Wang, Yan (1st Oil Prod. Co. Daqing) | Wang, Demin (Daqing Oil Company) | Wan, Jun (1st Oil Prod. Co. Daqing) | Luo, Jiangtao (1st Oil Prod. Co. Daqing) | Yu, Runtao (1st Oil Prod. Co. Daqing) | Dong, Zengyou (1st Oil Prod. Co. Daqing)
After large scale polymer flooding in the field, due to the high elasticity and viscosity of the fluid, the efficiency and effective life-span of the producers (and injectors) decreased significantly, new technologies were developed.
After polymer is produced, severe eccentric wear on sucker rods occur. To solve the problem, on the basis of theoretical and lab studies, techniques to reduce the normal force on sucker rods and control its eccentric wear were developed. Field practice shows that this technology has increased the average life span of pumping wells by 3 times.
The effective time of conventional fracturing and acid stimulation of polymer injectors is less than 3 months. Therefore, technologies of resin-coated sand tail-in fracturing and surfactant stimulation were developed. These 2 new technologies have increased the effective time of injector stimulation by about 5 times.
The above techniques are all used in a mass scale in the field with significant results; they can and are also used on conventional wells.
The year 2006 marks the first time the gas injection EOR production has surpassed that of steam injection processes in the US, signifying the growth of gas injection as a mature technology. In order to control the rising tendency of injected gas in horizontal floods, the water-alternating-gas (WAG) process has generally been the mode of operation in many fields. In spite of its wide application, the WAG process has not lived up to its expectations with reported recoveries in the range of 5-10% OOIP. In order to improve recoveries, we have been attempting to develop the gas-assisted gravity drainage process at LSU. This paper summarizes the effort of conducting scaled physical model experiments in a visual glassbead-packed model aimed at discerning the influence of some scaled dimensionless parameters, such as the capillary number, Bond number and gravity number, on the GAGD process performance.
A 2-D physical model, of 16?? X 24?? X 1?? dimensions, packed with uniform glass beads, was used to conduct visual experiments. These experiments were so designed as to mimic the dimensionless parameters observed in some field projects. The secondary mode GAGD floods yielded recoveries up to 80% OOIP. Additionally, the recoveries displayed a semi-logarithmic relationship with gravity number (ratio of gravity to viscous forces). Interestingly, this relationship was observed to hold good for the high-pressure GAGD corefloods and even the field production data from gravity-stable gas injection projects conducted in pinnacle reefs. A multi-variable regression analysis of the laboratory as well as field data indicated that the Bond number, being the ratio of gravity to capillary forces, had a greater influence on GAGD performance than other parameters. In addition to the observed high recoveries, our attempts to relate the model run times to field project durations, through dimensionless time considerations, have indicated reasonably good rates of production when GAGD process is implemented in field projects.
EOR surveys by the Oil and Gas Journal for the last two decades clearly show the increased popularity and production share of gas injection processes in the U.S. Among the gas injection EOR processes, CO2 as well as hydrocarbon processes, demonstrate higher potential as an effective tool to recover the ‘left-behind' oil. The recent record crude oil/natural gas prices, as well as increased greenhouse gas emission concerns, tip the scales in favor of CO2 as the most favorable enhanced oil recovery tool.
The important functions that any EOR process needs to perform to be successful are: (i) increase the microscopic displacement efficiency by increasing the capillary number, and (ii) attain better volumetric sweep efficiency by improving the mobility ratio (M) (Green and Willhite, 1998). The microscopic efficiency, defined as extent of mobilizing the trapped reservoir residual oil, is a function of the capillary number (Nc), where Nc is the ratio of viscous to capillary forces. On the other hand, the volumetric sweep, defined as the percent of reservoir rock contacted by the injected fluid, is governed by the mobility ratio and reservoir heterogeneity.
Yu, Liping (U. of Stavanger) | Evje, Steinar (International Research Institute of Stavanger) | Kleppe, Hans (University of Stavanger) | Karstad, Terje (University of Stavanger) | Fjelde, Ingebret (IRIS) | Skjaeveland, Svein M. (U. of Stavanger)
Improved oil recovery from fractured oil-wet carbonate reservoirs is a great challenge. The water-flooding efficiency will be low because of higher permeability in fractures than in matrix, and negative capillary pressure retains oil inside the matrix blocks. Studies of oil-wet chalk have shown that sulphate ions in the seawater may alter the wettability towards increased water-wetness.
One-dimensional spontaneous imbibition tests of seawater into preferentially oil-wet chalk cores are performed. To get a better understanding, a numerical model has been developed which includes effects of wettability alteration.
