Higher Ultimate Recovery Research Articles

Experimental Study on Gas Production Capacity of Composite Reservoir Depletion in Deep Carbonate Gas Reservoirs

Deep carbonate gas reservoirs exhibit diverse reservoir types and complex seepage patterns. To study the gas production capabilities of different composite reservoir types, we classified the reservoirs of the fourth member of the Dengying Formation in the Anyue Gas Field into high-quality reservoirs (HRs) and poor-quality reservoirs (PRs) based on high-pressure mercury injection (HPMI) experiment results. By varying the differential pressure of the depletion experiment and the connection method, as well as the permeability and water saturation of the composite core, the effects of well location deployment, permeability ratio of the high-quality reservoir and poor-quality reservoir (PRHPR), gas well production pressure difference (GWPPD), and water saturation on the depletion gas production characteristics of the composite reservoir were studied. The research results show that (1) deploying wells on HR enables high gas production rates and ultimate recovery rates; (2) only when the PRHPR falls within a reasonable range (21.88–43.19) can the “dynamic recharge” capability of PR and the high permeability of HR be coordinated to achieve high gas recovery rates; (3) a GWPPD of 3 MPa is optimal, resulting in fast gas production rates and high ultimate recovery rates for PR; (4) high water saturation (≥50%) leads to premature water breakthrough at the well bottom, decreased gas production rate, and sealing of HR and PR reserves by formation water. Combining experimental results with field production data is our next research focus. Our future research focus will be on integrating experimental results with field production data to provide solid theoretical support for the efficient development of this type of gas reservoir.

A semi-compositional approach to model asphaltene precipitation and deposition in solvent-based bitumen recovery processes

Steam assisted gravity drainage (SAGD), as a commercially proven high ultimate recovery process for heavy oil and bitumen is energy intensive and may be limited by high usage of water. In the recent years, numerous methods to combine solvent and heat have been proposed for the in-situ recovery of bitumen. Among these methods, N-Solv (heated solvent vapor injection) and EBRT (enhanced bitumen recovery technology) utilize heated solvent vapor to extract heavy crudes under in situ conditions. These methods take the advantage of partial in situ upgrading of oil with much lower consumptions of water and natural gas and have the potential to reduce greenhouse gas (GHG) emissions. However, with the current knowledge relevant to solvent/heat-assisted recovery processes, it still remained uncertain how the in-situ upgrading could impact ultimate recovery and the efficiency of these processes. This study, thus, aims at providing insights about these processes with a numerical model. The study develops a simulation model that captures important mechanisms involved in the processes such as diffusion/dispersion, solvent dissolution, asphaltene precipitation and potential deposition. The complexity of modelling such processes is due to interrelation of oil–gas phase behavior and fluid transport mechanisms combined with in situ upgrading of oil. The intention is not to only identify factors important to the modeling of these processes, but also find how robust simulation models can be developed to replicate observed field behavior. A semi-compositional approach, based on liquid–liquid equilibrium, is proposed to properly capture the asphaltene precipitation in thermal numerical simulators using direct lab measured data. Our analysis will be presented regarding upgrading mechanisms that should be implemented, their effect on the oil production rate, and techniques to model them.

PERFORMANCE EVALUATION OF TETRABUTYLAMMONIUM BROMIDE-BASED DEEP EUTECTIC SOLVENTS IN ENHANCED OIL RECOVERY OF NIGERIAN HEAVY OIL

Deep eutectic solvent (DES) is used as a green solvent in science due to its benefits over ionic liquids, such as biocompatibility and biodegradability, chemical stability with water, ease of preparation, and non-toxicity.DES 1 was successfully synthesized in a 1:2 molar ratio of Tetrabutylammonium bromide (TBAB) and polyethylene glycol 400 (PEG 400), while the novel DES 2 and DES 3 were synthesized in a 1:6 molar ratio of TBAB/ dimethyl sulfoxide (DMSO), and TBAB/N,N-dimethyl formamide (DMF) respectively. The performance(s) of the three DESs in the enhancement of heavy Nigerian crude oil recovery at ambient temperature was investigated. DES 1 recovered additional 16.07 % oil from core flooding using Berea sandstone core sample, resulting in an overall recovery of 53.44 %. DES 1 also resulted in an incremental recovery of 35.94 % from Niger-Delta sandstone, with a high ultimate recovery of 85.94 %. The presence of DES 2 and DES 3 were also shown to result in additional oil recovery. A drastic IFT reduction from 5.19 to 2.46mN/m was observed between the oil and the DES2 phase. Thus the study confirms that the presence of TBAB-based DES promotes reduction in the viscosity of the heavy oil and results in more oil recovery. Keywords: Deep eutectic solvents (DES), enhanced oil recovery, interfacial tension, tetrabutylammoniumbromide (TBAB)

