R.S. Seright

EOR Screening Criteria Revisited - Part 1: Introduction to Screening Criteria and Enhanced Recovery Field Projects

Screening criteria have been proposed for all enhanced oil recovery @OR) methods. Data from EOR projects around the world have been examined and the optimum reservoir/oil characteristics for successful projects have been noted. The oil gravity ranges of the oils of current EOR methods have been compiled and the results are presented graphically. The proposed screening criteria are based on both field results and oil recovery mechanisms. The current state of the art for all methods is presented briefly, and relationships between them are described. Steamflooding is still the dominant EOR method. All chemical flooding has been declining, but polymers and gels are being used successfully for sweep improvement and water shutoff. Only C02 flooding activity has increased continuously.

A strategy for attacking excess water production

This paper describes a straightforward strategy for diagnosing and solving excess-water-production problems. The strategy advocates that the easiest problems should be attacked first and that diagnosis of water productionproblems should begin with the information already at hand. A listing of water-production problems is provided, along with a ranking of their relative ease of solution. Although a broad range of water-shutoff technologies is considered. the major focus of the paper is when and where gels can be effectively applied for water shutoff.

Potential for Polymer Flooding Reservoirs With Viscous Oils

This paper examines the potential of polymer flooding to recover viscous oils, especially in reservoirs that preclude the application of thermal methods. A reconsideration of enhanced-oil-recovery (EOR) screening criteria revealed that higher oil prices, modest polymer prices, increased use of horizontal wells, and controlled injection above the formation parting pressure all help considerably to extend the applicability of polymer flooding in reservoirs with viscous oils. Fractional-flow calculations demonstrated that the high mobile-oil saturation, degree of heterogeneity, and relatively free potential for crossflow in our target North Slope reservoirs also promote the potential for polymer flooding. For existing EOR polymers, viscosity increases roughly with the square of polymer concentration—a fact that aids the economics for polymer flooding of viscous oils. A simple benefit analysis suggested that reduced injectivity may be a greater limitation for polymer flooding of viscous oils than the cost of chemicals. For practical conditions during polymer floods, the vertical sweep efficiency using shear-thinning fluids is not expected to be dramatically different from that for Newtonian or shear-thickening fluids. The overall viscosity (resistance factor) of the polymer solution is of far greater relevance than the rheology.

Why do gels reduce water permeability more than oil permeability

A capacity to reduce water permeability much more than oil permeability is critical to the success of gel treatments in production wells if zones cannot be isolated during gel placement. Although several researchers have reported polymers and gels that provide this disproportionate permeability reduction, the explanation for the phenomenon was unclear. In this paper, the authors examine several possible explanations for why some gels reduce water permeability more than oil permeability. Their experimental results indicate the disproportionate permeability reduction is not caused by gravity or lubrication effects. Results also indicate that gel shrinking and swelling are unlikely to be responsible for the phenomenon. Although wettability may play a role in the disproportionate permeability reduction, it does not appear to be the root cause for water permeability being reduced more than oil permeability. Results from an experiment with an oil-based gel suggest that segregation of oil and water pathways through a porous medium (on a microscopic scale) may play the dominant role in the disproportionate permeability reduction. However, additional work will be required to verify this concept.

Gel Propagation Through Fractures

Based on experimental results, a model was developed to quantify gel propagation and dehydration during extrusion through fractures. To maximize gel penetration along fractures, the greatest practical injection rate should be used. On the other hand, in wide fractures or near the end of gel injection, gel dehydration may be desirable to form rigid gels that are less likely to wash out after placement. In these applications, reduced injection rates may be appropriate. Significant advantages could be realized for gels made with a polymer that has the largest available molecular weight.

