A waterflood study has been performed on a high viscosity saturated oil deposit with bottom water aquifer and complex geometry driven by regional tectonic stress and numerous shale breaks. The commercial production is on-going for the last 2 years with medium length (1,000 m) horizontal wells and start facing formation pressure decline. The foremost challenge was to check if injection pressure is transmitted through the oil pay without leaking into the bottom water aquifer. The next question was whether the full net pay is engaged in pressure support under water injection. The last question was to check on permeability anisotropy. The transmissibility between wells have been assessed with multi-well retrospective testing (MRT) of permanent downhole gauges (PDG) historical data records which are a part of standard ESP telemetry. The fluid mobility and hydrodynamic average thickness between water injector and oil producers have been estimated with cross-well pulse-code pressure pulsations (PCT) based on pre-designed rate variation sequence [ 1 – 8 ]. The pulse-code sequence was designed in full-field 3D dynamic model to ensure capturing response in two contrast scenarios: with pressure propagating via aquifer and via oil pay, which have a high degree (30:1) of fluid mobility contrast. The data processing and interpretation was performed in PolyGon™ software [ 18 ] using the pulse-code decomposition for PCT tests and multi-well deconvolution for MRT tests. The cross-well mobility in injector-producer pairs from PCT was indicating that pressure was fairly propagating via oil pay. The effective thickness of PCT-scanned area turned to be in-line with net oil column thickness from 3D geological model. The MRT-scanned area was showing much lower transmissibility than 3D geological model prediction which was interpreted as the most part of the oil pay in this area has intermittent connectivity due to severe shale breaks development. This gives strong indication on searching the way to commingle production from isolated reservoir elements in this area [ 8 – 14 ]. The areal analysis of permeability in PCT-scanned and MRT-scanned areas has indication for 1:2 permeability anisotropy transversal to the regional stress direction which should be reconfirmed by a dedicated study.

Wettability contact angle characterization will be investigated by 2D technologies and a deterministic model is developed. Deterministic approach is a robust technique using 2D image capturing and image analyses that are applied on a Kuwaiti silty sandstone reservoir to accurately quantify, mathematically as well as physically, wetting contact angle trends in the rock sample. And, then, generate all possible pore contact angles. Wettability contact angle quantification utilizes imaging method and recovery model with deterministic systems is a novel approach. Prediction of recovery schemes is crucial for reservoir development and management. Since contact angle initial state is captured and well described, measurement will no longer be random or follow stochastic solution. In this study, heavy oil recovery prediction model is also developed by constructing mathematical model based on statistical grouping and averaging for all measured pore-walls available in the rock sample. Pore parameters such as pore-area, pore-count, and pore-wall and pore shape distribution are all captured and measured experimentally and data can be accurately generated. Previously, contact angle is always based on linear assumptions and its direct quantification is vaguely established. In this study, quantifying wetting contact angle follows morphological approach that has greater confidence.

Preformed Particle Gels are successfully used for profile control in heterogeneous reservoirs. However, it is still unclear how to select proper PPG size for a given heterogeneous reservoir. In order to obtain the best profile control performance, it is necessary to study the matching relationship between the PPG mesh and the permeability ratio. In this paper, the heterogeneous parallel-dual-sandpack experimental setup is established, including the injection system, measurement systems for temperature and pressure. During the experimental processes of water injection, PPG injection and subsequent water injection, the fractional flow of the two sandpacks with high and low permeability are recorded respectively. Then, a quantitative characterization parameter of the profile improvement ability is defined by dividing the change of fractional flow of the low permeable sandpack before and after PPG injection by that of low permeable sandpack before PPG injection. The experimental results show that different PPG meshes will achieve different profile control performance for the heterogeneous sandpack with the determined permeability ratio. The PPG with excessive large size may block the low permeable area, decrease its fractional flow and thus cause more severe flow heterogeneity. The PPG with excessive small size can not well block the high permeability area and they can migrate out during subsequent water injection resulting in the increase of fractional flow in high permeable area again. The matching relationship analysis show that the matched PPG mesh increases as the permeability ratio of the heterogeneous sandpack increases. In detail, the matched PPG sizes for the permeability ratio of 2, 4, and 6 are 120-150 mesh, 100-120 mesh and 60-80 mesh, respectively. The paper studied the matching relationship between PPG size and permeability heterogeneity, which was beneficial for selecting the proper PPG size for different heterogeneous reservoirs in more future applications.

