Enhanced Oil Recovery (EOR) has been touted as the Holy Grail for achieving the highest possible recovery factor. This technology is fairly matured in land based development, with older fields in Bakersfield and Indonesia achieving up to 90% recovery factors. However, EOR considerations take on a whole new dimension in an offshore environment. Astronomical rig rates and escalating operational costs have deterred operators from pursuing ambitious offshore EOR programs.
Most EOR pre-development studies are focused on the reservoir; in particular altering relative permeabilities, reducing residual hydrocarbon saturations, and improving sweep efficiencies. But with up to 40% of slated huge EOR capital development cost earmarked for well construction, more technical focus should be emphasized on well architecture.
This paper details the well architecture work done on several Malaysian fields scheduled for EOR redevelopment. A workflow featuring the various design and operational considerations is explained. Well architecture is composed of two main components: Trajectory and completions functionality. Malaysia's portfolio of complex reservoirs requires EOR development to be done through a creative lens of complex trajectories and multilateral wells. Marginal economics have precluded the practicality of conventional well construction.
A key enabler in cost efficient EOR redevelopment is advanced completions, namely remote downhole flow control and monitoring. In order to achieve incremental production beyond secondary recovery, reservoir conformance is of critical importance. Remote real time monitoring will allow decisions to be made accurately in a timely manner. Downhole flow control permits purposeful manipulation of injection and production streams. Proper installations of advanced completions will also reduce future intervention and operational costs.
Advanced well architecture however, also comes with a whole range of operational and installation risks. But these can be mitigated with proper planning and coordination with all parties involved.
Zhu, Youyi (Research Inst. Petr. Expl/Dev) | Wang, Zhe (Research Institute of Petroleum Exploration and Development, CNPC) | Wu, Kangyun (Research Inst. Petr. Expl/Dev) | Hou, Qingfeng (Research Institute of Petroleum Exploration and Development, CNPC) | Long, Hang (Research Institute of Petroleum Exploration and Development, CNPC)
Lab study of chemical EOR for the carbonate reservoir was performed through core characterization, chemical formula screening, surfactant adsorption losses experiments and oil displacement core flooding tests of chemical flooding.
The research results lay the foundation of future pilot tests for chemical combination flooding applying to carbonate reservoirs.
Core characterization by scanning electron microscope and mercury injection capillary pressure experiment prove that there are plenty micropores and a few emposieu within rock, porosity of formation cores is relatively high but permeability is low, the reservoir lithology belonged to typical biostromal carbonate reservoir and the heterogeneity is severe. Chemical flooding formula was investigated by polymer and surfactant screening tests. Salt tolerant polymers including STARPAM and KYPAM showed good viscosifying performances than conventional polymer when prepared with formation water. Amphoteric surfactant AS-13 and anion-nonionic surfactant SPS1708 were selected and ultra-low interfacial tension between crude oil and formation water can be obtained in alkali-surfactant-polymer (ASP) and alkali free surfactant-polymer (SP) systems. Adsorption losses of surfactants on core sample showed that the dynamic adsorption losses of surfactant AS-13 and SPS1708 were 0.46mg/g and 0.37mg/g respectively. Core flooding tests of chemical flooding proved that more than 17~18% incremental oil recovery over water flooding could be obtained with ASP (0.6wt% Na3PO4 + 0.3wt% surfactant + 1000ppm polymer) or SP (0.3wt% surfactant + 1000ppm polymer) flooding. The effect of both ASP and SP flooding was better than that of surfactant flooding.
The experimental results are considered to be technical feasibility and confirm the effectiveness of chemical EOR methods especially the SP flooding for the biostromal carbonate reservoir, which may present further understanding for chemical EOR field application in carbonate reservoirs.
Surfactant flooding is an enhanced oil recovery process used to mobilize the residual oil by lowering the interfacial tension (IFT) between oil and water. When surfactants are mixed with brine and oil, oil in water, water in oil microemulsions could be formed with region of ultra low IFT. The ability to predict the number of phases formed, their relative amount, and compositions at a particular reservoir brine concentration is crucial for successful CEOR planning.
