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.
The polymer pilot project performed in the 8 TH reservoir of the Matzen field showed encouraging incremental oil production. To further improve the understanding of recovery effects resulting from polymer injection, an extension of the pilot is planned by adding a second polymer injector.
Forecasting of the incremental oil production needs to take the uncertainty of the geological models and dynamic parameters into account. We propose a workflow which comprises a geological sensitivity and clustering step followed by a dynamic calibration step for decreasing the objective function to improve the reliability of a probabilistic forecast of the incremental oil recovery.
For the geological sensitivity, hundreds of geological realizations were generated taking the uncertainty in the correlation of the sand and shale layers, logs, cores and geological facies into account. The simulated tracer response was used as dissimilarity distance to classify the geological realizations. Clustering was then applied to select 70 representative realizations (centroids) from a total of 800 to use in the full-physics dynamic simulation.
In the dynamic simulation, an objective function comprising liquid rate and tracer concentration of the back-produced fluids was introduced.
To further improve the calibration, the P50 value of incremental oil production as derived from simulation was compared with the incremental oil production determined from Decline Curve Analysis from the wells surrounding the polymer injection well. The mismatch between the P50 and the Decline Curve Analysis was improved by adjusting polymer viscosity.
The calibrated models were then used to for a probabilistic forecast of incremental oil due to an additional polymer injector and to estimate the expected polymer concentration at the producing wells.
Rodriguez, F. (PDVSA, IFP Energies nouvelles, Paris Diderot University) | Rousseau, D. (IFP Energies nouvelles) | Bekri, S. (IFP Energies nouvelles) | Hocine, S. (Solvay) | Degre, G. (Solvay) | Djabourov, M. (ESPCI Paris Tech) | Bejarano, C. A. (PDVSA)
Primary cold production for the extra-heavy oils (4–10°API) of La Faja Petrolifera del Orinoco (FPO), Venezuela, is currently a low percentage (<5%) of the OOIP. Chemical EOR (CEOR) studies are being accomplished in order to increase oil recovery in those thin-bedded reservoirs which host up to 35% of the OOIP, where thermal EOR methods are not convenient because of heat losses and environmental issues. Specifically, Surfactant-Polymer (SP) flooding is now considered as a feasible approach to achieve both mobility control and mobilization of residual oil in the FPO's target zones for CEOR.
The objectives of this experimental study were to identify some mechanisms in play when surfactant and polymer solutions are injected in cores to displace extra-heavy oil and to assess for the potential of SP flooding for one of the FPO's reservoirs. The tests reported were performed with a dead crude oil of 9°API and 4500 cP, and injection water salinity of 6.4 g/L with low hardness and at a temperature of 50°C. The SP formulation consisted of a standard high molecular weight HPAM at rather high concentration to achieve high viscosity and an alkaline-free surfactant formulation providing both low interfacial tension (IFT) and good compatibility with polymer even at high polymer concentration. When possible, oil saturation profiles were determined by CT-scan at the main steps of the experiments.
Conditions and methodologies to determine the relevant experimental parameters for high viscosity oil have firstly been developed. Then, a set of surfactant and polymer injection tests have been performed on Bentheimer outcrop cores. These tests demonstrated that injection of the SP formulation after a secondary polymer flood was able to achieve a significant reduction of the residual oil (ASo = 80% ROIP). Results of secondary injections of water (final oil saturation, Sofinal = 63%), surfactant solution (Sofinal = 39%) and SP formulation (Sofinal = 5%) have also shown that mobility control is of tremendous importance to achieve high recovery, even at the core-scale. The potential of the SP formulation has also been validated on unconsolidated reservoir rock material from the FPO (Sofinal = 8%). Relative permeabilities have also been determined to investigate the feasibility of an effective modeling of the impact of the surfactant on oil recovery without making any assumption of the local mechanisms in play. Future work will involve 3D reservoir simulation with physico-chemical parameters generated at the lab.
Polymer flooding can significantly improve sweep and delay breakthrough of injected water, thereby increasing oil recovery. Polymer viscosity degrades in reservoirs with high salinity brines, so it is advantageous to inject low salinity water as a preflush. Low salinity water flooding (LSW) can also improve local displacement efficiency by changing the wettability of the reservoir rock from oil wet to more water wet. The mechanism for wettability alteration for low salinity waterflooding in sandstones is not very well understood, however experiments and field studies strongly support that cation exchange (CE) reactions are the key element in wettability alteration. The complex coupled effects of CE reactions, polymer properties, and multiphase flow and transport has not been explained to date.
