Enhanced oil recovery (EOR) is fundamental to increasing the ultimate recovery of a reservoir. Among several parameters that govern the success of an EOR project, profile modification is a key factor when flooding heterogeneous reservoirs with multiple zones. Given the time and economic constraints, simultaneous flooding of all zones of interest is preferred although it can be difficult for reasons such as a varying pressure and fluid injectivity/productivity profile caused by permeability contrasts between zones. Injection fluids can bypass low-permeability oil-saturated zones, not achieving the full benefit of injection if the profile is not properly modified. Failure to modify production profiles can lead to early water and gas breakthrough. To mitigate these problems, various approaches such as mechanical downhole equipment or chemical treatments have been used.
This paper presents a comparison of the use of mechanical versus chemical conformance control systems in different scenarios. Conformance control is defined as the process that helps improve the drive mechanism for better sweep of reservoir. The basic premises of both mechanical and chemical systems are introduced. Their applicability, operational benefits, and disadvantages are also described. A 3D reservoir simulator is used to illustrate the varying sweep efficiencies, depending on the conformance control method used. The result from the best case with both injector and producer profile modification demonstrated nearly double the oil recovery compared to the base case with no treatment.
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.
Haynes, Andrew Kenneth (Chevron Australia Pty Ltd) | Clough, Martyn David (Chevron Australia Pty Ltd) | Fletcher, Alistair J. P. (Chevron Australia Pty Ltd) | Weston, Stuart (Chevron Australia Pty Ltd)
Barrow Island's Windalia reservoir is Australia's largest onshore waterflooding operation and has been under active waterflood since 1967. The highly heterogeneous reservoir consists of fine-grained, bioturbated argillaceous sandstone that is high in glauconite clay. The high clay content results in a low average permeability (5 md) despite high porosities (25-30%) and hence fracture stimulation is required to achieve economic production rates.
The Windalia reservoir and fluid properties preclude the use of traditional EOR technology, with thermal, miscible and mobility control processes all deemed unfeasible through screening studies. Consequently, the in-depth flow diversion mechanism was developed and applied, which utilizes a low molecular weight polymer to drive the growth of induced hydraulic fractures in the treated injection wells. A 3-injector pilot was executed involving polymer injection for two years, with no detrimental injectivity losses observed for polymer concentrations up to 750 ppm. Considerable fracture growth, oil production rate uplift and reduction in water cut were observed throughout the pilot pattern, in line with predictions:
• Fracture half-lengths increased from 6 ft to 400 ft in one injector and from 141 ft to 322 ft in another
• An initial oil rate uplift of 38% relative to the production baseline was observed; a more conservative estimate suggested that at least half of this was attributable to the tertiary recovery process
• The water-oil ratio was observed to fall from 15 to 11, similarly timed with the oil production increase.
These improvements were observed consistently throughout the pilot area and were distinct from the waterflood behavior elsewhere in the field. This paper briefly summarizes the technology screening and pilot execution stages, after which the results from the pilot are presented and discussed. This technology may be of use in other low-permeability waterfloods with induced injector fractures, for which traditional EOR practices are believed to be unfeasible.
This paper illustrates an innovative field-scale application of injecting condensate gas and recycling gas in Jake field, Sudan. This field has two production series, namely AG condensate gas pools and Bentiu oil pool from bottom to up, with the former 3520 ft. below the Bentiu reservoir and 1695 psi of initial reservoir pressure difference. Bentiu pool of Jake field is a medium crude oil (29 API) pool with strong aquifer support. Well productivity was 500 BOPD. Operator intended to inject high-pressure condensate gas into Bentiu pool to increase field output, whereas was confronted with following challenges: 1) injection of condensate gas in an easy-to-operate wellbore configuration; 2) optimization of injection parameters to achieve highest output; 3) suppress aquifer water breakthrough.
Field scale application had been optimized and implemented since 2010:1) High-pressure condensate gas had been injected into two updip crest Bentiu wells in the same well bore, following a huff-and-puff process, well output amounted 4,000 to 13,800 BOPD under natural flow; 2) 1/4 recycling gas volume from compressors was re-injected into 12 downdip wells at controllable pressure to avoid early water breakthrough; 3) The remaining recycling gas was utilized to gas-lift other five updip wells.
Oil producers were reduced from 19 to 7 comparing to original field development plan, while oil rate ascended from 22,000 to 30,000 BOPD, with watercut dropping to 7% from 15%, achieving a high offtake rate of 6%. Reservoir simulation indicated ultimate recovery factor is expected to be over 50% with such full-field gas injection.
Conclusions drawn from field scale injection of condensate gas and recycling gas were as follows:1) condensate gas injection in the same well bore was technically innovative and operationally robust; 2) recycled gas injection into downdip wells helped detain water breakthrough; 3) field scale application had evidenced outstanding success with high output and high offtake rate.