Surfactants play an important role in the widely used enhanced heavy oil recovery methods such as surfactant-polymer flooding and alkali-surfactant flooding. In this study, we focus on the effects of surfactant during surfactant flooding and provide a pore scale simulator of surfactant flooding based on the Lattice Boltzmann (LB) method. We introduce a dipole to present the amphiphilic structure of surfactants in the Lattice Boltzmann model, and characterizes microscopic fluid interactions at the kinetic level. There are three velocity distribution functions to present the oil, water, and surfactant species, and every distribution follows the discrete Boltzmann-BGK equation. There is also an additional dipole vector representing the orientation of amphiphile, so that the interactions related with surfactants depend not only on particle relative distances but also on their dipolar orientations. The simulation results show that surfactants can reduce the oil-water interfacial tension and recover more oil trapped by capillary force. Moreover, surfactants are able to emulsify the flooding system, forming O/W emulsions or bi-continuous micro-emulsions. Higher surfactant concentration leads to smaller oil droplets in emulsions. In addition, the phase distribution morphologies in porous media are much different in different wetting conditions. By associating the fluid-solid interfacial tension with the surfactants adsorption concentration on walls, we characterize the wettability alteration mechanism in LB model accurately. The oil recovery can be improved by changing the wettability from oil-wet to water wet, increasing the surfactant concentration, and enhancing the adhesion parameters. However, the adsorption onto walls leads to unnecessary waste and could decrease the surfactant concentration in bulk phase. The study provides an effective pore scale tool to simulate the surfactant involved interfacial flows in porous media. In addition, we can use it to study the flow mechanisms and remaining oil distributions during surfactant flooding.

There are ongoing efforts to assess the techno-ecnomic viability of surfactant polymer (SP) flooding to increase oil recovery by improving microscopic and macroscopic sweep efficiency. This paper sheds light on a methodology to design an appropriate SP formulation for potential deployment in the Ratqa Lower Fars (RQLF) heavy oil reservoir in Kuwait. Besides achieving low residual oil saturation due to SP flooding under typical RQLF reservoir conditions, this study focuses on mitigating surfactant retention. Several injection strategies were investigated using alkali, adsorption inhibitors and a variety of water treatment techniques. For each scenario, a specific SP formulation was designed and evaluated through static adsorption tests using crushed reservoir rock. The two most promising options were then evaluated through coreflood experiments. The best option was selected based on in-depth chemical propagation, oil desaturation and surfactant adsorption. Finally, lab-optimization work was performed through additional corefloods to reduce chemical consumption while maintaining favorable oil recovery. Softened seawater obtained through reverse osmosis was considered as the most appropriate water source to implement the desired SP process. Previous work revealed that the use of unsoftened seawater results in high levels of surfactant adsorption on reservoir rock. Salt addition allows applying an efficient salinity gradient post SP injection. Sodium chloride was used instead of alkali which did not exhibit any benefit in this case. A particular effort was made to reduce the amount of added salt and the corresponding formulation cost. Several injection sequences were investigated to compare polymer and SP flooding. The final coreflood experiment based on SP injection (0.6 PV of surfactant at 4 g/l), followed by a salinity gradient, and involving a polymer drive recovered 80% of the original oil in place. The promising performance of this injection sequence will be further evaluated using the results from a one-spot EOR pilot. This EOR study on the RQLF shallow heavy oil reservoir in Kuwait provides important insights to select an appropriate surfactant-polymer injection strategy to increase oil recovery while maintaining reduced adsorption levels, thereby improving SP techno-economic viability.

One of the EOR technologies is low-salinity water flooding (LSWF) is an EOR method that operates at a lower cost than other EOR methods, which makes it a preferred area of interest for oil industry economists, who continue to call for EOR costs to come down. The aim is to minimize the possible cost to recover as much oil as possible. The performance of low salinity waterflooding in decreasing residual oil saturation in low permeability- porosity clay-rich sandstone reservoir. Porosity test, core flooding test, XRD and scanning electron microscopy (SEM) tests were achived in this study. Salinity effect on the porosity, oil recovery, and injecton pressure was established. The results showed that low salinity waterflooding resulted in improving oil recovery and porosity with permeability reduction and decreased the clay content. SEM results results showed that the flowing direction will be restributed during low salinity waterflooding by realizing some sand particle and minerals and increased the porosity. Therefore, low salinity water flooding can modify both porosity and permeability and, in turn, improve oil recovery factor.