Differential evolution for early-phase offshore oilfield design considering uncertainties in initial oil-in-place and well productivity

• Differential evolution optimization of number of wells, plateau rate and NPV. • Multi-objective optimization considering ultimate recovery factor and NPV. • The NPV distribution average can be estimated with the average of the variables. • Method provides decision support to field planners in early field development. During the early phases of offshore oil field development, field planners must decide upon general design features such as the required number of wells and maximum oil processing capacity (field plateau rate), usually by performing sensitivity studies. These design choices are then locked in subsequent development stages and often prevent from achieving optimal field designs in later planning stages when more information is available and uncertainties are reduced. In the present study, we propose using numerical optimization of net present value (NPV) to advice field planners when deciding on the appropriate number of wells, maximum oil processing capacity (plateau rate) in a Brazilian offshore oil field. Differential Evolution (DE) is employed for solving the optimization models. The uncertainties considered are well productivity and initial oil-in-place, handled by (1) using the mean of the distributions and (2) Monte Carlo simulation. A multi-objective optimization was also formulated and solved including ultimate recovery factor in addition to net present value. The proposed method successfully computes probability distributions of optimal number of wells, plateau rate and NPV. If one wishes to compute the mean of such distributions only, for most cases it is adequate to run an optimization using the mean of the input values instead of performing Monte Carlo sampling. The multi-objective optimization allows to find field designs with high ultimate recovery factor and high NPV. In this case, the value of NPV is similar to the optimum NPV value when optimizing NPV only. The methods described could provide decision support to field planners in early stages of field development.

Displacement behavior and mechanism of long-term water flooding in sandstone oil reservoirs

Sandstone oil reservoirs with huge bottom water and high permeability are generally developed with high flow rate. After long-term water flooding (LTWF), the water flooding characteristics are quite different from that of original reservoir. In this paper, the effects of the PV number, viscosity, and displacement rate during LTWF are studied through experiments. The mechanism is analyzed based on analysis of changes in oil composition, rock mineral composition and wettability. The oil-water relative permeability curves, oil recovery and wettability were obtained with new experiments methods, which avoids the oil metering error by measuring oil and water separately. The research indicates that when the viscosity increases, the water phase permeability decreases, the residual oil saturation increases, and the water content rate increases earlier. A higher water flooding rate results in a higher ultimate recovery. A higher asphaltene content results in a higher viscosity and more oil-wet reservoir conditions. After LTWF, the wettability tends to water-wet, which is more favorable for heavy oil recovery. Moreover, LTWF reduces the clay content, which creates a more water-wet surface and a larger reservoir pore throat environment. This research provides insightful characteristics of offshore sandstone oil reservoirs, which can be used to enhance oil recovery.

Effects of salinity and rock clogging on injectivity dynamics of flooding wells: Experiments, modeling and validation on field data

