Zhu, Youyi (Research Inst. Petr. Expl/Dev) | Jian, Guoqing (Research Institute of Petroleum Exploration and Development, CNPC) | Liu, Weidong (Research Institute of Petroleum Exploration and Development, CNPC) | Cheng, Lijing (Oil Production Engineering Research Institute of Dagang Oilfield) | Hou, Qingfeng (Research Institute of Petroleum Exploration and Development, CNPC) | Li, Jianguo (Research Institute of Petroleum Exploration and Development, CNPC)
Surfactant-Polymer (SP) flooding has attracted lots of attention among chemical combination flooding researchers in recent years. Pilot tests of SP flooding in China were introduced and key factors influencing the performance of pilot tests were analyzed in this paper. Main technological problems occurred in pilot tests were indicated. Suggestions concerning technology improvement and development were given.
About ten SP flooding pilot tests were carried out in China since 2003. These target reservoirs were characterized with high permeability and low permeability sandstone, conglomerate, and high temperature and high salinity ones respectively. At present, the performance of SP flooding pilot tests in Gudong Block 6 and Gudong Block 7 of Shengli oilfield have shown good enhanced oil recovery (EOR) effect. It confirmed SP flooding could improve both of oil displacing efficiency and sweep efficiency and EOR ability for SP flooding is better than that of polymer flooding. EOR effect of SP flooding can be reflected from the following two aspects. Firstly, with SP slug injecting, the pressure of injection well increased and fluid entry profile was adjusted. The performance of profile control was favorable. Secondly, ultralow interfacial tension could be achieved and residual oil was displaced significantly. SP flooding showed stronger ability in decreasing water cut and increasing oil production than polymer flooding. The production history data showed that main factors influencing EOR were the corresponding relationship between injection wells and production wells, the chemical formula properties and the injection amount of SP system. The favorable oil production was obtained when the corresponding relationship between injection wells and production wells was good. The quality stability of SP formula could influence the flooding EOR performance greatly. Small injection slug size of chemical system would lead low EOR level.
The key technologies which should be improved and optimized for SP flooding are displacing agent quality, formula system stability, slug design, well pattern and so on.
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.
Shiau, Bor Jier Ben (University of Oklahoma) | Hsu, Tzu-Ping (University of Oklahoma) | Lohateeraparp, Prapas (University of Oklahoma) | Rojas, Mario R. (University of Oklahoma) | Budhathoki, Mahesh (University of Oklahoma) | Raj, Ajay (University of Oklahoma) | Wan, Wei (University of Oklahoma) | Bang, Sangho (University of Oklahoma) | Harwell, Jeffrey H. (University of Oklahoma)
Reservoirs containing very high total dissolved solids and high hardness make the design of a surfactant polymer (SP) flood extremely difficult because surfactant tends to precipitate and separate under these conditions. Beside divalent ions, Ca2+, Mg2+, presence of iron in the brine can be a challenging issue. Different surfactant formulations are evaluated and incorporate cosurfactants and co-solvents which minimize viscous macroemulsions, promote rapid coalescence under Winsor Type III conditions, and stabilize the chemical solution by reducing precipitation and phase separation. The optimal surfactant formulations were further evaluated in one-dimensional sand packs and coreflood tests using Berea sandstone, reservoir oils, and brines at reservoir temperatures. Using similar injection protocols, 3 pore volumes of surfactant-only system, experimental results show the oil recovery ranging from 45 % to 70% of the residual oil (Sor) after water flooding. The level of surfactant loading is less than 0.5 wt%. A single-well test was conducted to confirm laboratory results in situ in the presence of high-salinity formation water containing 102,300 mg/L total dissolved solids (TDS). The aim of ongoing test is to confirm the effectiveness of the high-salinity surfactant-only formulation (0.46 wt% of surfactant). In this effort, we plan to conduct multiple single-well tests at different wells to minimize the design risks involved for the surfactant pilot test. A pilot test at a sandstone reservoir is scheduled to be performed in July of 2013 to further evaluate the effectiveness of surfactant formulation and address technical issues related to scale-up.
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.
Immiscible WAG (IWAG) processes, although proven quite useful in maintaining pressure in low permeability reservoirs, has the inherent drawback of leaving high residual oil saturation (Sor) behind the flood front. Often, dependent on the reservoir characteristics, the oil volume which is left behind by a secondary IWAG process can be of significant value and requires investigating tertiary EOR processes that could economically produce it. This case study discusses the approach taken to mature an EOR opportunity in a giant onshore carbonate reservoir currently being developed with IWAG injection.
A plan was put in place to assess the suitability of prospective EOR processes in the subject reservoir. This commenced with a detailed PVT lab study which involved specially designed EOR tests such as swelling, slimtube, forward contact, backward contact, equiphase and asphaltene deposition. The experimental data was used to develop an equation of state model (EOS) that is able to describe the reservoir fluid behavior. Next, analytical methods were used to screen out the EOR processes found most promising. The EOR processes were screened based on the performance indicators estimated using classical reservoir engineering techniques, empirical methods, experience and judgment. The favourable results for the CO2 injection, both from the PVT experiments and the analytical screening led to the design of 1D coreflood experiments on composite cores at full reservoir conditions.
