Fracturing fluids are commonly formulated with fresh water to ensure reliable rheology. However, fresh water is becoming more costly, and in some areas, it is difficult to obtain. Therefore, using produced water in hydraulic fracturing has received increased attention in the last few years. A major challenge, however, is its high total dissolved solids (TDS) content, which could cause formation damage and negatively affect fracturing fluid rheology. The objective of this study is to investigate the feasibility of using produced water to formulate crosslinked-gel-based fracturing fluid. This paper focuses on the compatibility of water with the fracturing fluid system and the effect of salts on the fluid rheology.
Produced water samples were analyzed to determine different ion concentrations. Solutions of synthetic water with different amounts of salts were prepared. The fracturing fluid system consisted of natural guar polymer, borate-based crosslinker, biocide, surfactant, clay controller, scale inhibitor, and pH buffer. Compatibility tests of the fluid system were conducted at different cation concentrations. Apparent viscosity of the fracturing fluid was measured using a high-pressure high-temperature rotational rheometer. All rheology tests were conducted at a temperature of 180°F and were conducted according to API 13m procedure with a three-hour test duration. Fluid breaking test was also performed to ensure high fracture and proppant pack conductivity.
Produced water analysis showed a TDS content of 125,000 ppm, including Na, Ca, K, and Mg ion concentrations of 36,000, 10,500, 1,700, and 700 ppm, respectively. Results indicated the potential of produced water to cause formation damage. Therefore, produced water was diluted with fresh water and directly used to formulate the fracturing fluid. Divalent cations were found to be the main source of precipitation, and the reduced amounts of each ion were determined to prevent precipitation. The separate and combined effects of Na, K, Ca, and Mg ions on the viscosity of the fracturing fluid were also studied. Fluid viscosity was found to be significantly affected by the concentrations of divalent cations regardless of the concentrations of monovalent cations. Monovalent cations reduced the viscosity of fracturing fluid only in the absence of divalent cations, and showed no effect in the presence of Ca and Mg ions. Water with reduced concentrations of monovalent and divalent cations showed the most suitable environment for polymer hydration and crosslinking.
This paper contributes to the understanding of the main factors that enable the use of produced water for hydraulic fracturing operations. Maximizing the use of produced water could reduce its disposal costs, mitigate environmental impacts, and solve fresh water acquisition challenges.
Although geochemical reactions are the fundamental basis of the alkaline/surfactant/polymer (ASP) flooding, their importance is commonly overlooked and not fully assessed. Common assumptions made when modeling geochemical reactions in ASP floods include: 1) ideal solution (i.e., using molalities rather than ion activities) for the water and aqueous geochemical species 2) limiting the number of reactions (i.e., oil/alkali and alkali consumptions) rather than including the entire thermodynamically-equilibrated system 3) ignoring the effect of temperature and pressure on reactions 4) local equilibrium ignoring the kinetics. To the best of our knowledge, the significance of these assumptions has never been discussed in the literature. In this paper we investigate the importance of geochemical reactions during alkaline/surfactant/polymer floods using a comprehensive tool in the sense of surfactant/soap phase behavior as well as geochemistry.
We coupled the United States Geological Survey (USGS) state-of-the-art geochemical tool, with 3D flow and transport chemical flooding module of UTCHEM. This geochemical module includes several thermodynamic databases with various geochemical reactions, such as ion speciation by applying several ion-association aqueous models, mineral, solid-solution, surface-complexation, and ion-exchange reaction. It has capabilities of saturation index calculation, reversible and irreversible reactions, kinetic reaction, mixing solutions, inverse modeling and includes impacts of temperature and pressure on reaction constants and solubility products. The chemical flood simulator has a three phase (water, oil, microemulsion) phase behavior package for the mixture of surfactant/soap, oil, and water as a function of surfactant/soap, salinity, temperature, and co-solvent concentration. Hence, the coupled software package provides a comprehensive tool to assess the significance of geochemical assumptions typically imposed in modeling ASP floods. Moreover, this integrated tool enables modeling of variations in mineralogy present in reservoir rocks. We parallelized the geochemistry module of this coupled simulator for large-scale reservoir simulations.