Low salinity (LS) water flooding is a promising EOR method which has been examined by many experimental studies and field pilots for a variety of reservoirs and oils. This paper investigates applying LS flooding to a heavy oil. Increasing the LS water temperature improves heavy oil recovery by achieving higher sweep efficiency and improving oil mobility by lowering its viscosity. Steam flooding projects have reported many problems such as steam gravity override, but override can be lessened if the steam is is alternated with hot LS water. In this study, a series of reservoir sandstone cores were obtained from Bartlesville Sandstone (in Eastern Kansas) and aged with heavy crude oil (from the same reservoir) at 95°C for 45 days. Five reservoir cores were used in this study, and five treatments were performed. They were flooded with (a) steam; (b) formation hot water (FHW); (c) low salinity hot water (LSHW; (d) steam + FHW; and (e) steam + LSHW (so-called LSASF). The laboratory experiments showed that basic water flooding using FW recovered approximately 50% of OOIP. After that initial flood, upon switching to the various steam, FHW, LSHW, steam + FHW, and steam + LSHW treatments, the incremental oil recoveries were 5, 3.1, 6.3, 7.5, and 12% OOIP, respectively. The contact angle measurements showed that injecting steam + LSHW alters the wettability considerably more than using steam + FHW. The results of this work show that water flooding using LSHW in reservoir cores could improve oil recovery significantly because it both reduces oil viscosity and alters the rock wettability towards more water-wet. The results also showed using LSHW alternated with steam is more beneficial than using steam only or alternated with regular water due to the combined benefits of reducing gravity override and altering the wettability. Using LSHW water is more economical than using steam and gives significantly improved oil recovery, and using LSHW is more beneficial than ambient temperature LS water.

This study presents an assessment of heterogeneity on vertical and areal scales and discusses the development of methodology for a proposed waterflood scheme in a heavy oil field in Northern Kuwait. The field produces average 15° API crude of 50-100 cp at 100° F. The field has a complex geologic and stratigraphic architecture, and the associated reservoirs are highly heterogeneous in nature. Both numerical simulation and analytical models were used to assess the performance of the proposed waterflood. Vertical and areal heterogeneity of the oil bearing formation were evaluated using Dykstra-Parsons coefficient, Lorenz coefficient and coefficient of variance methodologies. Both numerical simulation and analytical models were deployed to evaluate the waterflood performance under 5-spot and inverted 9-spot patterns for 20 and 10 acre spacing. An analytical excercise was carried out as a pre-check for the expected waterflood recovery factors. Results from all three methods of heterogeneity assessment indicated the existence of a highly heterogeneous reservoir with average Dykstra-Parsons coefficients being greater than 0.8. A heterogeneity distribution map shows strong presence of areal heterogeneity. Ratio of the injectors to producers, pressure depletion schedule and associated recovery factors for planned pattern configurations were assessed from numerical simulation. Pattern by pattern heterogeneity indices were estimated and attempted to correlate to predicted flood performances. This work highlights the impact of heterogeneity on the waterflood performance for a heavy oil reservoir to assess a more realistic production target, with integrated results from analytical and numerical methodologies.

Waterflooding with different inonic composition called advanced ion management which play a role with ionic composition of injected water to enhance the oil production. In the last decate, many studies pointed out that the composition of injected water could changes rock wettability during waterflooding. The main purpose of this study is to evaluate the effects of SO4 and low salinity water on improving oil recovery in oil-wet carbonate reservoirs. Sulfate ion concentration, low salinity water, rock composition, porosity, and permeability were examined using a designed model. Typical seawater, increase SO4, two and three times in the seawater, and low salinity water that had been diluted 10 and 100 times were applied as waterflooding processes with three different average matrix permeability. Oil recovery factor improved as sulfate ion concentration increased and water salinity decreased by changing core wettability with greater water-wet conditions. Morover, the diluted seawater has more effect than sulfate ion concentration when a carbonate core has a few percentage of silica. Sulfate ion concentration performance increased with porosity and temperature, and the dilute seawater showed more effect at high temperature. Increased sulfate ion concentration followed by diluted sea water with present silica in the core composition might be a viable technique to improve oil recovery in the carbonate reservoir. The experimental results validated by field-scale simulation study and provides deep insight into understanding of advanced ion management performance.

