practice for addressing high water production challenges in similar conditions in other fields.

This paper describes a collaborative analytical technique employed by a team of subsurface, production and facilities engineering members on improving production allocation in a mature field producing at a high water cut. The field production allocation deteriorated sharply from 2015 when a field water cut was beyond 90%. The paper describes the entire workflow starting with problem identification, preliminary investigation, key actions taken, and collaborative analytical techniques utilized and proposed solutions to improve production allocation. The team conducted a primary investigation using several key investigative techniques and the result led to the identification of two main focus areas to resolve the production allocation issue; a) Improving the existing production allocation method, and b) Improving the current well-test measurement procedure. The team developed collaborative analytical techniques including fit-for-purpose mathematical modelling, specific design for field experiments and advance nodal analysis, which used as a means of identifying the potential root causes in well-test measurement procedure. Following primary investigations, the allocation methodology was updated to include the export meter oil volume readings as an extra step in the allocation algorithm. This helped removing the impact of physical conditions (e.g. weather) from the variations of tank dip measurements. Following implementation in July 2017, results indicated a clear improvement on allocation factors up to 26% on two platforms. Unfortunately, the remaining platforms barely showed any improvement. This was in line with preliminary findings that had identified these platforms as contributing the most to the overall field allocation factor deterioration. On the well-test measurement procedure, the result of collaborative analytical techniques concluded that the current Basic Sediment and Water (BSW) measurement by centrifuge method being deployed in the field was acceptable for crude with a low water content, while it tended to underestimate BSW in wells producing at relatively higher water cuts. With this realization, correction factors were developed and recommended to be applied to the measured BSW to mitigate the measurement uncertainty. The applied correction factors were found to better reflect the actual oil rate from the wells and better match the oil volume measured at platform export meters. The result showed immediate improvements the overall field allocation factor by up to 21%. This collaborative analytical technique to improve production allocation was uniquely developed for a mature oil field producing with extremely high water cut and located offshore in the Gulf of Thailand. Although the collaborative analytical techniques consisted of fit-for-purpose mathematical modelling, specifically designed for the field in question and adaptive approach of nodal analysis, the methods can easily be replicated to other fields, with a number of simply quantifiable potential benefits.

Publication Rights Reserved This paper was prepared for the Rocky Mountain Regional Meeting to be held in Montana, June 10–11, 1965, and is considered the property of the Society of Petroleum Engineers. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract A discussion of the oil and water contents and the producing water cut behavior of Tensleep-Minnelusa reservoirs is given. Interpretations of rock and fluid data, logs and well performance are illustrated. Interpretation of the basic data indicates the presence in some reservoirs of oil-water transition zones several hundred feet in thickness. The characteristics of these zones are such that they may have interstitial water saturations as low as 20 per cent of pore space and still produce with extremely high water cuts. These characteristics cause evaluation of productivity of both logs and core analyses to be extremely difficult - particularly in exploration wells where the basic data on the reservoir fluids may not be available. Oil in place values approaching 1000 barrels per acre foot are indicated in zones which may produce at water cuts in excess of 95 per cent. Such productive intervals warrant investigation as secondary recovery prospects using thermal or other advanced techniques. Introduction The Pennsylvanian Age sands, particularly the Tensleep-Minnelusa members, are prolific oil producers in many areas of Wyoming and Montana. Much of this production is low gravity oil and is frequently accompanied by high water cuts. Evaluation of such reservoirs, particularly in exploration drilling has proved to be extremely difficult. Intervals which appear from core analyses and log information to be oil productive have frequently been found to produce at uneconomically high water cuts - either upon initial completion or shortly thereafter. A study of certain measured rock and fluid property information and logs has been made in an attempt to explain this performance and to arrive at better means of evaluation of the productive characteristics of this formation.