Equations of state (EOS) such as the Peng-Robinson (PR) and Soave-Redlich-Kwong (SRK) are usually used to predict the phase equilibrium. They require critical properties and accentric factors of the components. However, since oil and surfactants are not pure substances, they are treated as pseudo-components for which the pseudo critical properties must be estimated. Also, PR and SRK EOS are originally developed for non-ionic, non-polar and non-associating hydrocarbons. These pose some limitations in their application to surfactant/Brine/Oil mixture.
This study presents a new computational model to estimate surfactant/brine/oil ternary phase behaviour using PR EOS. In this study we have adopted group contribution model (GCM) using information from the molecular structure of the pseudo components for the estimation of their critical properties. A numerical solution is developed for solving the system of nonlinear equations governing the phase equilibrium by means of Newton-Raphson iterative procedure.
Phase behavior experiments were conducted at temperature of 50oC using Alfa Olefin Sulfonate (AOS) surfactant, decane and brine. Brine concentrations were varied at each temperature and phase relative amount and compositions were determined. The laboratory results were compared with the results predicted by the model. The study shows the level of reliability of our new predictive model. The model developed can be used in compositional simulation of surfactant flooding operations and should prove to be an invaluable tool in planning and evaluation of surfactant flooding processes.
Konishi, Yusaku (Japan Oil, Gas and Metals National Corporation) | Takagi, Sunao (Japan Oil, Gas and Metals National Corporation) | Farag, Sherif (Sclumberger) | Ha, Vo Viet (Japan Vietnam Petroleum Co., Ltd.) | Hatakeyama, Atsushi (JX Nippon Oil & Gas Exploration Corporation) | Trung, Phan Ngoc (Vietnam Petroleum Institute) | Son, Le Ngoc (PetroVietnam)
The application of the Carbon Dioxide Enhanced Oil Recovery (CO2-EOR) to an offshore oilfield in Vietnam has been investigated through an international joint study between Japan and Vietnam since 2007. In order to reduce and mitigate uncertainties and risks for future field scale application, a CO2-EOR pilot test was conducted in the Rang Dong field, offshore Vietnam in 2011.
The pilot test was conducted as a single-well "Huff-n-Puff?? operation which was designed to minimize the test duration, required CO2 volume to observe the meaningful CO2-EOR effects and to reduce the risk of corrosion to the existing facility. Over 100 tons of CO2 were successfully injected into the Lower Miocene sandstone reservoir and the well was flowed back after two days of soaking time. Various parameters were monitored including production rate, bottom-hole pressure and production fluid properties. To investigate the CO2-EOR effects and for the purpose of monitoring the reservoir fluid saturation change, cased hole pulsed neutron saturation logging was carried out during every stage of the test. These logging operations and their timing were carefully designed to avoid any possibility of fluid contamination and to minimize operation time.
Through the analysis of the acquired logs, vertical contrast of preferential CO2 injection, zonal oil saturation change, oil saturation change with time within single run, etc., were clearly identified. These observations played important roles in evaluating the CO2-EOR effect in detail by comparing them with the reservoir simulation prediction.
In this paper the detailed design for the reservoir fluid saturation monitoring, observed results and three-phase fluid saturation changes wtih time are discussed.
Choudhuri, Biswajit (Petroleum Development Oman) | Kalbani, Ali (Petroleum Development Oman) | Cherukupalli, Pradeep Kumar (Petroleum Development Oman) | Ravula, Chakravarthi V. (Petroleum Development Oman) | Hashmi, Khalid (Petroleum Development Oman) | Jaspers, Henri F (Petroleum Development Oman)
In viscous oil reservoirs, Polymer flooding is often used to improve oil recovery either after a short period of waterflooding or as a tertiary recovery process following extensive period of waterflood. After six years of water flooding in a major reservoir in Sultanate of Oman having viscous oil (90cp), a field development plan was developed to implement polymer flooding in this reservoir with anticipated incremental oil recovery of around 10% over and above that of waterflood. Necessary facilities were constructed, injection and production wells were drilled, completed, converted and the polymer flood project was initiated and ongoing since the last three years through 27 polymer injectors. By implementing proactive Well and Reservoir Management (WRM) strategies, the actual oil recoveries have been better than predicted levels so far. It is demonstrated here that proactive well and reservoir management through proper well and reservoir surveillance and dynamic adjustment of injection and production rates play a very important role in improving the performance of polymer floods as in waterfloods.