Comparison of the different displacement tests showed CO2-WAG to be highly efficient recovery mechanism with 93% of the HCPV recovery potential. The PVT experiments and the coreflood injection tests, within their experimental limitations provided recovery profiles and CO2 injection characteristics to validate model predictions on a microscopic scale, and thus enhanced confidence in full field development studies based on the underlying reservoir simulation models. The proposed CO2-EOR strategy will help reduce the Sor significantly and hence improve Ultimate Recovery (UR). A field pilot is being considered to evaluate the CO2 injection recovery process optimally.
Liu, Xincang (No.4 Oil Production Company of Daqing Oilfield) | Zhang, Dong (No.4 Oil Production Company of Daqing Oilfield) | Ding, Jian (No.4 Oil Production Company of Daqing Oilfield) | Ran, Fajiang (No.4 Oil Production Company of Daqing Oilfield) | Zhao, Mingchuan (No.4 Oil Production Company of Daqing Oilfield) | Li, Shiyong (No.4 Oil Production Company of Daqing Oilfield)
It's very important to evaluate layered producing performances at different stages in the course of oilfield development, but due to limitations of monitoring well conditions and logging expenses, it is difficult to comprehensively and systematicly monitor all the producers, and this will bring troubles to adjustments and evaluations during oil field development. To solve this problem, the Chromatographic Fingerprint technique is introduced to monitor layered producing performances in test area F which has four target zones in Daqing Oilfied. After response of alkaline-surfactant-polymer (ASP) flooding, screw pumps are adopted to some producers to minimize scaling in F area where producing profile surveys for annulus wells aren't adaptable to mornitor the layed producing status. Pre-test in lab shows that the Chromatographic Fingerprint technique is feasible for the four individual test zones for there are distinct chromatographic fingerprint differences, and ASP injected solution has less influences on fingerprints. A fuzzy interpretation template has been successfully set up for commingled 4-6 layers production numerical simulation by using EPB neural network model, and relative errors can be controlled below 10%. The technique has been applied to the producers for 180 times. In-situ test results are stable and correspond to the static information of lays. It indicates that the Chromatographic Fingerprint technique is suitable for monitoring individual zone producing performances of ASP flooding. The results from the fuzzy interpretation template have provided powerful data to re-recognize the connectivity of heterogeneous reservoir between injectors and producers. It can be applied to producers whose producing intervals belong to the fuzzy interpretation template. The oil production proportion of per lay's can be easily achieved after the sample from the well fluid is analysed with chromatography and calculated with the fuzzy interpretation template. The technique has proved to be economical and it is not astricted by well conditions, so it can play an important role to guide development programs' adjustments and evaluations in oilfields.
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.
EOR technology has been applied on many projects globally with variable success. It shows great potential for offshore heavy oil with oil recovery low in life span of platform (general less than 30% by water flooding). About 60-70% oil is remained in the formation after water flooding, and for offshore heavy oil reservoir, more oil (about 80%) is remained by the end of the platform life.  It becomes more important to achive high recovery before abandoning the platform and the oilfields with lots of oil left in reservoir. With recovery increasment of 5-10% by EOR methods, the reserve will increase greatly, which means an order of magnitude of hundreds of million-tons oilfield is discovered without increase any exploration investment.
Surfactant-polymer (SP) flooding was a potential enhanced oil recovery (EOR) technology that was more powerful than the polymer flooding. And it was test or applied successfully in some high or extra-high WCT onshore oilfields of Shengli oilfields (SINOPEC), Daqing oilfields (CNPC) in china. The paper presents a filed EOR test case of offshore heavy oilfield oilfield by SP.
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.
Zhu, Youyi (Research Inst. Petr. Expl/Dev) | Hou, Qingfeng (Research Institute of Petroleum Exploration & Development, CNPC) | Weng, Rui (Research Inst. Petr. Expl/Dev) | Jian, Guoqing (Research Institute of Petroleum Exploration & Development, CNPC) | Luo, Yousong (Research Institute of Petroleum Exploration & Development, CNPC) | Li, Jianguo (Research Institute of Petroleum Exploration & Development, CNPC)
For mature oil fields, foam flooding is an attractive chemical EOR technique and many pilot tests have been carried out in China. The performance of foam flooding pilot tests and its affect factors on oil recovery was discussed in this paper. The development trend and key technologies of foam flooding technique are pointed out.
Eighteen foam flooding pilot tests have been carried out in China from 1994 to 2010. Good performance have achieved in sixteen pilot tests. Through effects analysis of the pilot tests, three main aspects are concluded for affecting the performance of foam flooding tests. First, the characteristics of target reservoirs influence effects of foam flooding tests. The performance of foam flooding in higher oil viscous reservoirs is better than that in light oil reservoirs. The reservoir temperature and formation water salinity also influences the effects of foam flooding. Secondly, the chemical formula of foam solution and the size of slug influence the performance of foam flooding. The stability of foam formula influences the effects of foam flooding greatly. With the same amount of surfactant solution, the effect of high concentration small-sized slug is better than that in low concentration large-sized slug. Last, the injection method and gas liquid ratio can directly influence the foam performance in the reservoir, gas and liquid mixing injecting model is better than surfactant solution-alternation-gas (SAG) injection, and reasonable gas liquid ratio is important for guarantee good effects of foam flood.
At present, the trend of foam flooding in China is from nitrogen foam flooding and natural gas foam flooding to air foam flooding. The key technologies of foam flooding are the development of high stable foam formula with oil tolerance, salt and temperature resistance, good injection method and reasonable injection parameter etc.