One of the most significant challenges for extending production life in mature waterflood fields is high water cut. Couple with high reservoir heterogeneity, extensive layering and faulting, these fields often developed irregular flood patterns after decades of production which compounded the challenge of optimizing recovery from these fields. The severity of this problem has been observed in the Niger Delta oil fields, where several matured fields are producing at high water cut after many years of waterflooding. This study aimed to improve oil recovery using Water Alternating Gas (WAG) injection in comparison with Waterflooding and Gas injection methods in the Niger Delta. Water- alternating-gas (WAG) injection process is one of innovative and new enhanced oil recovery (EOR) methods. This method Improves gas injection microscopic and water injection macroscopic displacement processes. In this study, a computer software known as “ECLIPSE” was used to model and simulate the hydrocarbon flow of an oil field in the Niger Delta. The software was used in optimizing oil recovery using WAG method in comparison with water flooding and gas injection was discussed. From the results obtained, WAG injection had a maximum field oil efficiency (FOE) of 34%, a field oil production total (FOPT) of 76.46 MMSTB, a plateau time of 3.7years and a field water cut (FWCT)of 26.11%. Waterflooding had a FOE of 26.65%, a FOPT of 59.62 MMSTB, a plateau time of 2.2years and FWCT of 47.58%. Whereas gas injection had an FOE of 21.35%, a FOPT of 47.89 MMSTB, a plateau time of 2 years, and FWCT of 9.2%. From comparative analysis of the three recovery methods, WAG injection outperformed both waterflooding and gas injection with the highest FOE of 34%, the longest plateau time of 3.7years, and a minimal water cut of 26.11%. Therefore, WAG recovery method has thus far demonstrated to be the most effective recovery method, in comparison to waterflooding and gas injection methods

The paper combines a brief case history of applications with supporting laboratory data, for using a new relative permeability modifier (RPM) in conjunction with a conventional acid stimulation treatment. This design was targeted at mature oil wells with high water cuts in Ecuador. The recommendation was proposed after mineralogical characterization of core samples, using scanning electron microscopy (SEM) followed by laboratory core flooding with treatment fluids. The methodology described in the paper comprises stimulation of certain areas of the sandstone formation with an acid followed by a RPM treatment to prevent the water from the stimulated water-bearing zones from entering the wellbore. Coiled tubing is used for effective placement of the treatment. Conventional stimulation treatments in the Hollin sandstone formation in Ecuador result in high water cuts because of encroaching water from an active aquifer. The acidizing technique with RPM improved the economic life of many mature wells in the field. Both laboratory and field data indicate excellent results from the treatments. The overall water cut in the treated wells decreased (by 8 to 15%), while oil production increased (~200%). Coiled tubing enables accurate placement of the acid and RPM into the desired zones, with the benefits from this targeted treatment far outweighing the cost of using coiled tubing units. Successful implementation of the laboratory core flood results in the field resulted in field-wide protocols aimed at oil wells producing water at unacceptable rates. The optimized stimulation treatment increases oil production and selective placement of RPM using coiled tubing decreased water cut, thereby prolonging the economic viability of mature wells.

The Ford Geraldine Unit (FGU), in Reeves and Culberson Counties, West Texas, produces from the Ramsey Sandstone in the upper Bell Canyon Formation. After primary depletion, a major portion of the reservoir was waterflooded in stages from 1969 to 1980 and is currently under a maturing CO flood that was started in 1981. However, because of high initial water saturation of 47.7% and some aquifer encroachment, the structurally low areas in the northeastern part of the reservoir were producing at very high water cut when the primary recovery approached its economic limit in 1968. As a result, this area responded very poorly to waterflood and no significant production has since been realized from this part of the unit. An estimated 10.1 MMSTB of the 12.9 MMSTB original oil in place (OOIP) remains in the reservoir in this area. This paper presents results of a study in which advanced geologic, geophysical, and engineering reservoir characterization techniques have been applied to this part of the reservoir as a demonstration area for enhanced recovery. A conditionally simulated Stochastic-permeability-distribution model has also been developed. Compositional simulations were performed for CO flood using stochastic and layered permeability distributions and conservative estimates of fluid saturations. Results indicate that a minimum of 10% of remaining oil in place (ROIP) can be recovered at breakthrough. Despite very high postwaterflood water saturations, the producing water cut gradually declines because of increase in hydrocarbon mobility as the injected CO dissolves in the oil. An important observation is that compositional simulations indicate significant incremental recovery after breakthrough. At the permissible gas-oil ratio (GOR) of 30 MSCF/STB, recovery of over 30% of ROIP is achievable from the demonstration area. P. 375