This paper addresses two questions for polymer flooding. First, what polymer solution viscosity should be injected? A base-case reservoir-engineering method is present for making that decision, which focuses on waterflood mobility ratios and the permeability contrast in the reservoir. However, some current field applications use injected polymer viscosities that deviate substantially from this methodology. At one end of the range, Canadian projects inject only 30-cp polymer solutions to displace 1000-3000-cp oil. Logic given to support this choice include (1) the mobility ratio in an unfavorable displacement is not as bad as indicated by the endpoint mobility ratio, (2) economics limit use of higher polymer concentrations, (3) some improvement in mobility ratio is better than a straight waterflood, (4) a belief that the polymer will provide a substantial residual resistance factor (permeability reduction), and (5) injectivity limits the allowable viscosity of the injected fluid. At the other end of the range, a project in Daqing, China, injected 150-300-cp polymer solutions to displace 10-cp oil. The primary reason given for this choice was a belief that high molecular weight viscoelastic HPAM polymers can reduce the residual oil saturation below that expected for a waterflood or for less viscous polymer floods. This paper will examine the validity of each of these beliefs.
The second question is: when should polymer injection be stopped or reduced? For existing polymer floods, this question is particularly relevant in the current low oil-price environment. Should these projects be switched to water injection immediately? Should the polymer concentration be reduced or graded? Should the polymer concentration stay the same but reduce the injection rate? These questions are discussed.
This paper describes the analysis and positive results of injecting water, from constant to discontinuous rates in a reservoir under a high water cut stage. By following and improving waterflooding surveillance applications it was possible not only to describe the kind of reservoir, but also to keep the water cut up for a longer time. The goal of this study is to demonstrate the powerful benefits of applying and improving the surveillance plots that are available in the existing literature. The pore volumes injected plot, which was enhanced in this study by adding the injection rates per well in a secondary Y axis, was a powerful tool to identify the water cut behavior.
One of the two injector wells of the field was shut in for about 5 months and returned to its water injection conditions for 7 months. These events are presented in three phases. The first is related to the reservoir characterization achieved before the injector shut in. The second includes the well responses observed and monitored during the injector shut in. And, the third illustrates the promising reservoir results after the injector shut in. As well, an economic model is also developed.
As a result of the field events, analysis, and results described in this paper, the reservoir water cut was stable for a longer time in comparison with the whole life of the IOR project. In addition the increase Estimate Ultimate Recovery was 304,968 bbl for 8 years, the net present value of the field increased to 24%, and the average operating cost was reduced to 2.49 USD/bbl from 2015 to 2022.
The cyclic waterflooding existing literature supports reservoir characterization, analysis and results achieved in Tiguino Field. The initial application monitored in Ecuador will be helpful to be considered as a first approach for starting an IOR optimization in similar stratified reservoirs. The results obtained in Tiguino field are helpful not only as a real example but also as a statistical support for cyclic waterflooding. The Tiguino case experience would be extrapolated to other fields worldwide.
We study Enhanced Oil Recovery (EOR) through Low Salinity (LS) waterflooding in a brown oil field. LS waterflooding is an emerging EOR technique in which water with reduced salinity is injected into a reservoir to improve oil recovery, as compared with conventional waterflooding, in which High Salinity (HS) brine or seawater are commonly used. The efficiency of this technique can be quantified at the well-scale by a Single Well Chemical Tracer Test (SWCTT), which is an in-situ method for measuring the Remaining Oil Saturation (ROS) after flooding the near-wellbore region with a displacing agent. Two SWCTTs were executed on a sandstone North African field. The tests were realized in sequence with seawater and LS water to evaluate the EOR potential at the well-scale.
Here, we propose the interpretation of these two SWCTTs. They were modeled through numerical simulations because of the presence of several non-idealities in the complex scenario considered. A recently-developed tracer simulator was employed to solve the reactive transport problem. This was used as a fast post-processing tool coupled with a conventional reservoir simulator. Model parameters were estimated within an inverse modeling framework, on the basis of an assisted history matching procedure that exploits the Metropolis Hastings Algorithm (MHA). Results were scaled up on a sector model of the field, and forecast scenarios that consider a field-scale implementation of this technique were defined.
The well-scale displacement efficiency gain associated with LS water, as compared with seawater, was evaluated. It was quantified as a ROS reduction of 8 saturation unit (s.u.), with a P10–P90 range of 3–15 s.u. Reservoir-scale simulations suggest that the associated ultimate oil recovery of the EOR pilot may be increased by 2% with LS water, with a P10–P90 range of 0.7–4.3%.
Overall, the LS EOR potential for a selected field was quantified through a robust and original workflow, based on SWCTT interpretation. This state-of-the-art procedure is now available for further applications. The simulated oil recovery improvement with LS water is promising, and leads the way to the implementation of an inter-well field trial.
