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Prior to field-scale development of chemical EOR processes, pilot tests are widely accepted in the oil industry as a standard method to determine the efficiency of the formulated chemicals. During such tests there can be significant differences in temperature between the injected and reservoir fluids. This results in a cool-down of the wellbore, near-wellbore and inter-well regions which can be aggravated in high temperature reservoirs. Key features of surfactant flooding, such as interfacial tension (IFT) reduction between the oil and water phases, depend strongly on temperature. As a result it is necessary to estimate the strength of this cool-down effect upon designing pilot tests. This is the topic of this paper which addresses several scales ranging from near-wellbore to pilot pattern.
This work assesses the impact of temperature gradients during a pilot test on the efficiency of surfactant injection using advanced reservoir simulation. We first determine the temperature window seen by an injected surfactant solution with the aim of understanding how it may drive surfactant formulation. We then apply our findings on a pilot design study, with a model including a temperature dependent IFT. We analyse the sensitivity of given injection sequence and operational constraints to specific properties of the injected surfactant solution (low-IFT temperature windows) and then propose a methodology to determine the most efficient injection sequence for a specific surfactant formulation. We show that the temperature window encountered by the surfactant is very sensitive to thermal history of the reservoir and injection temperature.
The analysis of chemicals slug thermal and compositional mixing with in-situ fluids is found to be a game changer for reliable pilot design and production forecasts. Obtaining the lowest IFT between oil and water phases is the key in surfactant flooding efficiency: as such the in-situ temperature profiles obtained by simulation and the formulation design at the laboratory should be closely linked. We demonstrate that the process is considerably sensitive to temperature and suggest as a result the following workflow for the design of injection sequences during a pilot test: 1) assessing the temperature window that will be seen by the surfactant using simulation, 2) designing an adequate surfactant formulation, 3) estimating an optimal and robust surfactant injection sequence using simulation, 4) iterating between the three previous steps until an optimal recovery is achieved with a laboratory-formulated, cost-effective surfactant.
The impact of temperature on surfactant pilot tests is a specific, not so well documented subject, although it is a capital step in the feasibility assessment of a field scale deployment of surfactant EOR technology. Our workflow yields a reliable assessment of temperature landscapes seen by the injected fluids, which may then be used to test surfactant formulations from near-wellbore to interwell/reservoir scale (e.g. for designing and performing single well chemical tracer tests). As such it should be of interest to petroleum engineers, production engineers and chemists working on the design of chemical EOR processes.
Al-Murayri, Mohammed (Kuwait Oil Company) | Hassan, Abrahim (Kuwait Oil Company) | Hénaut, Isabelle (IFPEN) | Marlière, Claire (IFPEN) | Mouret, Aurélie (IFPEN) | Lalanne-Aulet, David (SOLVAY) | Sanchez, Juan-Pablo (Beicip-Franlab) | Suzanne, Guillaume (Beicip-Franlab)
Abstract This study presents an integrated approach to design a fit-for-purpose surfactant-polymer process for a major sandstone reservoir in Kuwait. The adopted procedure is described covering core flood experiments through pilot design using a reservoir simulation tool that was calibrated using laboratory results. The surfactant-polymer formulation design was already described in another publication (SPE-183933). In this paper, further optimization of the chemical formulation is described, including core floods to minimize the quantity of the injected chemicals while maintaining high oil recovery. Formulation robustness and its impacts on water-oil separation at the surface are also evaluated. Furthermore, reservoir simulation was utilized to design a field trial. At first, the parameters that were used to model surfactant-polymer performance were calibrated using core flood results. Then, the reservoir simulation model was used at a larger scale to identify the most appropriate injection sequence for field implementation. The performance of the designed surfactant-polymer formulation is promising. Core flood experiments demonstrate that the injection of the chemical formulation recovers more than 85% of the remaining oil after waterflooding, while having relatively low adsorption values. The designed formulation was also found to be quite resilient to variations in divalent cations concentration, water-oil ratio and oil composition. It was noticed that rock facies heterogeneity has a limited effect on surfactant adsorption. Favorable phase behavior properties were maintained around reservoir temperature and the formulation exhibited good aqueous stability between reservoir and surface temperatures. EOR parameters including salinity-dependent surfactant adsorption, capillary desaturation and polymer-induced water mobility reduction were calibrated in the reservoir simulation model using core flood data. Larger scale reservoir simulation enabled the design of a suitable injection sequence including a main surfactant-polymer slug followed by a polymer slug. The main variables of the design, including slug injection durations, chemical concentrations and pattern size were optimized through numerous sensitivity scenarios. Using a 5-spot pattern with a spacing of 75 m, surfactant-polymer injection effects should be observed within a short timeframe of around 14 months. This paper describes a successful approach to design a surfactant-polymer process, integrating laboratory experiments and reservoir simulation. This work paves the way for a 5-spot EOR pilot involving a major sandstone reservoir and will undoubtedly provide valuable insights for chemical EOR applications in similar reservoirs elsewhere.
