The Pelican Lake heavy oil field located in northern Alberta (Canada) has had a remarkable history since its discovery in the early 1970s. Initial production using vertical wells was poor because of the thin (less than 5m) reservoir formation and high oil viscosity (600 to over 40,000cp). The field began to reach its full potential with the introduction of horizontal drilling and was one of the first fields worldwide to be developed with horizontal wells. Still, with primary recovery less than 10% and several billion barrels of oil in place, the prize for EOR is large.
Initially, polymer flooding had not been considered as a viable EOR technology for Pelican Lake due to the high viscosity of the oil, until the idea came of combining it with horizontal wells. A first - unsuccessful - pilot was implemented in 1997 but the lessons drawn from that failure were learnt and a second pilot met with success in 2006. The response to polymer injection in this pilot was excellent, oil rate climbing from 43bopd to over 700bopd and remaining high for over 6 years now; the water-cut has generally remained below 60%.
This paper presents the history of the field then focuses on the polymer flooding aspects. It describes the preparation and results of the two polymer flood pilots as well as the extension of the flood to the rest of the field (currently in progress).
Polymer flooding has generally been applied in light or medium gravity oil and even today, standard industry screening criteria limit its use to viscosities up to 150cp only. Pelican Lake is the first successful application of polymer flooding in much higher viscosity oil (1,000-2,500cp) and as such, it opens a new avenue for the development of heavy oil resources that are not accessible to thermal methods.
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.
Chemical EOR projects were very active during 1980?s, however, during 90?s the interest in chemical EOR has fallen due to the low oil prices and also technical challenges that the methods poses. While surfactant flooding has difficult design considerations of chemicals, large capital requirements and is very sensitive to local reservoir heterogeneities, alkali can react strongly with minerals in the connate water and reservoir rocks may adversely impact the process. This complex process is yet to be understood. If the field is offshore, chemical EOR becomes even more challenging due to sophisticated logistics, incremental costs, highly deviated wells, larger well spacing and limited well slots on the platform. However, recently there has been a renewed interest in chemical flooding mainly due to valuable insights gained through chemical floods done in the past and better technical understanding of the processes and favorable economic conditions
For robust production forecasts, various uncertainties due to complex chemical processes should be quantified thoroughly. Some of the important uncertainties for full field production forecasts are chemical adsorption on rock surface, interfacial tension (IFT) and residual oil saturation reduction by chemical. Proper coreflood experiments are critical to reduce these uncertainties. Careful matching of coreflood experiments in numerical simulations is also important which provides key inputs for full field forecast. Another important element in the successful commercial application for chemical EOR process is a well-designed pilot. After the completion of pilot, the results should be carefully matched in the simulation model. Once satisfactory match is obtained, the key step would be to upscale the results to the full field level.
Discussed in this paper are the impact of some of these uncertainties and the method used to reduce them. In this paper the workflow and key tasks in dealing with the simulation of chemical EOR process elements like residual oil saturation, IFT reduction and adsorption parameters are discussed. The results show that the incremental oil is very sensitive to the various simulation inputs.
Chemical injection in enhanced oil recovery (EOR) projects is a complex process because it involves multiple chemicals with complex fluids. Costs for even a small-scale pilot test could be up in the millions of US dollars (USD) and large-scale field-wide expansion would be in the 100s of millions USD for onshore projects. Costs for offshore projects would increase by multiple folds compared to onshore projects with comparable sizes.
This paper discusses (1) conventional designs for small- or large-scale injection facilities, (2) recent improvements in conventional designs, and (3) new concepts in chemical injection facility designs that can improve the quality, lower the cost, and reduce the lead time in the implementation of chemical EOR (CEOR) projects.
Trigos, Erika Margarita (Ecopetrol) | Vega Moreno, Sandra Milena (Corporacion Natfrac) | Rodriguez-Paredes, Edwin (Ecopetrol SA) | Rivera de la Ossa, Juan Eduardo (Ecopetrol SA) | Naranjo-Suarez, Carlos Eduardo (Ecopetrol S.A.)