Mohd Shafian, Siti Rohaida (PETRONAS Research Sdn Bhd) | Kamarul Bahrim, Ridhwan Zhafri (PETRONAS Research Sdn Bhd) | Abdul Hamid, Pauziyah (Petronas Research Sdn Bhd) | Abdul Manap, Arif Azhan (PETRONAS Research Sdn Bhd) | Darman, Nasir B. (PETRONAS) | Sedaralit, Mohd Faizal (PETRONAS) | Tewari, Raj Deo (Petronas Carigali Sdn Bhd)
This paper discusses laboratory results of enhancing the performance of water alternating gas (WAG) injection process. Currently, field is under primary and secondary phases. It is light oil with moderate to good reservoir characteristics and relatively higher in reservoir temperature between 92 - 101oC and higher CO2 percentage in produced gas. Field is in decline phase and rise in water cut and GOR values. Redevelopment strategy of the field includes optimization of well spacing and WAG application to maximizing the oil recovery. One of the key challenges faced on WAG injection is gas overriding. Therefore, it becomes important to control the gas flood front during gas injection cycle of WAG and allowing the reservoir to reach to Sorg level.
The study will focus on measuring the variation of petrophysical parameters for surfactants that has bulk foam stabilization properties. In addition to classical foam Mobility Reduction Factor (MRF) determination, effect of foam on gas saturation has also been monitored along the core using in-situ X-ray monitoring tool. Propagation of foam in porous media is less understood and application of X-ray monitoring for gas saturation in dynamic condition helps to understand this to great extent.
Experiments have been carried out on Berea and reservoir cores mounted on dedicated X-Ray-equipped core flood bench. The core, initially at Swi, is flooded up to Sorw with water followed by gas injection to Sorg level to establish the reference condition for WAG. A slug of surfactant solution is then injected followed by gas prior to co-injection of surfactant and gas (83 % quality foam). Fluid propagation in core is correctly monitored for every 0.1 PV injection of fluids. The results suggest efficient mobility control by achieving required MRF in presence of ROS. High MRF is an essential ingredient for the success of the process. These results are also correlated with a homogenization of the gas front in presence of foam.
Foaming of nitrogen stabilized by C14-16 alpha olefin sulfonate in natural sandstone porous media, previously subject to water flooding, was studied experimentally. Foam was generated in-situ by co-injecting gas and surfactant solution at fixed foam quality. Effect of surfactant concentration on the foam strength and foam propagation was examined. X-ray CT scans were obtained to visualize the foam displacement process and to determine fluid saturations at different times. The experiments revealed that stable foam could be obtained in the presence of water-flood residual oil. CT scan images, fluid saturation profiles and mobility reduction factors demonstrated that foam exhibited a good mobility control in the presence of water-flood residual oil. This was further confirmed by a delay in the gas breakthrough. The experiments also proved that immiscible foam displaced additional oil from water-flooded sandstone cores, supporting the idea that foam is potentially an effective EOR method. Foam flooding provided an incremental oil recovery ranging from 13±0.5% of the oil initially in place for 0.1 wt% foam to 29±2% for 1.0 wt% foam. Incremental oil due to foam flow was obtained first by a formation of an oil bank and then by a long tail production due to transport of dispersed oil within the flowing foam. The oil bank size increased with surfactant concentration, but the dispersed oil regime was less sensitive to the surfactant concentration.
Mohd Anuar, Siti Mardhiah (Universiti Teknologi Malaysia) | Jaafar, Mohd Zaidi (Universiti Teknologi Malaysia) | Wan Sulaiman, Wan Rosli (Universiti Teknologi Malaysia) | Ismail, Abdul Razak (Universiti Teknologi Malaysia)
Spontaneous potential (SP) is commonly measured during reservoir characterization. SP signals are also generated during hydrocarbon production due to the streaming potential occurrence. Measurement of SP could be used to detect and monitor water encroaching on a well. SP signals could also be monitored during production, with pressure support provided by water alternate gas (WAG) process. The objectives of this study are to quantify the magnitude of the SP signal during production by WAG injection and to investigate the possibility of using SP measurements to monitor the sweep efficiency.
Measurement of streaming potential has been previously proposed to detect the water encroachment towards a production well. The peak of the signal corresponds to the waterfront where there is a change of saturation from ionic water to non-polar hydrocarbon. Similar trend is predicted in the case of WAG where we have several interfaces between the injected water and the injected gas.
The results indicate that the magnitude of the SP generated in hydrocarbon reservoir during WAG process can be large and peaks at the location of the moving water front. Gas, which can be assumed to be non-polar, exhibit no electrokinetic effect. These observations suggest that WAG displacement process can be monitored indirectly from the signal acquired. Water or gas override can be detected and controlled if wells were equipped with inflow-control valves. As a conclusion, the SP measurement is a promising method to monitor the effectiveness of a WAG process.
This study is significant because monitoring the progress of water and gas in a WAG process is key in the effectiveness of this enhanced oil recovery method. Measurement of the streaming potential provides another method besides using tracers to monitor the WAG profile. Better monitoring will lead to more efficient displacement and great benefits in term of economy and environment.