Al Murayri, Mohammed T. (Kuwait Oil Company) | Hassan, Abrahim A. (Kuwait Oil Company) | Abdul Rahim, Abdulla (Kuwait Oil Company) | Decroux, Benoit (The EOR Alliance) | Negre, Andres (The EOR Alliance) | Salaun, Mathieu (The EOR Alliance)
Abstract This paper discusses the design and implementation of a Single Well Chemical Tracer Test (SWCTT) to evaluate the efficacy of a lab-optimized surfactant-polymer formulation for the Raudhatain Lower Burgan (RALB) reservoir in North Kuwait. A SWCTT was designed upon completing extensive lab and simulation work as discussed in a previous publication (Al-Murayri et al. 2017 and Al-Murayri et al. 2018). SWCTT design work was aimed at confirming the optimal injection/production sequence determined at core flood scale in terms of minimal volumes, rates and duration. The main uncertainties were assessed using numerous sensitivity scenarios. Afterwards, the SWCTT was implemented in the field and the results were carefully analyzed and compared to previously obtained lab andsimulation results. The main objective of this SWCTT was to validate the efficacy of polymer and surfactant solutions in terms of residual oil saturation reduction and injectivity. This invovles comparing residual oil saturation estimates before and after chemical flooding while monitoring injection rates and corresponding wellhead pressures. The SWCTT injection sequence included the following steps:Initial water-flooding, followed by tracer injection, soaking and production to measure oil saturation post water flooding. Pre-flush followed by a main-slug (with 5,000 ppm of surfactant and 500 ppm of polymer) and a post-flush (with only polymer). Sea-water push, followed by tracer injection, soaking and production to measure oil saturation post chemical flooding. Simulation work prior to the execution of the SWCTT test showed encouraging oil desaturation results post chemical flooding within a distance of 10 ft from the well. However, upon analyzing the pilot results, it was realized that there is a gap between the actual SWCTT results and previously obtained lab andsimulation results. This paper sheds light on the design and implementation of the above-mentioned SWCTTwith emphasis on the potential reasons for the realized gap between actual field data and lab/simulation results. The insights from this study are expected to assist in further optimization of surfactant-polymer flooding to economically increase oil recovery from relatively mature reservoirs.