As polymer injection has not reached the same maturity as waterflooding, implementing polymer injection projects at field scale requires a workflow comprising screening of the portfolio of an organization for oil fields potentially amenable for polymer injection, laboratory and field testing followed by sector- and field implementation and roll-out in the portfolio.
Going through the workflow, not only the subsurface uncertainty is reduced but also the knowledge about the cost structure and operating capabilities of the organization improved.
Analyzing the economics of polymer injection projects shows that costs can be split into polymer injector-producer (polymer pattern) dependent and independent costs. Knowing these costs, a Minimum Economic Number of Patterns (MENP) is defined to achieve Net Present Value zero. This number is used to determine a Minimum Economic Field Size (MEFS) for polymer injection which is taken into account in the screening of the portfolio.
Defining a robustness criterion for economics, the minimum number of patterns for polymer injection meeting this criterion is calculated. This criterion is applied to generate a diagram allowing for screening of fields for polymer economics using pattern dependent and pattern independent costs and Utility Factor.
The cost structure reveals how the NPV of polymer projects changes with number of patterns, incremental oil and injectivity. Injectivity is of particular importance as it determines the Chemical Affected Reservoir Volume (CARV) or speed of production.
A sensitivity analysis of the NPV showed that for the cost structure used here, in addition to the polymer costs, the well costs are important for the economics of a full-field polymer injection project.
MEOR (microbial enhanced oil recovery) is known as one of the emerging low-cost EOR technologies, which uses in-situ microorganisms living in the oil field. Some of the most promising microbial-induced mechanisms include production of extracellular polymeric sugars (EPS), biofilms as well as selective plugging caused by cell growth. However, there is limited data available concerning the way microbes and biofilms behave in contact to surfaces in porous media in the context of MEOR. The aim of this work was to investigate bacterial growth and biofilm production in the framework of an ongoing MEOR project conducted by Wintershall and BASF. We used various approaches to investigate cell behavior of a halophilic bacterial community derived from a Wintershall oil field. Bacterial growth was conducted in both batch cultures and under dynamic conditions. To visualize cell adhesion and also exopolymers occuring in biofilms we used specific fluorescent dyes. During incubation of the microbes over several weeks we could visualize different types of EPS under the microscope. This observation fits perfectly to a concurrent viscosity increase of the surrounding media. Modelling approaches were applied to estimate the potential contribution of these effects on additional oil recovery. The observations including cell clumping, sorption and polymer production were geometrically quantified and the effect of the modifications on permeability profile and resulting flow characteristics was numerically investigated with fluid dynamic simulations of the petrophysical changes. The potential implications of the observed changes on EOR capability by conformance control and wettability modification were further estimated with analytical approaches. With the developed methods for visualization and modelling of the microbes and biofilms in both batch and dynamic conditions, we are able to monitor the clumping and sorption behavior of the cells, which will help to interprete data obtained during an upcoming MEOR field trial.
Ghasemi, M. (Petrostreamz AS) | Astutik, W. (Petrostreamz AS) | Alavian, S. A. (PERA AS) | Whitson, C. H. (PERA AS/NTNU) | Sigalas, L. (Geological Survey of Denmark and Greenland) | Olsen, D. (Geological Survey of Denmark and Greenland) | Suicmez, V. S. (Maersk Oil & Gas A/S)
This paper presents a novel technique to determine multi-component diffusion coefficients for CO2 injection in a North Sea Chalk Field (NSCF) at reservoir conditions. Constant volume diffusion (CVD) method is used, consisting of an oil-saturated chalk core in contact with an overlying free-space, which is filled with the CO2. The experimental data are matched with an EOS-based compositional model.
Transport by diffusion controls the dynamics of the constant-volume system, together with phase equilibria, allowing a consistent estimation of diffusion coefficients needed to describe the observed changes in system pressure.
We conduct two experiments at reservoir condition: one utilizes a core plug saturated with live-oil, and the other with stock tank oil (STO). Once the experiments are completed, EOS-based compositional simulation is performed to match the experimental data using the oil and gas diffusion coefficients as history matching parameters. The modeling work is conducted with a commercial reservoir simulator using a two dimensional radial grid model to describe the experimental setup.
The experiment utilizes a vertically-oriented core holder with a height of 92 mm and 37.6 mm in diameter. An outcrop chalk core with a sealing sleeve is mounted in the core holder, which has the same diameter and a height of 64.6 mm, thus resulting in an overlying void space. The system is initially saturated with oil at reservoir condition. CO2 is then injected from the top, forming an overlying CO2 chamber, and displacing oil towards the bottom of the core holder. Once CO2 fills the overlying bulk space, the system is isolated with no further injection or production.