Well and Reservoir Management (WRM) principles in case of a polymer flood are similar to that of high mobility ratio waterfloods with some additional aspects that are specific to a polymer flood scenario. Polymer chemical costs, its higher viscosity and non Newtonian fluid flow behavior all create unique conditions that are nonexistent in normal waterfloods. This, in turn, dictates the strategies and methods employed to optimize polymer flood performance. This paper details successful implementation of proactive WRM strategy that has played a key role in sustaining production from this polymer flood field to date. It describes the pattern management processes to optimize pattern wise polymer injection and oil recoveries, conformance control measures implemented to increase sweep and oil recovery, innovative surveillance techniques to monitor fracture growth in polymer injection wells and for evaluation and optimization of production/injection profiles. Production wells and facilities issues arising from polymer breakthrough are being addressed to mitigate any adverse effects.
Thakuria, Chandan (Petroleum Development Oman) | Al-Amri, Mohsin Saud (Petroleum Development Oman) | Al-Saqri, Kawthar Ahmed (Petroleum Development Oman) | Jaspers, Henri F (Petroleum Development Oman) | Al-Hashmi, Khalid Hamad (Petroleum Development Oman) | Zuhaimi, Khalid (Petroleum Development of Oman)
The first field scale Polymer flood project in the Middle East region is being implemented in an oil field of Sultanate of Oman from early 2010. The oil field discussed here containing viscous oil (90 cp) was discovered in 1956 and is located in eastern part of South Oman Salt basin. First commercial production started in 1980 from this field. The field has gone through different development phases in its 30 years of history prior starting tertiary recovery phase by polymer flooding.
This field scales Polymer flood project comprising 27 patterns as Phase-1 covers about one third of the total field IOIP (initial oil in place). It is worth mentioning that whole field is under water flooding and water injection was going on prior to initiation of Polymer flood in all these 27 injectors. Further extension in phases to full field polymer flooding is under evaluation.
Till now this Polymer flood project has successfully completed 3 years of good performance contributing to significant oil gain. This paper describes briefly about the principles involved in polymer flooding, planning of this polymer flood project, field implementation and field examples of polymer response. In addition, a few practical aspects of managing key issues in polymer flooding like- fracture growth in injectors, shear degradation of polymer solution, pattern conformance and back produced polymer has been covered in this paper.
This paper discusses a structured combination of procedures used to investigate polymers for EOR application with the focus on performance, compatibility with production chemicals and phase behaviour. This approach allows for early identification of risks and points to further work necessary for mitigation before field implementation. The case studied here was a system with total dissolved solids (TDS) of 80000 mg/l and temperature requirements of 40 to 70 oC. Effective screening of polymers has benefited from dissolution/viscosity, thermal stability and filtration tests. At lower temperatures (40 oC), polymers were shown to be fit-for-purpose for the conditions evaluated. All polymers showed loss of viscosity with some leading to complete viscosity loss at increased temperatures. This is the result of hydrolysis and interaction with the divalent cations present in the make-up synthetic brine. In-situ viscosity allowed for identification of phase behaviour effects which could affect injectivity (difference in apparent and rheometer viscosity). For the best performing polymer the presence of corrosion and scale inhibitors did not affect viscosity. No detrimental effects on corrosion inhibition and water in oil emulsions were observed. Increases in oil in water with potential fouling/deposition was identified for future study.
Foam assisted CO2 enhanced oil recovery has attracted increasing attention of oil companies (operators and service companies) and research institutions mainly due to the potentially high benefit of foam on CO2-EOR.
Miscible and immiscible CO2 flooding projects are respectively proven and potential EOR methods. Both methods have suffered from limited efficiency due to gravity segregation, gas override, viscous fingering and channeling through high
permeability streaks. Numerous theoretical and experimental studies as well as field applications have indicated that foaming of CO2 reduces its mobility, thereby helping to control the above negative effects. However, there are still various conceptual and operational challenges, which may compromise the success and application of foam assisted CO2-EOR.