In the design phase of a pilot project for Enhanced Oil Recovery, more commonly referred as EOR, is important the prediction of the results by either numerical simulation or analytical modeling. Those tools are useful for the determination of the minimum conditions necessary for the implementation of the recovery method as well as to determine the feasibility of the project.
The more complexity degree of the process the more accurate the fluid model require. For example, to represent the steam injection process, any viscosity curve representing the behavior of known relative permeability curves with temperature is enough. Moreover, Enhanced Oil Recovery-EOR methods as in situ combustion, gas injection or miscible solvent injection (alone or assisted vapor) fluid require a more complex model representing all consistently appropriate physical-chemical changes that occur in the crude blend with a foreign agent.
The development of a numerical model of fluid to represent of injection processes of steam assisted with solvent. This model requires a previous experimental evaluation, which should include PVT characterization of solvent and oil, viscosity curves and miscibility conditions. Once they are developed in the lab tests, it should load the information obtained in a fluid modeling software, where the dead oil, live oil, blend live oil and solvent must be adjusted using equations of state. In this case, the equation of state that best represents the behavior of heavy oil and solvent is Peng Robinson. The most important matching parameters are: critical temperature and critical pressure, although it should be given special treatment with the binary interaction coefficients. Finally be obtain the equilibrium constants and viscosity tables, maintaining minimum allowable error of less than 5% compared to the laboratory data, which is important to reduce the uncertainty associated with the behavior of fluids.
This paper presents a detailed methodology to represent numerically the behavior of fluids in a steam injection process enhanced with solvent in heavy oil reservoirs, applied to a Colombian field.
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.
In May 2006, the Warner Mannville B ASP flood was the first field wide ASP flood implemented in Canada. The objective was to successfully implement a commercially viable ASP flood. In this project produced water is treated and reinjected into the reservoir. As of December 2012, an incremental 420 103m3 (2.65 million bbl) of oil has been recovered with an expected total incremental recovery of 777 103m3 (4.89 million bbl), which represents 11.1% of the OOIP. In October 2008, after 0.35 pore volume of ASP injection, the project moved into the Polymer only injection phase. Polymer injection will continue as long as is economically feasible.
A comprehensive monitoring and testing program was implemented to evaluate flood response and performance. This allowed for the optimization of the flood through continuous adjustment to flow rates and led to successful infill drilling locations.
Many challenges have been encountered during this project, including: silicate scale production, treating issues related to the water quality of the recycled injection water, and loss of injectivity in many injection wells.
The challenges were overcome and it has been an economic success with a cumulative positive cashflow within 5 years. The results of this flood have led to the implementation of an additional four floods. The lessons learned from this project have improved numerous aspects of how future floods are designed and implemented.
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.
Wu, Yongbin (PetroChina Co. Ltd.) | Li, Xiuluan (Research Inst. Petr. Expl/Dev) | Liu, Shangqi (Research Inst. Petr. Expl/Dev) | Ma, Desheng (Expl & Dev Rsch Inst Liaohe Co.) | Jiang, Youwei (Research Inst. Petr. Expl/Dev)
Thermal recovery technology particularly cyclic steam stimulation (CSS) is always an effective means to develop the conventional heavy oil reservoirs, which can be validated from literature. While most of the heavy oil reservoirs developed by CSS are the thick, well-deposited, high quality reservoirs and there are no much reports of producing oil from mid-depth oil reservoirs with large acquifers.
In this paper, according to the petrophysical properties and geologic characteristics of the target block F in Greater Fuld oilfield in Sudan, based on the oil test results, detailed 3D geologic model is established and the type well model for CSS and SF is extracted, to study the real performance with the real geological properties.
The development zone, the perforation strategies, the cylic steam injection quantity, the steam injection rate, soak time, and cyclic period are optimized for CSS. Based on the production performance of CSS, the optimal cycles of CSS followed by SF is determined. And the wellpattern and well spacing, the parameters of SF such as unit steam injection rate, steam quality, effects of bottom acquifer on the SF are also simulated and optimized. The simulation results indicate that the thermal recovery technique especially 4 cycles of CSS followed by SF can acquire satisfied performance, which shows an effective and economic future in the development of the heavy oil deposits in Greater Fula Oilfield.
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.