Wettability Survey in Bakken Shale With Surfactant-Formulation Imbibition

For ultratight shale reservoirs, wettability strongly affects fluid flow behavior. However, wettability can be modified by numerous complex interactions and the ambient environment, such as pH, temperature, or surfactant access. This paper is a third-phase study of the use of surfactant imbibition to increase oil recovery from Bakken shale. The surfactant formulations that we used in this paper are the initial results that are based on our previous study, in which a group of surfactant formulations was examined—balancing the temperature, pH, salinity, and divalent-cation content of aqueous fluids to increase oil production from shale with ultralow porosity and permeability in the Middle Member of the Bakken formation in the Williston basin of North Dakota. In our previous study, through the use of spontaneous imbibition, brines and surfactant solutions with different water compositions were examined. With oil from the Bakken formation, significant differences in recoveries were observed, depending on compositions and conditions. Cases were observed in which brine and surfactant (0.05 to 0.2 wt% concentration) imbibition yielded recovery values of 1.55 to 76% original oil in place (OOIP) at high salinity (150 to 300 g/L; 15 to 30 wt%) and temperatures ranging from 23 to 120 C. To advance this work, this paper determines the wettability of different parts of the Bakken formation. One goal of this research is to identify whether the wettability can be altered by means of surfactant formulations. The ultimate objective of this research is to determine the potential of surfactant formulations to imbibe into and displace oil from shale and to examine the viability of a field application. In this paper, through the use of modified Amott-Harvey tests, the wettability was determined for cores and slices from three wells at different portions of the Bakken formation. The tests were performed under reservoir conditions (90 to 120 C, 150to 300-g/L formation-water salinity), with the use of Bakken crude oil. Both cleaned cores (cleaned by toluene/methanol) and untreated cores (sealed, native state) were investigated. Bakken shale cores were generally oil-wet or intermediate-wet (before introduction of the surfactant formulation). The four surfactant formulations that we tested consistently altered the wetting state of Bakken cores toward water-wet. These surfactants consistently imbibed to displace significantly more oil than brine alone. Four of the surfactant imbibition tests provided enhanced-oil-recovery [(EOR) vs. brine water imbibition alone] values of 6.8 to 10.2% OOIP, incremental over brine imbibition. Ten surfactant imbibition tests provided EOR values of 15.6 to 25.4% OOIP. Thus, imbibition of surfactant formulations appears to have a substantial potential to improve oil recovery from the Bakken formation. Positive results were generally observed with all four surfactants: amphoteric dimethyl amine oxide, nonionic ethoxylated alcohol, anionic internal olefin sulfonate, and anionic linear a-olefin sulfonate. From our work to date, no definitive correlation is evident in surfactant effectiveness vs. temperature, core porosity, core source (i.e., Upper Shale or the Middle Member), or core preservation (sealed) or cleaning before use. Introduction Shale rock is an important source of oil and gas in a number of sedimentary basins in North America. Most shale reservoirs have a low porosity and ultralow permeability with natural fractures. Shale formations have long been considered important source rocks, capable of producing oil at economic rates when completed by hydraulically fractured horizontal wells. Surfactant-formulation optimization is a key step in our investigation of chemical imbibition (with the use of surfactant or brine formulations) to stimulate oil recovery from shale. Initial surfactant screening and optimization involved the balancing of pH, salinity, and divalentcation content of the injected aqueous fluid that promote imbibition while minimizing clay swelling and formation damage (Wang et al. 2011a, b). However, the effectiveness of a surfactant formulation can also depend on wettability alteration. In this paper, we investigated whether our initial optimized surfactant formulations can modify Bakken shale wetness. As a relatively thin, clastic unit, the Bakken formation in North Dakota consists of three informal units that are named the Lower Shale, Middle Member, and Upper Shale. The Middle Bakken Member ranges from 40 to 70 ft in thickness, with lithologic content varying from argillaceous dolostones and siltstones to clean, quartz-rich arenites and oolitic limestone with shale (Phillips et al. 2007). Measured core porosities in the Middle Member range from 1 to 16% and average approximately 5% by plot vs. permeability. A few high-pressure mercury-injection measurements indicate that in-situ porosities are on the order of approximately 3%. Measured permeability ranges from 0 to 20 md in the Middle Member and typically is low, averaging 0.04 md by plot of porosity vs. permeability. As burial depth increases, permeability in sandstones in the Middle Member has been shown to decrease from a range of approximately 0.06 to 0.01 md, where the adjacent shales are immature, to a range of approximately 0.01 to 0.01 md, where these shales are mature. The temperature of the Middle Member ranges from 80 to 120 C (Pitman et al. 2001). On the basis of the chemical analysis of Bakken formation water by the Environmental Analytical Research Laboratory at the University of the North Dakota, the brine salinities range from 150,000 to 300,000 mg/L (15 to 30 wt%) total dissolved solids (TDS) in the Williston basin (Wang et al. 2011a). Also, the statistical data from 200 well samples in the pre-Mississippian rocks (of which the Bakken is the top formation; Iampen and Rostron 2000) proved this range. Generally, wettability strongly affects fluid flow behavior. In a water-wet status, water can be imbibed into bypassed zones by capillary forces. Alternatively, if the porous media are oil-wet, capillary force prevents water from entering the bypassed zones (Sharma and Mohanty 2011). For most shale reservoirs, waterflooding has limitations because of relatively higher clay content, even though waterflooding is favorable for neutral-wet status. The mechanism of wettability alteration involves surfactant added related with capillary pressure. As wettability is altered, the capillary pressure changes from negative to positive, and countercurrent imbibition mobilizes more oil. Furthermore, the relative permeabilities and residual saturations are changed to provide a higher oil recovery from the core. Several previous studies were performed with the use of surfactant imbibition to alter wettability in carbonate and chalk reservoirs, with rock permeability ranging from 1 to 15 md and porosity up to 29.1%. Zhang and Austad Copyright VC 2012 Society of Petroleum Engineers