This paper presents a critical survey of the foam assisted CO2-EOR process to reveal its strengths, highlight knowledge gaps and suggest ways. The oil recovery mechanisms involved in CO2 foam flood, the effect of gaseous and soluble CO2 on the process, synergic effect of foaming agent and ultra-low IFT surfactants, logistic and operational concerns, etc. were identified as among the main challenges for this process. Moreover, the complex flow behaviour of CO2, oil, micro-emulsion and brine system dictates a detailed study of the physical-chemical aspects of CO2 foam flow for a successful design. Unavailability of reliable predictive tools due to the less understood concepts and phenomena adds more challenges to the process results and application justifications.
The study highlights the recent achievements and analysis about foam application and different parameters, which cannot be avoided for a successful foam assisted CO2 flood design and implementation. Accordingly, the study also addresses prospects and suggests necessary guidelines to be considered for the success of CO2 foam projects.
Sorop, Tiberiu Gabriel (Shell Global Solutions International) | Suijkerbuijk, Bart M.J.M. (Shell Global Solutions International) | Masalmeh, Shehadeh K (Shell Technology Oman) | Looijer, Mark T. (Shell Global Solutions International) | Parker, Andrew R (Shell Global Solutions International) | Dindoruk, Deniz M (Shell Exploration & Production Co) | Goodyear, Stephen Geoffrey (Shell E&P UK) | Al-Qarshubi, Ibrahim S.M. (Shell Global Solutions International)
Low Salinity Waterflooding (LSF) is an emerging IOR/EOR technology that can improve oil recovery efficiency by lowering the injection water salinity. Field scale incremental oil recoveries are estimated to be up to 6% STOIIP. Being a natural extension of conventional waterflooding (WF), LSF is easier to implement than other EOR methods. However, the processes of screening, designing and executing LSF projects require an increased operator competence and management focus compared to conventional waterflooding. This paper discusses the practical aspects of deploying LSF in fields, focusing on the maturation stages, while highlighting the key success factors.
LSF deployment starts with a portfolio screening against specific surface and subsurface screening criteria to prioritize opportunities. Next, the identified opportunities are run through reservoir conditions SCAL tests to quantify the LSF benefits, while de-risking the potential for any injectivity loss due to clay swelling or deflocculation. Standardized LSF SCAL protocols have been incorporated into the general WF guidelines, so that any suitable new WF project conducts LSF SCAL. For mature waterfloods, this SCAL program provides additional reservoir condition relative permeability data, enabling operating units to optimize well and reservoir management (WRM). The next steps in the process are production forecasting, facilities design, and project economics for the LSF opportunity. The multidisciplinary nature of LSF deployment requires integrated (sub)surface technology teams closely collaborating with R&D and asset teams. The standardization of the facilities design, including cost models, can significantly accelerate the deployment effort.
In Shell, LSF is currently at different stages of deployment around the world and across the whole spectrum of WF projects, from the rejuvenation of brown fields to green field developments (offshore and onshore). The LSF deployment effort is combined with the screening of other EOR technologies, to identify where LSF may be able to unlock additional value by creating the appropriate conditions for subsequent chemical flooding.
Polymer flooding is investigated in laboratory corefloods for potential application in a 2000 cP - 5000 cP heavy oil field. An incremental oil recovery is noted with the addition of very low concentrations of partially-hydrolyzed polyacrylamide (HPAM), either in secondary or tertiary (i.e. after waterflooding) injection. However, increasing polymer viscosity from 3 cP to 60 cP does not significantly change recovery from two pore volumes (PV) of tertiary polymer injection.
Existing scaling groups for viscous instability are investigated. Corefloods in this study and others are found to be in or near the transition zone, where recovery may be sensitive to variables such as core diameter, while field floods are all in the "pseudo-stable?? region, where this may not be the case.
Mounting evidence suggests that polymer flooding can be economically applied to very viscous oils, despite the fact that it is not feasible to obtain unit mobility ratio with non-thermal methods. Additional work is necessary to determine appropriate optimization methods and criteria for these floods.