Injection of water into a rock formation is a common oilfield services technology to maintain high reservoir pressure and increase ultimate recovery of hydrocarbons. While flowing through the well from surface to the rock formation, injected water typically transports fine particles, for example, fine sand grains and calcite precipitated at surface pipeline conditions while mixing water from different sources (e.g., fresh, Cenomanian and formation brine). In the framework of the two-fluid approach to suspension flow modelling, we formulate mathematical model for linear filtration of a particle-laden suspension in the vicinity of a fractured flooding well and transport of ion concentration (salinity). Two major factors of well injectivity decline are described, namely, particle trapping with associated reduction in permeability and porosity of the rock as well as the effect of salinity of injecting water leading to clay swelling, calcite precipitation and change of relative permeabilities of the rock with respect to water and oil. We calibrate suspension filtration model against in-house experiments on clogging of artificial and natural rock cores, in which the profiles of fines concentration along the cores are obtained using X-Ray computed tomography and analysis of 3D rock reconstruction images. The water injection model is adopted to conditions of Priobskoye oilfield of Western Siberia by using the results of standard laboratory experiments on fluid-fluid (calcite precipitation) and fluid-rock (clay swelling, migration of internal fines) compatibility, as well as the effect of salinity on oil displacement and analysis of solid fraction in the injecting water. The calibrated model is then used to describe field data on dynamics of injection rate of three flooding wells. It is obtained that the simulations predict the long-term injectivity dynamics of the wells very well, while at early times (up to 5 months from the start of injection) the model underestimates the injection rate. While fitting the model to field data, we varied only two parameters, namely, solids concentration in the injecting water (in the range provided by lab experiments) and trapping coefficient (the range is limited to result of experiments made with target rock cores). It is demonstrated that only a combination of injectivity decline factors allows to describe the long-term flooding rate of the wells. Ignoring either particle trapping or salinity effects lead to significant overestimation (up to 50%) of the long-term injection rate. Parametric study of water injection showed that two-fold increase in solids concentration in the injecting water as well as oil compressibility lead to similar decrease in long-term injection rate of a well.

Optimization strategies and impact of low oil price on long term SAGD projects

AbstractSteam assisted gravity drainage (SAGD) has been known as a commercially proven high ultimate recovery process for bitumen and heavy crudes. It is an energy intensive process, which is economical when oil price is above certain value. When the oil price goes below the economic threshold of project, steam injection can be decreased or completely stopped for a certain period of time, and can resume thereafter when the condition alters. The objective of this study is to provide comprehensive information about the effect of steam injection interruptions on thermal project performance. An optimization strategy for the SAGD process, in cases where steam injection interruption occurs, is discussed using actual reservoir models of different geological formations. An economical model is used to evaluate operating strategy effect on the net present value (NPV) of the project. The parameters, like shut‐in period, initial steam injection period, etc, are optimized for Athabasca type oil sand reservoirs. The results show several key mechanisms exist in the life cycle of the SAGD process that must be included to reflect the field scale behaviour; otherwise, the mechanistic simplicity of the models could lead to directional and semi‐quantitative conclusions. Among the mechanisms, temperature effect on basic petrophysical properties of reservoir rocks was found to have an important role in the oil recovery, and considerably impacts the results of optimization. When the steam injection is interrupted, an optimum shut‐in period can be determined to maximize the oil recovery. The optimum length of steam injection interruption depends on the initial steam injection period.

A novel foam formulation by Al2O3/SiO2 nanoparticles for EOR applications: A mechanistic study

Abstract In this study, the influence of Al2O3/SiO2 nanoparticles (NPs) on the Cetyl Trimethyl Ammonium Bromide (CTAB) foam formation and stability is investigated for enhanced oil recovery (EOR). The optimum foaming concentration of CTAB in the presence of heavy crude oil was first determined via visual foam stability inspections for different CTAB concentrations. The results of these sets of experiments were used to find out an appropriate CTAB: Al2O3/SiO2 NPs concentration ratio for foam stabilization through spectroscopy measurements. Different static analyses, including zeta potential, contact angle, and interfacial viscosity measurements were conducted to support the observations in the porous media during flooding. Improved foam stability in the presence of crude oil was observed with Al2O3/SiO2 CTAB foam via electrostatic adsorption of positive CTA+ molecules onto the negatively charged NPs at the appropriate concentration ratio of CTAB: NPs. Contact angle measurements showed a similar glass wettability alteration from an oil-wet (155 ± 3°) to a water-wet condition (19–29°) for all blends of CTAB and Al2O3, SiO2, or Al2O3/SiO2 NPs. Foam/heavy crude oil interfacial viscosity measurements increased with the addition of NPs to the foam solutions, indicating an improved foam bubble deformability, viscoelasticity, and stability, which was consistent with the foam behavior in the porous medium. Oil displacement studies in the glass micromodel showed the highest ultimate and incremental oil recovery of 92% and 73% OOIP, respectively, for Al2O3/SiO2 CTAB foam injection in the dual permeability porous medium. Some new forms of conventional foam mechanisms in the porous medium were also observed during the injection of Al2O3/SiO2 CTAB foam, which are believed to be the possible reason for this high ultimate oil recovery. These results prove the efficient role of Al2O3/SiO2 NPs in enhancing the foam performance via synergistic effects of NPs and CTAB.