Our simulation results show that the assumption of ideal solution overestimates ASP oil recovery. Assuming only a subset of reactions for a coupled system is not recommended, particularly when a large number of geochemical species is involved, as is the case in realistic applications of ASP. Reservoir pressure has a negligible effect but temperature has a significant impact on geochemical calculations. Although mineral reaction kinetics is largely a function of the temperature and in-situ water composition, some general conclusions can be drawn as follows: to a good approximation, minerals with slow rate kinetic reaction (e.g., quartz) can be excluded when modeling ASP laboratory floods. However, minerals with fast rate kinetic reactions (e.g., calcite) must be included when modeling lab results. On the other hand, in modeling field-scale applications, local equilibrium assumption (LEA) can be applied for fast rate kinetic minerals, whereas kinetics should be used for slow rate kinetic minerals.
Achieving maximum oil recovery utilizing CO2 has limitations when operating at, or very close, to the Minimum Miscibility Pressure (MMP) of the CO2 in the oil. A modular source of CO2 would allow Enhanced Oil Recovery (EOR) flooding of "stranded" and shallow reservoirs. Unfortunately, modular sources of CO2 production often include CO and N2 mixed with the CO2. Thus, testing for EOR application of a mixed gas-containing CO2, N2, and CO was initiated.
Bench scale testing using Rising Bubble Apparatus (RBA), Slim Tubes, and linear core flood have been conducted on oils ranging from 16-42° gravities having viscosities of 0.5-280 cp. All tests were conducted at reservoir temperatures and pressures. CO, being a strong reducing agent, was further tested on reservoir rock containing swelling clays with hydrated ferric hydroxides. Due to the apparent reduction of the ferric hydroxide, and the liberation of its water of hydration, an increase in matrix permeability and clay stabilization, was observed.
For most oils tested, the CO2/CO mixture increased rate of oil recovery by 2-3X, using only 50-60% as much gas/bo as compared to pure CO2. Recovery factors of 80%, at immiscible pressures 30-40% below CO2 MMP, were achieved. Addition of 15% N2 (v/v) to the CO2/CO mixture did not impair oil recovery. Interfacial testing (IFT) of oils, using pure CO, demonstrated a lowering of the IFT. RBA testing of asphaltine-rich heavy oils has shown that a mixture of CO2/CO dissolves into the oil at a far faster rate than either CO2 or CO individually and faster than the sum of both individual gases. A similar test using non-asphaltine type oils did not display this unique characteristic. Slim tube testing suggests that CO facilitates the mobilization of asphaltine-rich heavy oils and lowers viscosity. A linear corefloods of a reservoir containing 5% smectite + illite/smectite + and chlorite demonstrated a 275% increase in matrix permeability. Packed column tests, containing quartz sand and bentonite, demonstrated up to 300-900% increase in permeability in the presence of CO.
Thus a method to recover oil faster, from stranded reservoirs, at pressures below MMP, using significantly less gas, appears possible. In addition the use of CO, either alone or in combination with CO2 and/or N2, has been shown to increase matrix permeability. Such a gas mixture may be beneficial to achieving low pressure EOR from shallow, "stranded" reservoirs, non-conventional shale oil reservoirs, and viscous, heavy oil reservoirs at low temperatures. Incorporation of CO, or CO2/CO, in a frac fluid, or alternately as a post frac cleanup for shale oil and gas applications appears to warrant investigation.
