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.
Polymer flooding is a well established tertiary EOR technique to improve mobility control of a waterflood. Currently partially hydrolyzed polyacrylamide (HPAM) is the industry workhorse in polymer EOR in reservoirs with low salinity and temperature. Biopolymers including hydroxyethylcellulose (HEC) and Xanthan are soluble and excellent viscosifiers in high salinity conditions. This paper will provide a literature review on the use of biopolymers for EOR and focus specifically on the benefits of HEC as a mobility control polymer.
With the depletion of light oil, heavy oil is becoming one of the most promising resources to meet future energy consumption. It is estimated that total resources of heavy oil are 3396 billion barrels worldwide. Water flooding can only achieve less than 20% of heavy oil recovery. Thermal recovery has been proven as a feasible method to recover heavy oil. But it is not suitable for thin layers and deep reservoirs due to excessive heat loss. Polymer flooding and CO2 flooding are potential EOR techniques for the heavy oil reservoirs not suitable for thermal recovery. However, polymer degradation and high costs seriously hinder its field applications. Carbon Dioxide immiscible flooding effectively recovers heavy oil thanks to several mechanisms, such as oil swelling, viscosity reduction and blow-down recovery. This paper discusses the developments in CO2 immiscible flooding at laboratory scale as well as field scale. Laboratory tests show that CO2 can significantly improve heavy oil recover by 30%. Several field cases in USA, Turkey and Trinidad are reviewed. Field experiences show that CO2 flooding is a successful EOR method for heavy oil fields. However, some issues are encountered in field applications, including early gas breakthrough, corrosion, CO2 availability and high costs.
Angsi field is slated to be the first in the world for Alkaline-Surfactant and Polymer (ASP) chemical flooding via a floating structure in an offshore environment. The chemical flooding will be for 3 years with 6 months of low salinity water pre-flush injection prior to chemical injection to condition the reservoir, and 6 months of treated seawater with polymer injection as post-flush activity. The chemical flooding will be conducted via injection of treated and partially desalinated seawater mixed with ASP chemicals produced from the floater which is tie-in to the existing Angsi water injection pipeline network (Figure 1.0). Angsi reservoirs will experience three (3) different salinity range exposures with two (2) as invading fluids with effects of chemical cocktail, wettability and fluid distribution. One of the main challenges for ASP flooding in an offshore environment is handling the chemical residuals breakthrough in produced water causing the water unable to be disposed overboard. To overcome this problem and to eliminate environmental pollution, a full scale Produced Water Re-Injection (PWRI) system with full integration to existing Angsi Produced Water Treatment (PWT) system should be adopted to meet the new water reinjection specifications. Since the PWRI water will be commingled with treated and partially desalinated seawater mixed with ASP chemicals from the floater, it is paramount to predict the range of salinity of the produced water over time to help to design the PWRI and Floater's water treatment system to achieve the final water quality and optimum salinity required for an effective ASP cocktail for re-injection. This paper will summarise the PWRI design and operation philosophy coupled with subsurface studies to predict salinity profiles for the produced water.
Lawrence, John J. (ExxonMobil Upstream Research Co.) | Sahoo, Hemant (Exxon Mobil Corporation) | Teletzke, Gary F (ExxonMobil Upstream Research Co.) | Banfield, Jessica (ExxonMobil Canada) | Long, Jamie M. (ExxonMobil Canada) | Maccallum, Nicholas (ExxonMobil Canada) | Noseworthy, Ryan J. (ExxonMobil Canada) | James, Lesley A (Memorial University of Newfoundland)
The Hibernia oil field is located in the North Atlantic Ocean over 300 km from St. John's, Newfoundland. The field consists of numerous fault blocks undergoing conventional gas or water injection. The gas injection process is proving to be very efficient providing high recoveries in individual blocks. Expansion of gas injection through conventional development or EOR may potentially provide significant benefits if optimized correctly under a limited gas supply. The need to understand the relative benefits of gas injection into one block versus another has increased and necessitated a full gas utilization study. One EOR option being considered is water-alternating-gas (WAG) injection in some blocks.
The objective of the study is to establish a field-wide improved recovery plan based on integrated laboratory, reservoir simulation, pilot, gas supply, and infrastructure studies. This paper will describe the integrated study plan and current progress.
The Gas Utilization Optimization Project entails three broad phases: 1) Study Phase; 2) WAG Pilot Execution; and 3) Field-Wide EOR Development. The primary focus at this point is the Study Phase, which will include laboratory studies, reservoir simulation studies, pilot engineering studies, and gas supply and infrastructure assessment.
The laboratory studies are being performed to develop a better understanding of PVT, EOR, and SCAL as it applies to the WAG pilot and field-wide development. The reservoir simulation studies provide a basis for the design of the EOR pilot and the field-wide development plan. Pilot engineering must be performed to ensure the pilot will provide the information necessary to make business decisions on future development. Assessing gas supply and infrastructure is essential to understanding gas availability, value, and opportunities for enhancement. This phase is particularly important for remote locations where external gas supplies are limited.
This study provides a template for obtaining and integrating information and data necessary to design, evaluate, and implement a gas injection project for improved oil recovery.
Advancement in drilling and production technologies, such as horizontal drilling with multi-stage fracturing, has enabled commercial production from more challenging reservoirs, namely, tight oil formations. However, high capital costs and relatively low recovery narrow the profit from such reservoirs. CO2 EOR has provided not only an excellent opportunity to unlock more oil production, but also a chance to sequestrate more CO2 to reduce environmental footprint. However, profitability of CO2 EOR processes could rely heavily on market conditions.
While CO2 EOR reserves and CO2 storage can be quantified through compositional simulation, thorough economic analyses need to be conducted to evaluate the viability of a CO2 EOR project. The complexity of this study can be reduced significantly through experimental design. Randomized economic uncertainties, such as commodity prices, royalty scheme and incentives, CO2 sequestration credits, capital and operating cost structure, CO2 price, etc. can also be investigated with Monte Carlo simulation. This coupled approach allows us stochastically to sensitize the probability of each parameter and quantify their financial impacts on CO2 EOR projects. This methodology is extremely valuable in the assessment of risks in business, especially when uncertainties are high or the problem is rather complex, such as CO2 EOR/sequestration in tight oil reservoirs.
The remaining oil in tight oil formation, after primary and water flood, is still significant. Hence, CO2 EOR has attracted attentions from industrial partners and government regulatory bodies. This paper provides a rigorous workflow for the industry on how to appraise such projects, as well as a perspective for the governing bodies of how to transform their policies and incentives when market conditions change.
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.
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.
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.
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.