This paper presents the results of a multi-scenario approach that involves the simulation of chemical EOR processes (polymer- and surfactant-based) for the Ratqa Lower Fars heavy oil (200-1000 cP) field in Kuwait, in order to evaluate the viability of implementing an appropriate chemical EOR strategy. Both technical and economic results are discussed. The approach used involves the simulation of various chemical EOR scenarios (injection of chemical slugs with different durations and concentrations) using several wells patterns (inverted 5-spot, inverted 9-spot, inverted 7-spot with vertical wells, line-drive with horizontal wells) covering various sizes in terms of area. Preliminary simulations of depletion and waterflooding scenarios were also conducted, as base cases to be compared to. Hundreds of EOR scenarios were hence simulated and compared using economic indicators such as the final recovery factor and the cost of chemicals per additional barrel of oil produced, compared to the waterflooding base case scenario. The analysis of the different simulated scenarios shows that due to injectivity issues (low maximum injection pressure to prevent the shale cap rock from being fractured), inverted patterns (inverted 9-spot and especially inverted 7-spot) had to be considered to enhance overall performance and reach promising recovery factors using chemical EOR methods. It is also shown that the impact of the pattern area for the same pattern type (inverted 7-spot configuration) is of paramount importance to the final recovery factor obtained after a fixed simulation duration (20 years in the present case). While the overall efficiency of each EOR process - in terms of recovery factor as a function of the injected solution expressed in pore volume - is kept similar when varying the pattern area, the pattern size is directly linked to the final recovery. Indeed when the pattern area is increased, a smaller volume (in terms of pore volume) of chemical solution can be injected in a fixed timeframe. Finally, the use of simplified economic indicators allowed comparing different EOR processes (polymer and surfactant-polymer) and potential patterns in order to find the most promising configuration in preparation for field implementation. The proposed approach is new as it presents and discusses for the first time the results of a detailed simulation study to evaluate the potential application of chemical EOR processes at the Ratqa Lower Fars heavy oil field in Kuwait. The results of this study are promising and clearly demonstrate the potential applicability of chemical EOR processes in similar heavy oil reservoirs.

CO 2 injection has been used for several decades as a successful recovery method in enhanced oil recovery. The main impact of CO 2 is on lowering minimum miscibility pressure. However, the unfavorable mobility of CO 2 force us to use CO 2 with other methods such as water alternating gas to minimize this effect. Low temperature CO 2 injection may cover the role of the water and other fluids in this process. The injection of CO 2 at low temperatures open a unique opportunity to investigate the potential for usage of low temperature CO 2 as an enhanced oil recovery method. In this study, the effect of low temperature injection in a high temperature system is evaluated. Earlier studies suggested that this method could be beneficial. However, it is not verified by core flooding experiments. If proven effective, the usage of CO 2 would add its advantage along with its current huge economic and environmental advantages against other EOR methods. The results show that injection of low temperature CO 2 has a direct impact on recovery factor inside a high temperature system. The main outcome of this study is the proof for the effectiveness of low temperature CO 2 usage as early as a reliable secondary recovery method in macro scale without any major unfavorable effects such as early breakthrough and gravity override. This study provides an economic way to increase the recovery while minimum modifications of available techniques are needed. No chemical agents were used as the production cost should be minimized. In addition, this study provides the ability for CO 2 storage which also favors other conventional methods in terms of CO 2 emission.