Effect of Pressure on Vapor/Oil Gravity Drainage in Fractured Reservoirs

Summary This fundamental research is part of a larger study in determining the capability of a solvent process, referred to as vapor/oil gravity drainage (VOGD), for enhancing gravity drainage of viscous oil in fractured reservoirs by the injection of solvent. The solvent can be designed to traverse the reservoir mostly in its vapor phase at the reservoir temperature and pressure. Heated solvent vapor can also be used to facilitate the propagation of solvent vapor in low-temperature reservoirs, taking advantage of both thermal- and solvent-recovery processes. The experimental setup and corresponding acquired data were previously introduced by the authors in Anand et al. (2018), in which the effects of temperature, solvent-injection rate, and solvent type [n-butane and dichloromethane (DCM)] were investigated. Results from Anand et al. (2018) indicated encouraging high oil rates and ultimate recoveries; results also demonstrated that the oil rates and recovery were affected by diffusion and dispersion (in the form of intrinsic gas rate), asphaltene precipitation, and capillary pressure. The intent of our present work is to further study the mechanisms behind VOGD—in particular, those related to operating pressure and solvent-vapor/oil capillary pressure. The results from this work show that the ultimate recovery and oil rate are positively correlated to the operating pressure; experiments conducted at 50 and 75% saturation pressure (Psat) yielded lower ultimate oil recoveries, ranging from 33 to 68% of original oil in place (OOIP), compared with the experiments conducted at 90% Psat (recovery of 70% OOIP). Moreover, n-butane performed better than DCM, and lower asphaltene precipitation was seen at lower Psat. The main drivers for these observations were found to be lower solvent solubility and larger capillary pressure values at lower values of Psat.

Can water-alternating-solvent injection be an option for efficient heavy-oil recovery?: An experimental analysis for different reservoir conditions

We performed a set of experiments on vertically situated sandpack models. Different slug sizes of water and solvent (heptane used in the experiments) were tested for 2000 cp heavy-oil. As a benchmark, tests were also performed for 14 cp light oil for comparative analysis. In addition to the technical feasibility, an economic analysis was performed considering the amount of solvent injected and oil and solvent recovered. Experiments were repeated for oil-wet systems. For both light and heavy oils, starting the process with the solvent was feasible in the short run technically and economically. If the process starts with water, excess amount of it occupies the largest pores and hinders solvent-oil interaction for mixing and oil displacement. This was true especially if the rock is oil-wet and oil is heavy, which yielded faster recovery and higher ultimate recovery than the water-wet case. The time for switching to solvent injection is more critical in the heavy-oil case as it is more sensitive to the amount of existing water in the system. As oil becomes heavier and if the rock is water-wet, starting the process with waterflooding is not suggested. In this case, more solvent needs to be injected in the first cycle compared to oil-wet systems. Due to partial miscibility and more gravity stable nature, solvent retrieval and sweep with water can be more effective in case of heavy-oil compared to light oil (fully miscible case) and, as a result, can be even more profitable. This is highly critical in exploitation of heavy-oil reservoirs if thermal options are limited and greenhouse gas emission is a concern.

Expandable proppants to moderate production drop in hydraulically fractured wells