The CO2 and oil reach and remain in equilibrium locally at the gas-oil interface throughout the test, initiating and maintaining the diffusion mechanism. Diffusion of CO2 into the oil results in a decreasing pressure, which is the main history matching parameter.
The multi-component diffusion coefficients are found to match the model pressure-time prediction to the experimental data. This suggests the modelling workflow incorporates a representative EOS model and the main transport dynamics controlled by diffusion are being treated properly.
The two main challenges in the modeling are (1) the limitation on setting an appropriately-high permeability for the CO2 chamber, and (2) the reservoir simulator neglects compositional dependency of diffusion coefficients.
Proper simulation of CO2 injection in fractured chalk reservoirs requires the ability to model multi-component diffusion accurately. The proposed CVD-method provides such modeling capabilities. Our modeling and experimental work indicate the novelty of the CVD method to determine the diffusion coefficients of a system where diffusion is the dominant displacement mechanism. The fact that the oil is contained within a low-permeability chalk sample reduces density-driven convection that could result due to non-monotonic oil density changes as CO2 dissolves into the oil.
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 (
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.
Mukherjee, Joydeep (The Dow Chemical Company) | Nguyen, Quoc P. (The University of Texas at Austin) | Scherlin, John (Fleurde Lis Energy) | Vanderwal, Paul (The Dow Chemical Company) | Rozowski, Peter (The Dow Chemical Company)
A supercritical CO2 foam pilot, comprised of a central injection well in an inverted 5-spot pattern, was implemented in September 2013 in Salt Creek field, Natrona County WY. In this paper we present a thorough analysis of the pilot performance data that has been collected to date from the field. A monitoring plan was developed to analyze the performance of the pilot area wells before and after the start of the foam pilot. The injection well tubing head pressure was controlled to maintain a constant bottom hole pressure and the fluid injection rates were monitored to capture the effect of foam generation on injectivity. Inter-well tracer studies were performed to analyze the change in CO2 flow patterns in the reservoir. Production response was monitored by performing frequent well tests. The CO2 injection rate profile monitored over several WAG cycles during the course of the implementation clearly indicates the formation and propagation of foam deep into the reservoir. CO2 soluble tracer studies performed before and after the start of the foam pilot indicate significant areal diversion of CO2. The production characteristics of the four producing wells in the pilot area indicate significant mobilization of reservoir fluids attributable to CO2 diversion in the pattern. The produced gas-liquid ratio has decreased in all four of the producing wells in the pattern. Analysis of the oil production rates shows a favorable slope change with respect to pore volumes of CO2 injected. Segregation of CO2 and water close to the injection well seems to be the primary factor adversely affecting CO2 sweep efficiency in the pilot area. Foam generation leads to a gradual expansion of the gas override zone. The gradual expansion of the gas override zone seems to be the principal mechanism behind the production responses observed from the pilot area wells.
Dalmazzone, C. (IFP Energies Nouvelles) | Mouret, A. (IFP Energies Nouvelles) | Behot, J. (IFP Energies Nouvelles) | Norrant, F. (IFP Energies Nouvelles) | Gautier, S. (IFP Energies Nouvelles) | Argillier, J.-F. (IFP Energies Nouvelles) | Chabert, M. (SOLVAY)
A majority of the worldwide oil reserves is contained in carbonate reservoirs. Most of these reservoirs are naturally fractured and produce less than 10% of the oil in place during the primary recovery operations. It is noteworthy that this particularly low recovery ratio is essentially due to a low permeability associated to an intermediate or preferentially oil wettability. Consequently, the recovery of residual oil from these specific reservoirs is a great challenge. Changing the wettability from oil wet to preferentially water wet by using chemicals is one of the EOR technique that may be advantageously used to enhance the production rate. This chemical treatment consists in injecting an aqueous solution of surfactants or chemical additives to increase the water wettability and favour spontaneous imbibition into the porous matrix. We present a new test allowing a fast screening of aqueous solutions of chemicals that may be used to improve oil recovery from carbonate reservoirs. The test consists in depositing a drop of aqueous solution on a porous carbonate slice that has been treated to be preferentially oil wet before being put into dodecane. The evolution of the drop profile is then monitored as a function of time by means of a camera, which permits a simultaneous measurement of the interfacial tension between oil and water, contact angle between the water drop and the porous matrix and spontaneous imbibition. Various types of non-ionic and anionic surfactants belonging to different families have been tested and ranked to identify the best candidates among these chemicals. Finally, a Nuclear Magnetic Resonance technique was used to follow spontaneous imbibitions of selected candidates in miniplugs representative of the carbonate slices used in the screening test. NMR's results confirmed the classification issued from the fast screening test.