Imqam, Abdulmhsin (Missouri University of Science and Technology) | Wang, Ze (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Delshad, Mojdeh (The University of Texas at Austin)
Preformed particle gels (PPG) have been successfully applied as a plugging agent to solve the conformance problem in fractured reservoirs. They are injected to plug fractures and then divert displacing fluid into poorly swept zones and areas. However, PPG propagation and plugging mechanisms through open fractures have not been studied thoroughly. This paper investigated the influence of some factors (particle size, brine concentration, heterogeneity, injection flow rate, and brine salinity) on gel injectivity and plugging performance for water flow through opening fractures. Five-foot tubes were used to mimic opening fractures. Three models were designed to gain understanding on how fracture geometry and PPG properties affect gel injection and plugging efficiency, including (1) single fracture with uniform fracture width, (2) single fracture with different widths, and (3) two parallel fractures with different width ratios between each other. Results from single uniform fracture experiments showed that PPG injection pressure was more sensitive to gel strength than gel particle size. When large PPG size and high gel strength were used, high injection pressure and large injection pore volume were required for PPG and brine to reach fracture outlets. Results from single heterogeneous fracture model experiments showed PPG injection pressure increased as the fracture heterogeneity in sections increased. Particle gel accumulated at the choke point within each fracture and caused injection pressure to increase accordingly. Furthermore, results showed that having a lower salinity within a fracture, which was less than the brine salinity that was used to prepare PPG, would improve the PPG plugging efficiency for water flow. Parallel fracture models results showed that when weak PPG was used, a large volume of PPG flowed into a large fracture width and a small portion of the gel particle volume flowed into small fracture width. However, with increased gel strength and fracture width ratio, PPG only flowed through larger fracture widths. This paper demonstrates important impact elements of gel propagation and water flow for different opening fracture situations.
Fortenberry, R. (Ultimate EOR Services) | Delshad, M. (Ultimate EOR Services) | Suniga, P. (Ultimate EOR Services) | Koyassan Veedu, F. (DeGolyer & MacNaughton) | Wang, P. (DeGolyer & MacNaughton) | Al-Kaaoud, H. (Kuwait Oil Company) | Singh, B. B. (Kuwait Oil Company) | Tiwari, S. (Kuwait Oil Company) | Baroon, B. (Kuwait Oil Company) | Pope, G. A. (University of Texas at Austin)
Our team has developed a new simulation model for an upcoming 5-spot Alkaline-Surfactant-Polymer (ASP) pilot in the Sabriyah Mauddud reservoir in Kuwait. We present new pilot simulation results based on new data from pilot wells and an updated geocelluar reservoir model. New cores and well logs were used to update the geocellular model, including initial fluid distributions, permeability and layer flow allocation.
From the updated geocellular model a smaller dynamic sector model was extracted to history match field performance of a waterflood pattern. From the dynamic model a yet smaller pilot model was extracted and refined to simulate the 5-spot ASP pilot.
We used this pilot model to evaluate injection composition, zonal completions, observation well locations, interwell tracer test design and predicted performance of ASP flooding. A sensitivity analysis for some important design variables and pilot performance benchmarks is also included. We used multiple interwell tracer test simulations to estimate reservoir sweep efficiency for both water and ASP fluids, and to help us understand how well operations will affect this unconfined ASP pilot. This work details some crucial aspects of pre-ASP pilot design and implementation.
Erke, S. I. (Salym Petroleum Development) | Volokitin, Y. E. (Salym Petroleum Development) | Edelman, I. Y. (Salym Petroleum Development) | Karpan, V. M. (Salym Petroleum Development) | Nasralla, R. A. (Shell Global Solutions International) | Bondar, M. Y. (Salym Petroleum Development) | Mikhaylenko, E. E. (Salym Petroleum Development) | Evseeva, M. (Salym Petroleum Development)
Low-salinity waterflooding (LSF) has been recognized as an IOR/EOR technique for both green and brown fields in which the salinity of the injected water is lowered for particular reservoir properties to improve oil recovery. While providing lower or similar UTC's low salinity projects have the advantage of lower capital and operational costs as compared to some more expensive EOR alternatives.
This work describes LSF experiments, field-scale simulation results, and conceptual design of surface facilities for West Salym oil field. The field is located in West Siberia and is on stream since 2004. Conventional waterflooding was started in 2005 and current water cut is currently above 80% in the developed area of the field. To counter oil production decline a tertiary Alkaline-Surfactant-Polymer (ASP) flooding technique selected for mature waterflooded field parts and piloting of this technique is ongoing. Operationally simpler and more cost-effective LSF method is considered for implementation in the unflushed (green) areas of the field since it has been recognized that application of LSF in secondary mode results in better incremental oil recovery than LSF in tertiary mode.