Hydraulic fracturing is recognized as the primary technique to achieve economic oil and gas production from low permeability reservoirs like shale and tight-sand formations. One of the main challenges facing the oil and gas industry is maintaining the proppant functionality in the subsurface to guarantee a sustainable production rate and higher ultimate recovery. Proppant crushing and proppant embedment may diminish production from stimulated wells especially when bottomhole pressure is reaching low flowing pressures in soft and deep formations like Haynesville or Tuscaloosa Marine Shales. Experimental measurements and field observations have shown the strong impact of proppant stress and proppant embedment on reducing fracture conductivity. In this work, we introduce a novel material developed in order to achieve higher fracture conductivities at a minimum cost. The new type of proppants, so called "Expandable Proppants" (EP), is able to remotely control the expanding force and maintain the functionality of placed proppants. The presented proppants are made out of thermoset shape memory polymers which are activated by formation's in situ temperature to effectively maintain or even increase fracture's width. A fully coupled numerical model is developed to study the effectiveness of expandable proppants and evaluate fracture conductivity enhancement for different combinations and distributions of EP. In addition, a series of experiments were conducted in a modified API conductivity cell to verify the increase in fracture conductivity. Numerical and experimental results demonstrate that proppant expansion can increase the permeability up to 100%. Different conditions of confining stress and proppant sizes are studied to verify the optimum proppant design. This product can extend the lifetime of the fracture and ensure lasting production.

An experimental study to determine suitable injection strategies for water-alternating-solvent process in green and brownfields

Considering more than 50% of oil is left on average after primary and secondary methods in conventional reservoirs, techniques to recover the remaining oil from these proven and mature reserves is critically important to meet the future energy demand. One of the ways to achieve this is to inject miscible solvents (usually gas), which is performed in the form of water-alternating gas rather than continuous injection of this type of expensive material. In this case, the process should be optimally designed for slug sizes and proper sequences of the solvent considering several controlling parameters including past history of waterflooding (water content) and wettability.We performed a set of experiments on vertically situated sand pack models saturated with 14cp oil. Heptane was selected as the solvent phase due to high miscibility conditions. Tests were started with waterflooding or solvent injection. Different slug sizes of solvent and water were tested on fully oil-saturated water, oil-wet samples, and samples with connate water (10 and 30%). The amounts of oil and solvent retrieved were monitored using refractometer. Using the collected data, the recovery rates and ultimate recoveries were comparatively analyzed. In addition to the technical feasibility, an economic analysis was performed considering the amount of solvent injected, oil and solvent recovered, and time for recovery.Starting the process with heptane was technically and economically feasible (pay-out time is shorter) in the short run for both the oil- and water-wet cases. This was especially true if the rock were oil-wet, which yielded faster recovery and higher ultimate recovery. Excessive water injection (up to the plateau level) preceding the solvent injection in the oil-wet case resulted in lower recovery factor whereas this design was very effective in the water-wet case. Therefore, the time to switch to solvent injection was critical in the oil-wet case and a short initial cycle of solvent injection followed by short waterflooding cycle is suggested. In the oil-wet case, initial waterflooding resulted in an inefficient process; while it yielded high ultimate recoveries, the process time was longer than other injection options. In the water-wet case, a greater amount of solvent was needed in the first cycle.

Experimental study on imbibition displacement mechanisms of two-phase fluid using micromodel: Fracture network, distribution of pore size, and matrix construction

In this study, the effect of different parameters on the fluid transport in a fractured micromodel has been investigated. All experiments in this study have been conducted in a glass micromodel. Since the state of wetting is important in the micromodel, the wetting experiments have been conducted to determine the state of wetting in the micromodel. The used micromodel was wet by water and non-wet regarding normal decane. The fracture network, distribution of pore size, matrix construction, and injection rate are the most important parameters affecting the process. Therefore, the influence of these parameters was studied using five different patterns (A to E). The obtained results from pattern A showed that increasing water injection the flow rate results in both higher rate of imbibition and higher ultimate recovery. Pattern B, which was characterized with higher porosity and permeability, was employed to study the effect of matrix pore size distribution on the imbibition process. Compared to pattern A, a higher normal decane production was observed in this pattern. Patterns C and D were designed to understand the impact of lateral fractures on the displacement process. Higher ultimate recoveries were obtained in these patterns. A system of matrix-fracture was designed (pattern E) to evaluate water injection performance in a multi-block system. Injection of water with the flow rate of 0.01 cc/min could produce 15% of the oil available in the system. While in the test with the flow rate of 0.1 cc/min, a normal decane recovery of 0.28 was achieved.