This paper presents the first analytical solutions for the coupled synergistic behavior of low salinity waterflooding and polymer flooding considering cation exchange reactions, wettability alteration, adsorption, inaccessible pore volume (IPV), and salinity effects on polymer viscosity. A mechanistic approach that includes the cation exchange of Ca2+, Mg2+ and Na+ is used to model the wettability alteration. The aqueous phase viscosity is a function of polymer and salt concentrations. Then, the coupled multiphase flow and reactive transport model is decoupled into three simpler sub-problems, one where cation exchange reactions are solved, the second where a variable polymer concentration can be added to the reaction path and the third where fractional flows can be mapped onto the fixed cation and polymer concentration paths. The solutions are used to develop a front tracking algorithm, which can solve the slug injection problem where low salinity water is injected as a preflush followed by polymer. The results are verified with experimental data and PennSim, a general purpose compositional simulator.
The analytical solutions show that decoupling allows for estimation of key modeling parameters from experimental data, without considering the chemical reactions. Recovery can be significantly enhanced by a low salinity pre-flush prior to polymer injection. For the cases studied, the improved oil recovery (IOR) for a chemically tuned LSP flood can be as much as 10% OOIP greater than with considering polymer alone. The results show the structure of the solutions, and in particular the velocity of multiple shocks that develop. These shocks can interact, changing recovery. For example, poor recoveries obtained in core floods for small low salinity slug sizes are explained with intersection of shocks without considering mixing. The solutions can also be used to benchmark numerical solutions and for experimental design. We demonstrate the potential of LSP as a cheaper and more effective way for performing polymer flooding when the reservoir wettability can be altered using chemically-tuned low salinity brine.
Compositional reservoir simulation plays a vital role in the development of conventional and unconventional reservoirs. Two major building blocks of compositional simulation are phase behavior and fluid transport computations. The oil and gas reserves and flow of reservoir fluids are strongly dependent on phase behavior. In conventional reservoirs, capillary pressure is relatively small and is typically ignored in phase behavior calculations. However, large capillary pressure values are encountered in tight formations such as shales; and therefore, its effects should not be ignored in phase equilibria calculations. Neglecting the effects of capillary pressure on phase behavior can lead to an inaccurate estimation of original oil and gas in place as well as recovery performance. In spite of this, the effect of capillary pressure on phase behavior in tight reservoirs has not been well studied using compositional simulation, especially for hydraulically-fractured reservoirs.
In this paper, we develop a new compositional reservoir simulator capable of modeling discrete fractures and incorporating the effect of capillary pressure on phase behavior. Large-scale natural and hydraulic fractures in tight rocks and shales are modeled with a technique called Embedded Discrete Fracture Model (EDFM) where fractures are modeled explicitly without using local grid refinement or an unstructured grid. Flow of hydrocarbons occurs simultaneously within similar and different porosity types. Capillary pressure is considered in both flow and flash calculations, where simulations also include variable pore size as a function of gas saturation in each grid block. We examine the impact of capillary pressure on the original oil in place and cumulative oil production for different initial reservoir pressures (above and below the bubble-point pressure) on Bakken and Eagle Ford fluids. The importance of capillary pressure on both flow and flash calculations from hydraulically fractured horizontal wells during primary depletion in fractured tight reservoirs using Bakken fluid composition is demonstrated.
Phase behavior calculations show that bubble-point pressure is suppressed allowing the production to remain in the single-phase region for a longer period of time and altering phase compositions and fluid properties such as density and viscosity of equilibrium liquid and vapor. The results show that bubble-point suppression is larger in the Eagle Ford shale than for Bakken. When capillary pressure is considered, we found an increase in original oil in place up to 4.1% for Bakken and 46.33% for the Eagle Ford crude. Depending on the initial reservoir pressure, cumulative primary production after one year increases owing to capillary pressure by approximately 9.0 – 38.2% for Bakken oil and 7.2 – 154% for Eagle Ford oil. The recovery increase caused by capillary pressure becomes more significant when reservoir pressure is far below bubble-point pressure. The simulation results with hydraulically fractured wells give similar recovery differences; cumulative oil production after 1 year is 3.5 – 5.2% greater when capillary pressure is considered in phase behavior calculations for Bakken.
Ampomah, W. (Petroleum Recovery Research Center) | Balch, R. S. (Petroleum Recovery Research Center) | Grigg, R. B. (Petroleum Recovery Research Center) | Will, R. (Schlumberger Carbon Services) | Dai, Z. (Los Alamos National Laboratory) | White, M. D. (Pacific Northwest National Laboratory)
The Pennsylvanian–age Morrow sandstone within the Farnsworth field unit of the Anadarko basin presents an opportunity for CO2 enhanced oil recovery (EOR) and sequestration (CCUS). At Farnsworth, Chaparral Energy's EOR project injects anthropogenic CO2 from nearby fertilizer and ethanol plants into the Morrow Formation. Field development initiated in 1955 and CO 2injection started December 2010. The Southwest Regional Partnership on Carbon Sequestration (SWP) is using this project to monitor CO2 injection and movement in the field to determine CO2 storage potential in CO2-EOR projects.