Use of Preformed Gels for Conformance Control in Fractured Systems

Using wide ranges of gel age, gel velocity, and fracture conductivity or tube diameter, Cr(III)-acetate-HPAM gels were studied as they extruded through fractures and tubes. Gels exhibited shear-thinning behavior in fractures and tubes that correlated with the gel superficial velocity and the fracture width or tube diameter. In fractures with sufficiently small widths, gels dehydrated during extrusion, thus reducing the rate of gel propagation. This effect was more pronounced as the fracture width decreased. Using the experimental results, a numerical study was conducted to compare placement of preformed gels and water-like gelants.

Case Study on Prefromed Particle Gel for In-Depth Fluid Diversion

The paper describes preformed particle gel (PPG) treatments for in-depth fluid diversion in four injection wells located in the north of Lamadian, Daqing oilfield, China. Lamadian is sandstone oilfield with thick net zones. The selected four injectors have 46 connected producers with average water cut of 95.4% before treatment. The paper reports the detailed information for the four well treatments, including well candidate selection criteria, PPG treatment optimization, real-time monitoring result during PPG injection and reservoir performance after treatment. In addition, a discussion is made to analyze why so large amount of large particles can be injected into the reservoir. Large volume of PPG suspension with concentrations of 2,000-2,500 mg/L and particle sizes of 0.06-3.0 mm was injected into each well and it took about 4 months to finish each injection. The injection volume ranges from 11,458 to 17,625 m per well with a total of 56,269 m of PPG suspension (295,680 lbs of dried PPG) for the four wells. During PPG injection, the increase of the wellhead pressure was quite stable and no PPG was produced from adjacent producers. Recorded real-time monitoring Data about injection pressure and rate, PPG particle size change during PPG injection provide invaluable information to analysis the possibility of fracture/channel in the reservoir. The treatments resulted in an oil increase of 34.8 t/d and average water cut decrease of 0.94% within 10 months after treatments. Introduction Excess water production has become a major problem for oilfeld operators as more and more reservoirs mature due to long term of water flooding. Higher levels of water production result in increased levels of corrosion and scale, increased load on fluid-handling facilities, increased environmental concerns, and eventually well shut-in. Consequently, producing zones are often abandoned in an attempt to avoid water contact, even when the intervals still maitain large volumes of remaining hydrocarbons. Controlling water production has become more and more important to the oil industry. Reservoir heterogeneity is the single most important reason for low oil recovery and early excess water production. Most oilfields in China, which were discovered in continental sedimentary basins, are characterized by complex geological conditions and high permeability contrast inside reservoirs. To maintain reservoir pressure, these reservoirs were developed by water flooding from early stage of their development. Many of them have been hydraulically fractured, intentionally or unintentionally, or have been channeled due to mineral dissolution and production during waterflooding (Liu, 2006). Reservoirs with induced fractures or high-permeability channels are quite common in the mature oilfields. Gel treatment is a cost-effective method to improve sweep efficiency in reservoirs and to reduce excess water production during oil and gas production. Traditionally, gels are usually placed near wellbore of production or injection wells to correct inter-layer heterogeneity or heal fracture. However, the remaining oil on the top of a thick heterogeneous layer has become the most important target to improve oil recovery as a reservoir matures. In-depth diversion gels (Seright, 2004, Frampton, 2004, Sydansk, 2004, 2005, Cheung, 2007, Rousseau, 2005, Bai, 2007) have been reported to penetrate deeply into higher permeability zones or fractures and seal or partially seal them off thus creating high flow resistance in former, watered-out, high permeability portion of the zones. When successful, these gel systems divert a portion of the injection water into areas not previously swept by water shown in Fig. 1. Traditionally in-situ gels have been widely used to control conformance. The mixture of polymer and crosslinker called gelant is injected into target formation and react to form gel to fully or partially seal the formation at reservoir temperature (Sydansk, 1992, Jain, 2005). So the gelation occurs in reservoir conditions. A new trend in gel treatments is applying preformed gels for the purpose because the preformed gels are formed at surface facilities before injection and no gelation occurs in reservoirs so they can overcome some distinct drawbacks inherent in in-situ gelation systems, such as lack of