A novel insight of laboratory investigation and simulation for high pressure air injection in light oil reservoir

Due to the precipitous dropping oil price, air injection becomes advantageous to other gas flooding techniques as a result of the low cost. Therefore, this work targeted a light oil reservoir and comprehensively investigated the potential of air injection in this reservoir using experimental and numerical simulation, from which some new insights into high pressure air injection were recognized. Oxidation kinetics of the crude oil were first established using Thermal Gravity Analysis (TG)/Differential Thermal Gravity (DTG), and further validated through a set of history matching. The results indicate that the intense oxidation reaction consumed a great volume of oxygen forming only CO2. Temperature peak occurred after reacting 23 h, revealing that the oxidation reaction is an exothermic process under reservoir conditions and spontaneous combustion might take place. Reservoir dip angle is a crucial parameter governing the oil production and updip injection is generally suggested. Earlier air injection leads to more noticeable incremental temperature effect and also higher ultimate recovery. Air injection seems notably appropriate for rhythm reservoirs. Given a mature reservoir, high-permeability zone would cause gas breakthrough and thus considerably detract the air injection performance. Temperature-resistant polymer gel or foam is suggested to plug thief zones promoting oxidation reactions and air sweep efficiency.

Efficiency of Steam-Over-Solvent-Injection-in-Fractured-Reservoirs (SOS-FR) Method Considering Oil Recovery and Solvent Retrieval: Core-Scale Experimentation

Summary Sole injection of steam or solvent into heterogeneous reservoirs usually yields an inefficient recovery performance. The steam-over-solvent-injection-in-fractured-reservoirs (SOS-FR) method was suggested as a solution to improve the efficiency of heavy-oil/bitumen recovery from fractured carbonates and oil-sands reservoirs after cold production (Al-Bahlani and Babadagli 2008). The method consists of three phases: Phase 1, where steam is injected at low temperatures to heat the matrix and condition the oil for subsequent solvent injection; Phase 2, when solvent-injection dilutes matrix oil by diffusion and enhances gravity-drainage recovery rate; and Phase 3, when low-temperature (at approximately the boiling point of solvent) steam injection retrieves the solvent diffused into matrix. Previous research was focused on the effectiveness of Phases 1 and 2 of the method (Al-Bahlani and Babadagli 2009a, b), and positive responses were reported at the field scale (Al-Bahlani and Babadagli 2010) with high ultimate recoveries. The efficiency of this process, however, is determined purely by the amount of solvent retrieved at the end of the process. This paper, therefore, focuses on Phase 3, which is performed mainly for solvent retrieval (additional oil is also produced during this phase). Twenty-two static core experiments were performed on water- and oil-wet sandstone and limestone. After saturating the rock samples with different heavy oils, they were immersed into different liquid solvents--hexane, heptane, decane, and diluent oil. Diluent oil used in this study is a distillate that was obtained from a heavy-oil-upgrading unit in Canada. Once the ultimate recovery was achieved by diffusion and gravity drainage (Phase 2), the samples were exposed to different temperatures of hot water (Phase 3) and the amount of solvent retrieved was measured through volumetric and weight measurements and refractometer readings. The retrieval of solvent diffused into matrix was caused mainly by two reasons: (1) evaporation of solvent at elevated temperature and (2) imbibition of hot water into rock (if oil-wet samples become more water-wet during Phase 2). The amount of solvent retrieved through these processes was determined, and the efficiencies were analyzed for different parameters, including rock wettability, oil viscosity, solvent type, solvent-soaking period, rock type, boundary conditions, different combinations of steam/solvent cycle, and temperature applied.

Experimental study of enhanced oil recovery with CO2 slug+N2 flood in low permeability reservoir

Gas injection has become a significant enhanced oil recovery (EOR) measure to develop low permeability reservoirs. CO2 injection can achieve miscible displacement, but its cost is relatively high and CO2 is corrosive. N2 injection is cheap, but it is difficult to achieve miscible displacement in the formation with a limited EOR efficiency. Based on these problems, a feasibility analysis of CO2 slug+N2 to boost the recovery in low permeability reservoirs is studied through experiment. In this paper, with slim-tube test and core flood experiment, an analysis of minimum miscibility pressure, recovery of different gas injection scheme, and sensitivity of oil displacement efficiency of CO2 slug+N2 are obtained. The results show that the scheme of CO2 slug+N2 gets low miscibility pressure and can achieve miscible displacement with high ultimate recovery approximate to the scheme of continuous injection of CO2. Besides, injection timing, slug size of injected CO2, and formation pressure recovery before CO2 slug injection greatly influence the ultimate recovery. This study is significant for the understanding of EOR mechanism of CO2 slug+N2, optimization of injection parameters, and associated numerical simulation in low permeability reservoirs.