The experiments are carried out on cylindrical, sealed core plugs with only top open or with both ends open. Only countercurrent imbibition takes place for cores with top end open. For cores with both ends open, both countercurrent and cocurrent imbibition take place, and oil recovery rate is obviously accelerated. Taking formation water as the base case, higher oil recovery is observed with seawater imbibition. To simulate the wettability alteration process caused by seawater, a model is developed which includes molecular diffusion, adsorption of wettability alteration (WA) agent, gravity and capillary pressure. The WA agent diffuses into the formation water initially present in the core, adsorb onto the rock surface and induce wettability alteration. Consequently, the capillary pressure curve is shifted to higher values. In particular, the capillary pressure at the initial water saturation changes from negative to positive values and seawater is imbibed into the core. The shapes of relative permeability curves also depend on the wettability. The simulation results can fairly well match the experimental data.
With the experimental and modeling work we explore the interplay between capillarity and gravity, and especially the importance to consider wettability alteration process is again confirmed.
Crescente, Christian Miguel (StatoilHydro) | Rekdal, Andreas (StatoilHydro) | Abraiz, Akram (Norwegian U. of Science & Tech) | Torsaeter, Ole (NTNU) | Hultmann, Lisbeth (NTNU) | Stroem, Arne (Norwegian U. of Science & Tech) | Rasmussen, Kjetill (Statoil ASA) | Kowalewski, Espen
Micromodel experiments have been executed in order to have better insight into the displacement mechanisms allowing Rhodococcus sp. 094 to increase oil recovery. Changes caused by the bacteria in the fluid interfaces and pore walls have been recorded and are presented. The previously suspected mechanisms are further confirmed by the results, but a much better insight into the details of how the process occurs has been obtained and a theory for this process is developed.
This paper describes a low-cost completion technique that uses conventional tubing and replaces the expensive thermal packer with a new low-cost design. The new design allows free tubing expansion and protects casing through continuous gas circulation in the annulus. It also makes possible simultaneous injection of combustion gases from steam generators, when conventional systems are used, or small amounts of nitrogen, when the generators are not available.
Sim, Steve Soo-Khoon (Alberta Research Council) | Brunelle, Patrick (Quadrise Canada Fuel Systems Inc.) | Turta, Alexandru T. (Alberta Research Council) | Singhal, Ashok Kumar (Alberta Research Council)
Enhanced gas recovery by gas-gas displacement can be achieved economically in several situations. For mature volumetric gas reservoirs suffering from low productivity due to low reservoir pressure, injection of waste gas can increase the ultimate gas recovery by maintaining gas production rates and preventing premature well abandonment. For water-driven gas reservoirs, pressure maintenance by gas injection will serve to (1) retard the influx of aquifer and (2) partially mitigate water coning caused by excessive pressure drawdown.
This paper presents the results of laboratory core displacement tests conducted to investigate the feasibility of enhanced natural gas production by using exhaust gas from combustion of bitumen in an oxygen rich atmosphere. A synthetic gas mixture containing carbon dioxide, nitrogen and sulfur dioxide was used to represent the exhaust gas of interest. Displacement tests were conducted in Berea core and in porous media prepared with silica sand as well as crushed carbonate rocks at pressures ranging from 0.69 to 6.2 MPa. The objectives of the experiments were to determine the effects of (1) pressure, (2) displacing gas composition (3) formation water and (4) rock mineralogy on recovery efficiency of uncontaminated methane from the porous media.
Several interesting phenomena were observed during the course of this investigation. Separation of injection gas components was observed in the effluent gas during displacement. Breakthrough of carbon dioxide and sulfur dioxide were delayed relative to nitrogen. This can be attributed to the higher solubility of CO2 and SO2 in water relative to nitrogen. These results are beneficial to natural gas production as they reduce the operating costs associated with corrosion during production of CO2 and SO2. The amount of green house gases and acid gases being sequestered in the reservoir will also increase due to these effects.
Improved oil and gas recovery by means of carbon dioxide injection has attracted increasingly more attention in recent years due to (1) rising value of petroleum and (2) recognition that geological storage of CO2 in depleted oil and gas reservoirs could be a potential solution to global warming by controlling the amount of green house gases in the atmosphere. Enhanced oil recovery (EOR) by miscible CO2 flood has been practiced worldwide since the 1960's and is considered to be a mature technology. However, the idea of injecting wasted gas for enhanced gas recovery (EGR) is rarely practiced. So far, the only published field application of CO2 injection for EGR was conducted during 1986-1994 in the Budafa Szinfelleti Field of Hungry (Papay, 1999). Here, the injected gas consisted of 80% and 20% methane from an adjacent natural CO2 pool.
Green, Derrick (Green Imaging Technologies) | Gardner, John S. (Core Laboratories Inc.) | Balcom, Bruce John (U. of New Brunswick) | McAloon, Michael (U. of New Brunswick) | Cano-Barrita, Jesus (CIIDIR IPN U. Oaxaca)
The current study is a comparison trial of a new Magnetic Resonance Imaging (MRI) method for acquiring capillary pressure versus traditional techniques. This study is meant to evaluate the methodology and workflow by performing measurements at the University of New Brunswick, Canada and on-site with CoreLab in Houston, TX, USA. This study focuses on gas-brine primary drainage capillary pressure systems.