Castro, Ruben Hernan (ECOPETROL, S.A.) | Maya, Gustavo Adolfo (Ecopetrol SA) | Sandoval, Jorge (Ecopetrol SA) | Leon, Juan Manuel (Ecopetrol SA) | Zapata, Jose Francisco (Ecopetrol SA) | Lobo, Adriano (Ecopetrol SA) | Villadiego, Darwin Oswaldo (ECOPETROL, S.A.) | Perdomo, Luis Carlos (ECOPETROL, S.A.) | Cabrera, Fernando Ariel (TIORCO, Inc.) | Izadi, Mehdi (TIORCO, Inc.) | Romero, Jorge Luis (TIORCO Inc) | Norman, Charles (TIORCO, Inc.) | Manrique, Eduardo Jose (TIORCO, Inc.)
Dina Cretaceous Field is located in the Upper Magdalena Valley (UMV) Basin, Colombia. Dina Field operated by ECOPETROL S.A. (discovered, 1969) started peripheral water in 1985. Based on high water cuts (96%) and recovery factors of 32%, comprehensive enhanced oil recovery (EOR), screening evaluation began late 2009, identified Colloidal Dispersion Gel (CDG) as an optimum EOR method for the field.
This paper summarizes Dina CDG project from the laboratory to the field evaluation. Laboratory studies include basic fluid/fluid evaluation, static adsorption, CDG formulations, slimtube, and coreflood tests. Pilot area selection was based on a comprehensive reservoir and injection/production data analysis, water management, well integrity, among other factors. Pilot design was based on detailed numerical simulations using sector and full field models. CDG pilot design also considered water handling limitations and potential injectivity constraints due to the narrow margin of maximum injection and reservoir pressures, combined with low reservoir permeability (50 to 200 mD).
Peripheral CDG pilot included one injector and three producers. CDG injection began in June 2011 and as of September 2012, approximately 437,000 bbl of CDG have been injected (5% of pilot PV). CDG injection strategy considered a fix polymer concentration of 400 ppm and a variable polymer/crosslinker ratio ranging from 40:1 to 80:1; to control maximum injection pressure. Field results showed an important increase in oil recoveries (oil productivity up to 300%) and reduction of water cut decrease (10%). After 16 months, no polymer had been produced in offset producers. Main operating challenges experienced during the pilot project included; the improvement in water quality and its impact on CDG injectivity which will also be described.
This study provides guidance to successfully design, implement, and evaluate CDG pilot projects and other potential chemical EOR technologies in waterflooded reservoirs. Lessons learned during pilot testing contributed to defining pilot expansion strategies supported by an integrated decision-risk management approach.
Tewari, Raj Deo (Petronas Carigali Sdn Bhd) | Bui, Thang (Schlumberger) | Sedaralit, Mohd Faizal (PETRONAS) | Kittrell, Chuck M (Schlumberger IPM-RMG) | Riyadi, Slamet (Petronas Carigali Sdn Bhd) | Rahman, Hibatur (Petronas Carigali Sdn Bhd)
This paper discusses about the optimization study of applying the enhanced oil recovery technique in a multilayered mature offshore oilfield. This field is located at water depth 65-70 m. There is significant variation in rock and fluid properties from top to bottom in the field. Upper sands are highly porous and permeable, poorly consolidated and hold viscous oil.Whereas lower formations are fully consolidated and contain lighter oil with a high GOR. Oil in most of these reservoirs are under- saturated. The field is under primary production for the last 30 years with appropriate sand control and artificial lift measures.
Production performance indicates that current development strategy and practices will yield a moderate recovery lower than average recovery in Malay basin fields. A comprehensive reservoir characterization has been carried out to capture the reservoir heterogeneity and multiple realizations of reservoir properties distribution have been used to understand the major uncertainties of the field. Performance analysis combined with simulation modeling identified a suitable EOR application with appropriate well spacing to maximize the drainage of undrained oil while improving the sweep from partially drained portions of the reservoirs. Since the field is in mature stage of the producing life, delaying the enhanced oil recovery application may not be a sound strategy for maximizing the recovery. Improving the well density and applying EOR should be part of a redevelopment strategy. Exhausting the option of primary production and then embarking on enhanced oil recovery application may be detrimental in maximizing the value of the asset. Water alternating gas injection (WAG) in immiscible mode has been firmed up for improving the oil recovery from this offshore field. The improvement in recovery due to WAG injection is attributed to contact of the upswept zones and modification of residual oil saturations and targeting the attic oil. The combination of water and gas injection in WAG improves the microscopic displacement efficiency and increases the mobile oil saturation. Hysteretic effects which change saturation paths, due to sequential injection of water and gas, additionally improve the recovery. Thus the combined effect of water and gas injection in improving the recovery in WAG is better as compared to separate gas or water injection. Three phase flow (oil, water and gas) is better in displacing the residual oil compared to two phase flow water and oil or gas and oil.
One of the major challenges envisaged in the application of EOR in a multilayered reservoir with very large thickness is poor conformance of injectants. This is critical for the success of the process. Parameters which are critical for impacting the WAG enhanced oil recovery process are studied thoroughly. The study suggests that improving the well spacing and proper injection volume with good conformance control and timely initiation of the process would result into an improvement of recovery factor on the order of 8-10%. The paper also discusses the laboratory results of mechanism of formation damage with water injection and rock-fluid interaction.
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.