Miscible and Immiscible Foam Injection for Mobility Control and EOR in Fractured Oil-Wet Carbonate Rocks

Foam injection is a proven enhanced oil recovery (EOR) technique for heterogeneous reservoirs, but is less studied for EOR in fractured systems. We experimentally investigated tertiary \(\text {CO}_{2}\) injections, and \(\text {N}_{2}\)- and \(\text {CO}_{2}\)-foam injections for enhanced oil recovery in fractured, oil-wet limestone core plugs. Miscible \(\text {CO}_{2}\) and \(\text {CO}_{2}\)-foam was compared with immiscible \(\text {CO}_{2}\)- and \(\text {N}_{2}\)-foam as tertiary recovery techniques, subsequent to waterfloods, in fractured rocks with different wettability preferences. At water-wet conditions waterfloods produced approximately 40 % OOIP, by spontaneous imbibition. Waterflood oil recovery at oil-wet conditions was below 20 % OOIP, due to suppressed imbibition where water predominantly flowed through the fractures, unable to mobilize the oil trapped in the matrix. Tertiary, supercritical \(\text {CO}_{2}\)-mobilized oil trapped in the matrix, particularly at weakly oil-wet conditions, by diffusion. Recovery by diffusion was high due to small core samples, high initial oil saturation and a continuous oil phase at oil-wet conditions. Both immiscible \(\text {CO}_{2}\)- and \(\text {N}_{2}\)-foams and miscible, supercritical \(\text {CO}_{2}\)-foam demonstrated high ultimate oil recoveries, but immiscible foam was less efficient (30 pore volumes injected) compared to miscible foam (2 pore volumes injected) to reach ultimate recovery. This is explained by the capillary threshold pressure preventing the injected \(\text {N}_{2}\) gas from entering the matrix, verified by computed X-ray tomography, and the mobilized oil was displaced by the aqueous surfactant in the foam. At miscible conditions, there exists no capillary entry pressure between the oil-saturated matrix and the injected \(\text {CO}_{2}\), allowing foam to invade the matrix for efficient oil recovery.

New Cold-Production Technique for Heavy Oil With Strong Bottomwaterdrive

Summary Few heavy-oil reservoirs with strong bottomwaterdrive have been developed successfully, because severe water coning causes low ultimate recovery, low well productivity, and high water production. In these reservoirs, thermal and gravity-assisted methods that could improve recovery are perceived as economically unfavorable or technologically infeasible. In this paper, we propose a new cold-production technique, called the bilateral water sink (BWS), to meet those challenges. The BWS method suppresses water cresting by producing oil and water simultaneously from bilateral horizontal wells completed in the oil and water zones separately. Unlike conventional horizontal-well production, where water cresting causes water to bypass oil, making the waterdrive mechanism ineffective, the BWS prevents water cresting by altering the potential distribution in the near-well region. With cresting suppressed, water drives the oil from the edges of the well drainage area to the well, resulting in high ultimate recovery. By exploiting the natural reservoir energy of the bottomwaterdrive, the BWS becomes economically, technically, and environmentally appealing—especially for offshore fields where cold production is the only option and oil/water separation is a problem. In this paper, new analytical models are derived to design the water and oil rates for the BWS and to quantify the method's effect of avoiding water cresting and improving oil recovery. The analytical models are verified with numerical simulations. The BWS technique is also theoretically demonstrated by use of data from an actual oil field. The results show a considerable increase of oil recovery, from less than 15% for a conventional horizontal well to approximately 40% for a BWS well.