The results of a comprehensive conceptual study performed to justify the LSF trial are presented in this paper. To generate production forecast for LSF in the isolated area at the outset of reservoir development the results of laboratory core tests executed at different salinities presented earlier (
Fracture treatment performance in Bakken shale reservoirs can be improved by altering rock wettability, as measured with contact angle (CA), from oil-wet to water-wet. The use of chemical additives for altering wettability also results in alteration of the interfacial tension (IFT). The Young-Laplace equation relates the capillary pressure to IFT and contact angle. Thus, it follows that capillarity is significant in nano-pores associated with unconventional liquid reservoirs (ULR) and complex as the CA and IFT varies simultaneously. We carefully evaluate these interactive variables to improve oil recovery by alteration of capillary pressure by understanding the wetting state of siliceous and carbonate Bakken cores with and without chemical additives. We have observed that wettability can be altered from the ULR natural state of oil-wet to systems favoring frac fluid imbibition. Surfactants can be added to completion fluids, in proper concentrations, to alter wettability while hydraulic fracturing the formation. This experimental study evaluates and compares the efficiency of anionic, nonionic and blended surfactants as well as complex nanofluids (CNF) on recovering liquid hydrocarbons from Bakken shale cores by analyzing the effect of wettability and IFT alteration and their impact on spontaneous imbibition.
The original wettability of Bakken cores is determined by CA measurements. Then, three surfactant types, anionic nonionic and nonionic-cationic, and CNF are evaluated to gauge their effectiveness in altering wettability. The results show that all surfactants and CNF are able to shift core wettability from oil-wet to water-wet. However, chemical additives efficacy strongly depends on rock lithology, surfactant, and CNF type. Moreover, to evaluate further wettability alteration, stability of surfactant and CNF solution films on the shale rock surface is determined by zeta potential measurements. Surfactants and CNF show higher zeta potential magnitudes than water without additives, as an indication of better stability and water-wetness, which agrees with CA results. In addition, the effect of IFT alteration is studied in solutions with surfactants and CNF, and Bakken crude oil. Higher IFT reduction is achieved by anionic surfactants, but all surfactants and CNF perform better than water alone.
Surfactants and CNF potential for improving oil recovery in ultralow permeability Bakken cores is investigated by spontaneous imbibition experiments using modified Amott cells in an environmental chamber. Using computed tomography (CT) scan methods, water imbibition as penetration magnitude is measured in real time. In addition, oil recovery is recorded with time to compare the performance of surfactants, CNF, and completion fluid alone. The results suggest that surfactants and CNF are better on recovering oil from shale core displacing more oil and having higher penetration magnitudes than water without additives. In addition, oil recovery depends on surfactant and CNF type and rock mineral composition. These findings are consistent with CA, zeta potential, and IFT measurements. From the results obtained, it can be concluded that altering wettability and reducing IFT when surfactants and CNF additives are added to completion fluids can improve oil recovery in Bakken cores.