This paper will present a field case study to clean out wellbore organic deposits using a high flash point emulsified solvent system. Wellbore organic deposition was present in a horizontal water injector, Well-X, at 140 feet (ft.). The water injector is a pilot well completed above a tar mat formation to provide reservoir pressure maintenance. The wellbore deposits have restricted wellbore accessibility and caused loss of injection potential. Downhole samples from the obstructing material were collected from the wellbore using a wireline bailer. The samples were analyzed in the laboratory using solvent extraction and infared spectroscopy. The downhole samples were found to be comprised mostly of maltene which was present in the form of saturates, aromatics and resins at varying weight percentages. The organic deposits also contained asphaltene. The wellbore organic materials underwent extensive solubility testing at a simulated downhole temperature. Several solvent systems were evaluated such as xylene in diesel and aromatic solvent systems. Based on the performance of the dissolution systems in terms of solubility and soaking time an emulsified solvent system comprising n-methylpyrrolidone, fresh water, emulsifier, and an aromatic solvent was chosen for field deployment. Other factors such as chemicals hazards and cost were also considered as part of the treatment fluid selection process. The treatment fluid deployment was carried out using both the bull heading and coiled tubing (CT) techniques to ensure full exposure of wellbore organic deposits to the emulsified solvent system. The treated deposit solutions were flowed back using zero discharge system and their organic contents were inspected periodically. The field treatment design, job execution, contingencies, and what-if scenarios will all be discussed in this paper.

The synergy between various enhanced oil recovery (EOR) processes has always been raised as a potential optimization route for achieving a more economic and effective EOR application. In this study, we investigate the possible synergy between polymer and SmartWater flooding. While the potential for such synergy has been suggested and researched in the literature, we investigate this possibility in a more realistic framework—part of the development of an EOR portfolio for a slightly viscous Arabian Heavy reservoir. In this work, we study the possible synergy between SmartWater and polymer flooding by performing rheological, electrokinetic (Zeta) potential, contact angle and displacement experiments. Rheological tests as expected demonstrated the possibility of achieving the same target viscosity at lower polymer concentrations. With SmartWater, the polymer concentration required to achieve a target viscosity of 11 mPa.s was found to be one-third lower than that with normal high salinity injection water. Electrokinetic potential and contact angle results demonstrated that polymer presence has a negligible to slight yet favorable impact on wettability alteration induced by SmartWater. On synthetic calcite surfaces, polymer showed negligible impact while on rock surfaces polymer resulted in a further reduction in contact angle beyond that obtained with SmartWater. Coreflooding experiments conducted at reservoir conditions with finite SmartWater/polymer slugs demonstrated the enhanced performance of SmartWater/polymer compared to either of these individual processes besides yielding comparable performance to surfactant/polymer flooding. A combined SmartWater/polymer process was able to recover substantial additional oil (6.5 to 9.9% OOIC) above that obtained with either of the two processes when applied independently. Ultimate recoveries from the application of SmartWater/polymer (70% OOIC) were quite comparable to – actually slightly higher than – that of surfactant/polymer (67% OOIC). However, in terms of the remaining oil in core (ROIC) post polymer flooding, both processes (SmartWater/polymer and surfactant/polymer) exhibited quite similar incremental recoveries of 20.6 and 20.5% OOIC, respectively. The results of this work clearly demonstrated the potential synergy between SmartWater and polymer flooding – beyond that of the well-established polymer viscosity enhancement – for a realistic scenario. The additive effect of SmartWater was successfully shown to combine with polymer to increase oil recovery, in addition to lowering the polymer concentration. Therefore, this favorable synergy will reduce chemical consumption and costs and improve recovery and returns to enhance EOR project economics for the slightly viscous Arabian heavy oil reservoir considered in this study.

Voidage replacement is a key element in displacement processes, not only for keeping the reservoir pressure at its initial level but also in mitigating surface subsidence in certain fields. Despite its simple definition, it is a complicated process in reservoir management because of uncertainities involved and lack of all required measurements due to economical or technical restrictions. Thus, every single decision parameter and their relative significance in voidage replacement process is important for robust reservoir management. In general, voidage replacement is achieved where injection is based on production. This study investigates the case of triggers where the production rate at the bottom hole conditions is predicated on the bottom hole flowing conditions or reservoir gas injection rate. A full-physics commercial reservoir simulator is coupled with robust optimization software, where a miscible flood operation is modeled with a group bottom hole flowing target coupled with voidage replacement gas and water injection targets. The simulation results of this realistic case is presented in a way to show the relative significance of each operational parameter, which is outlined with tornado charts to serve as a guide in decision making in efficient reservoir management where voidage replacement is a crucial component. It is observed that triggers help to better manage voidage replacement, especially in large reservoirs where reservoir surveillance is a challenge due to number of wells and patterns. The results can be scaled up to different size of reservoirs and patterns with similar recovery processes. This study scrutinizes the feasibility of a reversal of the typical scenario where injection is based on production. Thus, it serves as a useful and realistic example for efficient reservoir management through optimization of voidage replacement through triggers for production rate.