Decade of Stimulation Experience in the Deepwater Gulf of Mexico

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 159660, ’A Decade of Deepwater Gulf of Mexico Stimulation Experience,’ by Lee N. Morgenthaler, SPE, and Leigh A. Fry, Shell E&P, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-10 October. The paper has not been peer reviewed. The deepwater Gulf of Mexico is a technically and economically challenging production environment. High rates and ultimate recoveries are required per well to offset high development costs. Stimulation treatments maintain wells at peak production rates and accelerate reserves recovery. In these complex layered reservoirs, stimulation is necessary to ensure recovery volume. The primary objective of stimulation is to restore impaired well/reservoir connectivity. Successfully identifying the cause and location of impairment is required. Looking back over a decade of experience in this challenging environment yields useful insights as the industry moves into new deepwater provinces. Introduction Shell’s deepwater development began in 1991 with the Tahoe subsea prospect tied back to the Main Pass 252 platform. Development continued with the Auger, Mars, Ram Powell, Ursa, and Brutus tension-leg platforms (TLPs) and many subsea fields that tie back to them (Fig. 1). Most of the reservoirs producing to these structures are geologically young turbidite sands that require sand control. Initially, all of the fields were geopressured significantly above hydrostatic and were significantly undersaturated. The soft compacting sands and aquifer support often provide sufficient energy to achieve adequate recovery by depletion. The hydraulic fractures created in the frac-pack process provided lower skin values with minimal use of acid. The horizontal openhole gravel packs used acid-soluble bridging agents to stabilize the wellbore during gravel packing. The bridging agents were then removed with acid washing. Because most of these sand-control completions were cased-hole gravel packs or cased-hole frac packs, most of this paper refers primarily to the experience with those completion types. As the fields matured, there were more subsea-tieback developments. Stimulation campaigns generally focused on the direct-vertical-access (DVA), or dry-tree, wells of the TLPs. However, stimulation of subsea wells has been highly profitable, and technology has been developed to reduce the subsea-intervention costs to make these interventions more attractive. The complex operations on TLPs introduce challenges when planning and conducting stimulation operations. Logistics coordination and proper management of returning wells to production are critical to realize production gains and to meet environmental-discharge regulations and goals.

Technology Focus: Production Operations (March 2012)

Technology Focus At the 2011 SPE Annual Technical Conference and Exhibition in Denver, there were many interesting discussions on shale-gas (and/or liquid-rich) resources. While already an important part of the industry, we are just beginning to identify some of the challenges with these resources and how best to deal with them. With hydraulic fracturing being an integral part of these operations, one area of focus is how to optimize the well geometry and the fracturing treatment to achieve long-term production and high ultimate recovery. Nevertheless, two other key considerations concern where to obtain the huge volumes of water that are required for these fracturing jobs, and what water treatment is required to ensure a safe and problem-free operation. With the need to rely less and less on fresh surface water to minimize the environmental effects, operators have been forced to explore other options, including finding suitable aquifers and/or water-recycling technologies. Some of the papers featured in this issue (or listed as additional reading) illustrate some of these challenges and how companies are trying to address them. During this last year, we also saw an increase in the use of inflow-control devices in conjunction with horizontal wells in a variety of applications throughout the world. One of the most interesting developments is that of the so-called “autonomous” devices, which should be capable of adjusting themselves on basis of the type of fluid flowing through them (i.e., applying more choking to less-viscous fluids such as water and gas). There also have been interesting advancements in sandface-monitoring systems, as illustrated in two of the papers in the reading list. Recommended additional reading at OnePetro: www.onepetro.org. SPE 144032 A Novel Screening Method for Selection of Horizontal-Refracturing Candidates in Shale-Gas Reservoirs by Shekhar Sinha, SPE, Schlumberger, et al. (See JPT, November 2011, page 102.) SPE 147264 Shale-Gas Water-Treatment Value Chain—A Review of Technologies, Including Case Studies by Patrick Horner, Aqua Pure Ventures, et al. SPE 145737 The Autonomous RCP Valve—New Technology for Inflow Control in Horizontal Wells by Vidar Mathiesen, Statoil ASA, et al. SPE 147439 Fiber-Optic Strain Sensing at the Sandface Enables Real-Time Flow Monitoring and Compaction Mitigation in Openhole Applications by Denise M. Earles, SPE, Baker Hughes, et al. SPE 145581 Ormen Lange: Delivering Production Optimization and an Improved Reservoir Understanding Using a New Cableless Sandface-Monitoring System by B.P. Champion, SPE, Expro, et al.