Gel Placement in Fractured Systems

This paper examines several factors that can have an important effect on gel placement in fractured systems, including gelant viscosity, degree of gelation, and gravity. For an effective gel treatment, the conductivity of the fracture must be reduced and a viable flow path must remain open between the wellbore and mobile oil in the reservoir. During placement, the gelant that``leaks off`` from the fracture into the rock plays an important role in determining how well a gel treatment will reduce channeling. For a given volume of gelant injected the distance of gelant leakoff is greater for a viscous gelant than for a low-viscosity gelant. In one method to minimize gelant leakoff, sufficient gelation is designed to occur before the gelant leaves the wellbore. The authors investigated this approach in numerous experiments with both fractured and unfractured cores. They studied Cr(III)/acetate/hydrolyzed polyacrylamide (HPAM), resorcinol/formaldehyde, Cr(III)/xanthan, aluminum/citrate/HPAM, and other gelants and gels with various delay times between gelant preparation and injection. Their results suggest both hope and caution concerning the injection of gels into fractured systems.

A Survey of Field Applications of Gel Treatments for Water Shutoff

Previously published field results were examined to determine if they reveal usable guidelines for the selection of wells as candidates for gel treatments. Views of seven gel vendors and experts from eight major oil companies were also examined concerning the selection and implementation of gel treatments in injection and production wells. This study demonstrates that gel treatments have been applied over a remarkably wide range of conditions. Unfortunately, the success rates for these projects have been very sporadic. Our analysis indicates that the producing water/oil ratio was usually the only criterion used to select candidate wells. To improve the success rate for future gel applications, the source and nature of the water production problem must be adequately identified. Results from interwell tracer studies and simple injectivity and productivity calculations can be especially useful in this diagnosis. Recovery calculations should indicate that considerable mobile oil remains that could be recovered more cost-effectively if a blocking agent could be realistically placed in the proper location. lmprovements are needed in the methods used for sizing gel treatments. The method of sizing should be tailored to the type of channeling problem encountered. Five different types of channeling problems are discussed. References and illustrations at end of paper INTRODUCTION A large number of gel treatments have been applied with the objective of improving reservoir sweep efficiency. With this extensive field experience, one might expect conditions where this technology does and does not work to be fairly well defined. However, considerable uncertainty still exists concerning how and where gel treatments are best applied. While many projects have been very successful,2d many other projects have been technical failures. Two studies indicated that less than 45 % of the gel treatments were successful In this paper, we investigate whether published field results reveal usable guidelines for the selection of candidates for gel treatments. Views of seven gel vendors and experts from eight oil companies are also examined concerning the selection and implementation of gel treatments. After analyzing the literature and survey responses, we propose criteria for candidate selection, both for injection and production wells. LITERATURE REVIEW OF FIELD APPLICATIONS Our review of the petroleum literature included 114 injectionwell gel projects (involving more than 3500 wells) and 171 polymer floods that were planned and/or implemented during the 1980s. The literature that provided the information for this survey is listed in Appendix A of Ref. 9. The information was obtained from over 600 articles and reports from 21 different journals and organizations. We also found 274 field applications of polymers and gels in production wells that were