This paper presents a field scale compositional reservoir flow modeling study in the Farnsworth Unit. The performance history of the CO2 flood and production strategies have been investigated for optimizing oil and CO2 storage. A high resolution geocellular model constructed based on the field geophysical, geological and engineering data acquired from the unit. An initial history match of primary and secondary recovery was conducted to set a basis for CO2 flood study. The performance of the current CO 2miscible flood patterns were subsequently calibrated to the history data. Several prediction models were constructed including water alternating gas (WAG), and infill drilling using the current active and newly proposed flood patterns.
A consistent WAG showed a highly probable way of ensuring maximum oil production and storage of CO2 within the Morrow formation.
The production response to the CO2 flooding is very impressive with a high percentage of oil production attributed to CO2 injection. Oil production increasingly exceeded the original project performance anticipated. More importantly, a large volume of injected CO2 has been sequestered within the Morrow Formation.
The reservoir modeling study provides valuable insights for optimizing oil production and CO2 storage within the Farnsworth Unit. The results will serve as a benchmark for future CO2–EOR or CCUS projects in the Anadarko basin or geologically similar basins throughout the world.
In 2014, TOTAL performed two Single Well Tracer Tests (SWTT) to evaluate the remaining oil saturation in an offshore high temperature, high salinity carbonate reservoir. The SWTT method has proved to be a reliable way, when carefully programmed, to measure a representative remaining oil saturation without being impacted by near wellbore effects. The objective of these measurements was to evaluate the efficiency of a single well chemical EOR (CEOR) pilot by measuring oil desaturation.
Extensive in-house laboratory work was carried out by TOTAL to lay the foundation for the pre and post CEOR pilot SWTTs. A specific tracer injection skid was internally developed to ease the operations. Specific numerical work was performed to achieve robust designs and interpretations. These simulations, carried out in-house, took into account all major uncertainties highlighted by experimental work. Detailed results from the SWTT preparation phase will be described in the paper.
Results from the baseline SWTT interpretation evidenced excellent quality tracer profiles from the first test and high remaining oil saturation, improving our knowledge on the flooding pattern of this reservoir. Results from the post EOR SWTT showed again a clear response of a remarkable decrease in remaining oil saturation, proving the efficiency of the chemical formulation provided by TOTAL and the envisaged recovery mechanism. Interpretation of these Single Well Tracer Tests also allowed us to evidence a much lower than anticipated reservoir dispersion. These findings highlight the potential of EOR implementations in these carbonate formations.
Lessons learned from these two offshore SWTTs are discussed in this paper, such as the need for specific preparation to tackle the complexity of a high temperature high salinity carbonate reservoir in presence of H2S. TOTAL has shown that such operations can be performed in a strict timeframe while adhering to company safety rules. Careful interpretation of such results is mandatory to validate the success of the single well chemical EOR pilot.
Reconciling geological models to the available dynamic information, commonly known as history matching, is an essential step for optimizing reservoir management and field development strategies, including improved recovery methods. There are several challenges in the current history matching workflow, particularly for high resolution geologic models with multimillion cells and complex geologic architecture. Streamline-based inverse modeling has shown great promise in this respect because of computational efficiency and analytic calculation of sensitivity of production response to reservoir properties. However, the current streamline-based approach is mostly restricted to history matching water-cut and tracer response in two-phase flow.
In this paper we present a novel approach to extend the streamline-based history matching to three-phase flow by incorporating water-cut, gas-oil ratio and bottomhole pressure data while updating high resolution geologic models. The crux of our approach lies in the analytic computation of bottomhole pressure and gas-oil ratio sensitivities which allows for efficient inversion of production and pressure data. Thus, our approach overcomes one of the major limitations of the current state-of-the-art while preserving the computational efficiency and the intuitive appeal of the streamline method. The streamline-based approach can also be used in conjunction with finite difference simulators, further generalizing its applicability to enhanced oil recovery methods. We validate the accuracy and efficiency of the streamline-based sensitivities by comparison with adjoint or numerical methods using finite-difference simulators. In history matching, we incorporate the novel streamline-based method with multiscale approach to account for the disparity in resolution of different types of history data. This method leads to capturing of the large- and fine-scale heterogeneity and reproducing the pressure and production responses efficiently.
We demonstrate the power and utility of our approach using synthetic and field applications. The synthetic example involves the SPE9 benchmark field case with waterflooding and aquifer drive. The field example involves full-field history matching of the Norne Field in the North Sea using water-cut, gas-oil ratio and bottomhole pressure data and subsequent design of a polymer flood. A novel multiscale workflow demonstrates the efficiency and advantage of our proposed approach in achieving geologically consistent history matching at the full-field level.