Al-Murayri, Mohammed Taha (Kuwait Oil Company) | Hassan, Abrahim Abdulgadir (Kuwait Oil Company) | Al-Mahmeed, Narjes (Kuwait Oil Company) | Suzanne, Guillaume (Beicip-Franlab) | Sanchez, Juan-Pablo (Beicip-Franlab)
Abstract This paper sheds light on the design of a one-spot surfactant-polymer (SP) flooding pilot in a reservoir with oil viscosity greater than 1000 cP using a vertical well. The results of this pilot will be important to optimize the selected chemical formulation and finalize the recommended injection sequence with the purpose of de-risking subsequent multi-well surfactant-polymer flooding deployment. Based on systematic screening, preliminary laboratory evaluation and reservoir simulation, SP flooding was identified as a promising EOR method for the Ratqa Lower Fars (RQLF) reservoir in Kuwait. This was followed by extensive laboratory work to design a robust chemical formulation based on specific reservoir properties and operating conditions. The performance of the developed chemical formulation was validated by means of simulation. Thereafter, a one-spot EOR pilot, which is also referred to as a Single Well Chemical Tracer Test (SWCTT), was designed to assess the effectiveness of the selected chemical formulation mainly in terms of injectivity and oil desaturation. It was envisioned that the injectivity of a lab-optimized SP formulation for the RQLF heave oil reservoir needs to be confirmed in connection with oil desaturation using a one-spot EOR pilot due to the relatively high reservoir oil viscosity and low injection pressure to maintain cap rock integrity. Assuming favourable injectivity, incremental oil recovery in a one-spot EOR pilot is represented by the difference in residual oil saturation after water flooding and after chemical (SP) flooding. However, achieving low oil saturation as a result of waterflooding in a heavy oil reservoir takes a long time and requires large water volumes that are not applicable to full-field deployment. Therefore, the objective of the one-spot EOR pilot that is discussed in this paper was adjusted to validate oil desaturation as result of polymer and surfactant injection upon confirming water injectivity within a 3ft radius of investigation as outlined below: Initial water injectivity test Polymer solution injection Measurement of oil saturation Surfactant-polymer injection followed by polymer drive Measurement of oil saturation This paper describes a methodical approach to de-risk surfactant-polymer flooding in a heavy oil reservoir using a one-spot EOR pilot. There is limited reference in the literature, if any, to field deployment of surfactant flooding in heavy oil reservoirs with an oil viscosity of more than 1000 cP. The findings of this study can be used to evaluate and potentially improve the techno-economic feasibility of chemical EOR in heavy oil reservoirs with similar properties.
Al-Tameemi, Naser Majeed (Kuwait Oil Company) | Al-Subaihi, Meshari Ahmed (Kuwait Oil Company) | Al-Mayyan, Haya Ebrahim (Kuwait Oil Company) | Guillon, Valentin (IFPEN) | Company, Roberto (Solvay) | Bekri, Samir (IFPEN) | Negre, Andrès (Beicip-Franlab)
Abstract Um Gudair Minagish Oolite reservoir (UGMO), in Kuwait, is a high temperature mature carbonate field. It is also naturally water-flooded by a strong bottom active aquifer. Specifics challenges for Polymer (P) or Surfactant-Polymer (SP) chemical enhanced oil recovery (cEOR) are faced in high temperature carbonated reservoirs such as UGMO's field. P and SP process selection prior multiwell evaluation is addressed by a well-crafted laboratory approach. This involves extensive laboratory work including coreflood experiments to select the most effective processes in terms of oil recovery and cost-effectiveness. Softened sea water through nanofiltration two passes was considered as the most appropriate water source to be used in a SP cEOR process. Polymer was selected based on classical workflow relying on bulk measurements such as solubility, stability and viscosity, and on coreflooding experiments to characterize polymer injectivity and in-depth propagation. The selected polymer was also tested for compatibility with surfactant. SP formulation was designed and evaluated following a dedicated workflow in order to achieve low interfacial tension (IFT), high solubility, oil recovery and promising economics in reservoir conditions. The most favorable SP formulation regarding economics, surface facility modifications, operating costs and performances were evaluated through coreflood tests. The best SP formulation was selected based on chemicals in-depth propagation in reservoir core, incremental oil recovery and surfactant adsorption. The process was then optimized through additional corefloods to reduce chemicals dosage while keeping high oil recovery performances. Finally, the robustness towards both, rock and field variation conditions, was tested and confirmed. P and SP process were designed and proved to be both promising for UGMO's field. SP while using more chemicals than P process leads to a far better oil recovery as final oil saturation is decreased from 42% (P process) to 11% (SP process). As surfactant adsorption is a key parameter for both SP process efficiency and cost efficiency, several surfactant adsorption mitigation strategies were tested. Injection of a non-ionic surfactant after the main surfactant flood proved to efficiently manage surfactant adsorption despite of the very challenging conditions, allowing to reach very low adsorption level of 60 μg/g. Reservoir simulations showed afterwards that both P or SP process designed were economical at commercial pilot scale. Applied laboratory study on high temperature carbonate UGMO oil reservoir in Kuwait provides useful insights that can be used on other chemical EOR projects in such challenging conditions. This allows to select the most appropriate P or SP process and injection strategy while having reduced surfactant adsorption to very low levels in highly challenging conditions and enhanced profitability.