GUPCO (Gulf of Suez Petroleum Company) is the pioneer in Egypt and Middle East in applying conventional waterflooding projects fas a secondary recovery method, Starting from Morgan field, Ramadan, October and July field by injecting into different reservoirs such as Lower Rudies, Upper Rudies and Cretaceous. These successful examples have been done and still running to recover greater amount of oil utilizing more advanced techniques like BrightWater and LoSal. The Heavy oil block in July field which is located in the Gulf of Suez (GoS) was discovered in Jan. 1986 by appraisal well J53. Many tests were performed to get the extension, characteristics of the reservoir and the hydrocarbons as well. It was found that the API gravity of oil is 19 degree. Using Numerical Simulation, we could define different scenarios of depletion plans to maximize the recoverable oil, and hence a decision was taken to start and implement the optimum scenario. This paper will discuss different scenarios and the selected optimum depletion plan, and comparing between the forecast from the model versus the actual achievement addressing production performance, reservoir rock characteristics, Data gathered and surveillance plan for the reservoir since May 1996 followed by water injection using dual string completion in December 1996. The paper is a good example as a case study for the value of using the technology of 3D modeling to maximize the recovery from challenging reservoir like heavy oil reservoirs in addition to proving that waterflooding has successfully improved the recovery of 19 API degree oil in July field.

In this paper, techniques have been developed to experimentally evaluate performance of CO 2 injection in heavy oil reservoirs for pressure maintenance purpose. More specifically, a three-dimensional (3D) physical model consisting of five vertical wells and three horizontal wells is used to examine effect of well configurations on pressure maintenance and oil recovery with CO 2 injection in heavy oil reservoirs. The initial oil saturation, oil production rate, water cut, gas-oil ratio, ultimate oil recovery, and distribution of residual oil saturation are examined under various well configurations, which can be optimized to maximize heavy oil recovery when CO 2 injection is employed for pressure maintenance purpose. The well configuration with a horizontal producer plus four vertical injectors is found to achieve a better performance than the conventional five-spot well configuration, while the oil recovery is experimentally determined to be 15.7% of OOIP during CO 2 injection process.

Accumulated field empirical observations suggest that water injected to displace heavy oils forms in the reservoir channel-like communication paths from the injectors to the producers. The evidence comes from mass balances and, more recently, from 4D seismic monitoring of heavy oil waterfloods. The reasons for this are multifold, including unconsolidated sand formation dilation about injectors due to slow pressure diffusion in heavy oils, reservoir heterogeneities in permeability and saturation, sand production from the reservoir, and the instability of the displacement interface due to the high mobility ratio between water and heavy oil. Once formed, the channels can degrade further economic recovery of the heavy oil as the water oil ratios increase significantly. This study reports on initial results from a laboratory program to test the optimal reservoir management response upon formation of such communication paths in heavy oil waterfloods. To physically simulate reservoir waterflood behavior under the existence of a communication path, a large scale ‘big can’, five feet long with a ten inch by ten inch cross section, was designed and constructed that allowed for the creation of a highly reproducible communication path from the injection to production end of the can. This was a mandatory requirement for accurate comparison between alternative reservoir management strategies whose differences would otherwise be hidden by variations in random communication path formation. The design has proven to be highly successful. Our first objective was to test whether the industry paradigm and the regulatory mandated practice of maintaining a voidage replacement ratio (VRR) of one throughout the entire waterflood is optimal. Live 18.6 API Alaska North slope oil was used to saturate four Darcy sand that filled the big can. Upon creation of the communication path, three VRRs were tested: 1.0 (conventional waterflood), 0.7 (hybrid waterflood/solution gas drive), and 0.0 (conventional solution gas drive). The VRR=0.7 run outperformed the conventional VRR=1.0, suggesting that periods of under injection may improve heavy oil waterflood response upon formation of injector-producer communication.