Khorsandi, Saeid (The Pennsylvania State University) | Qiao, Changhe (The Pennsylvania State University) | Johns, Russell T. (The Pennsylvania State University) | Torrealba, Victor A. (The Pennsylvania State University)
Reservoir simulation is a valuable tool for assessing the potential success of enhanced recovery processes. Current chemical flooding reservoir simulators, however, use Hand's model to describe surfactant-oil-brine systems even though Hand's model is not predictive, and can fit only a limited data set. Hand's model requires the tuning of multiple empirical parameters using experimental data that usually consist of salinity scans at constant reservoir temperature and atmospheric pressure. Given experimental data supporting the change in microemulsion phase behavior with key formulation properties (e.g. temperature, pressure, salinity, EACN, and overall composition), there is a need for an improved model that can capture changes in these relevant parameters at the reservoir scale. The recent EOS proposed for microemulsion phase behavior (
In this paper, the EOS model with the extension to two-phase regions is incorporated for the first time into the chemical flooding simulators, UTCHEM, and our new in-house simulator PennSim. Hand's model is only used for comparison purposes, and is no longer needed even for flash calculations in the type II- and type II+ regions. The results show excellent agreement between UTCHEM and PennSim both in composition space and for composition/saturation profiles. Further, the HLD-NAC based EOS model and Hand's models are fitted to the same experimental data and the results of these simulations are nearly identical when variations of salinity, pressure and temperature are small. For large gradients, the results of the physics-based EOS deviates from Hand's model, and shows it is critical to incorporate these gradients in recovery predictions at large scale.
Pilots are widely used for the purpose of gathering valuable information about performance and practical challenges of implementing a particular CEOR process in a given field (
Addition of chemical species to the material balance equations alongside finer resolution requirements for CEOR simulations compared to waterfloods (WF), often make it impractical to run full field CEOR simulations to the required accuracy. Massively parallel computing, dynamic local grid refinement and sector modeling have been used with varying success, of which sector modeling is the most common. Sector models, by their very definition, are also naturally suited for modeling of pilots.
The art of sector modeling needs mastering a few important steps such as: appropriate selection of the sector model extent, details on carving it out of the Full Field Model (FFM), populating it with proper petrophysical and fluid properties, initializing it to correct initial conditions and optimizing its boundary conditions. On top of that, choice of optimum grid size for proper trade-off of simulation run times and accuracy needs to be considered.
This paper presents a case study for appropriate simulation of a CEOR pilot within Chevron. The candidate has a waterflood history matched FFM. This model is used to generate a sector model for the CEOR pilot area. This paper outlines how the extent of the sector model and all the regions in communication with the Area of Interest (AOI) is decided. It also discusses proper initialization and optimization of the boundary conditions of the sector model along with its appropriate refinement and grid optimization. Proper CEOR simulations on the final optimized sector model and sensitivity analysis are also presented. The challenges, lessons learned and best practices are shared and important considerations for adequate simulation of CEOR processes are outlined.
The production and transportation of heavy and extra-heavy crude oil are two of the paramount concerns in the oil industry due to the difficulties associated with heavy crude oil high viscosity. One of the most efficient techniques to improve the recovery and the transportability of such oil is to reduce its viscosity through dilution that can be applied solely or via thermal methods.
In the present work, a new type of plant-based diluent is proposed, and its efficacy in heavy oil viscosity reduction for different concentrations, temperatures and shear rates is studied. Various concentrations of diluent, ranging from 5 to 25 wt%, are added to heavy-oil samples with different concentrations of asphaltene and viscosity, ranging from 48000 to 65000 cp in ambient temperature. A rotational viscometer was then employed to the measure viscosity of the prepared samples at the temperature range of 70 to 190°F and a shear rate of 3 to 50 s-1.
The application of the proposed diluent led to promising results in that in caused the viscosity of the heavy oil samples to reduce by 93% in 75°F and 85% in 190°F with 20 wt% of diluent. To compare the performance of the proposed solvent and the common viscosity-reducing solvents, heavy oil samples were diluted with xylene and toluene with the same concentrations. Results indicated that the application of proposed diluent outperformed all of the commonly used solvents in terms of decreasing viscosity. The application of 20 wt% of the proposed diluent led to a 93% viscosity reduction of the heavy oil samples, which is 15% more than efficiency of adding the same concentration of toluene.
The proposed diluent is a plant-based, non-hazardous substitute to the conventional hazardous diluents, e.g., xylene or toluene, that provides more efficient viscosity reduction compared to its conventional alternatives. Its flashpoint is higher than that of light crude resulting in less evaporation at high temperatures thus a longer period of reduced viscosity can be obtained. Furthermore, due to its high flashpoint, the proposed diluent can be employed in thermal methods more efficiently.