Traditional centrifuge capillary pressure measurements require the fluid(s) to reach equilibrium at many different speeds. This is very time consuming as each equilibrium step can take a couple of days. In addition, the inlet saturation must be computed using an approximate solution that is known to cause errors. Porous plate capillary pressure measurements are considered the most accurate but acquiring the complete curve can take months.
The new method (GIT-CAP) centrifuges the core plugs then directly measures the water saturation distribution inside the core plug using MRI. The measured water saturation together with the known centrifugal force directly leads to a capillary pressure curve.
Conventional medical based MRI methods have difficulty in relating the detected signal intensity to water or oil saturation. This is because the MRI image intensity depends on the environment of hydrogen atoms which changes based on saturation level. In this work, we use a new MRI method, one dimensional centric scan Single-point Ramped Imaging with T1 Enhancement (SPRITE), in which the detected signal is directly proportional to the amount of water or oil present.
The new technique measures the capillary pressure curve more quickly and accurately. It is also three to five times faster since only two to three centrifuge speeds are required (versus seven to ten). In some rock types, this reduces the measurement duration from many weeks to days. The new technique is also potentially more accurate as it directly measures the water saturation in the rock instead of relying on a calculation using a measurement of the expelled water. The current study focuses on gas-water systems comparing traditional capillary pressure measurements with the new MRI-based method.
Using analytical results and thermal reservoir simulations, we study the heating of - and oil recovery from - a vertical stack of matrix blocks. The stack is surrounded by fractures, where steam is injected at the top and oil recovered from the base of the fracture system.
We compare fine-grid single-porosity simulations with coarse-grid dual-permeability simulations (where the matrix-fracture interaction is modelled via shape-factors). We independently validate the simulation results with new analytical results for the recoveries due to thermal expansion and temperature-induced viscosity reduction.
Our dual-permeability results show that the early-time heating of the matrix cannot be captured using a constant shape-factor. We analytically derive the time-dependent (transient) shape-factor that captures the heating of the blocks for all time-scales.
When this transient shape-factor is used in combination with an analytically derived viscosity correction (to capture the effect of the temperature profile inside a matrix-block), the coarse-grid dual-permeability simulations accurately reproduce the fine-grid single-porosity simulations and analytical results.
Yu, Hongmin (China University of Petroleum) | Yang, Baoquan (China University of Petroleum) | Xu, Guorui (China University of Petroleum) | Wang, Jiexiang (China University of Petroleum) | Ren, Shaoran (China University of Petroleum) | Lin, Weimin (ZhongYuan Oilfield Co. Ltd., Sinopec, China) | Xiao, Liang (ZhongYuan Oilfield Co. Ltd., Sinopec, China) | Gao, Haitao (ZhongYuan Oilfield Co. Ltd., Sinopec, China)
The Hu-12 Block, located in ZhongYuan Oilfield, Henan Province China, contains many small but highly heterogeneous oil reservoirs, with low permeability oil bearing formations and high permeability mixed (oil/water) layers. The reservoir temperature is 90 oC, and the original reservoir pressure of nearly 25 MPa, and with high salinity of formation water (around 200,000 mg/l). After 20 years of water injection, the recovery factor achieved was only 20-25%, and average water cut has reached to over 95%. N2 gas injection has been tried with less success due to early gas breakthrough from high permeability zones. Since 2006, high pressure air foam and air injection (Air Foam Alternative Air Injection, AFAAI) has been proposed and implemented in one of the reservoirs, in order to block high permeability water zones and increase the sweeping efficiency of air and water injection. A series of laboratory experiments have been conducted to study the oxidation kinetics of air/air foam with oil and the blocking and displacement efficiency of air foams in different oil sands. Reservoir simulation has also been carried out for predicting the reservoir response to air foam injection and optimizing the injection process. Air foam and air injection was started in the field since May 2007 in a well group with 1 injector and 4 producers, using a small high pressure air compressor (40 MPa, 7 m3/min air rate). Up to now, 460,000 Nm3 air and 2920 m3 foam surfactant solutionhave been injected into the reservoir. The field results show that no oxygen/N2 breakthrough was observedand a significant increase in oil production with water cut reduced by 4%. The detailed laboratory study and field experience are presented in this paper.
A large body of literature has reflected an extensive experimental study of natural imbibition driven by local capillary pressures at high interfacial tension. However, water imbibition induced by emulsification at low interfacial tension is not well understood. Recently, anionic surfactants have been shown to induce imbibition in mixed wet and oil wet carbonates. Sodium carbonate has been used to reduce the surfactant adsorption. However, calcium and other divalent cations can cause precipitation of the alkali unless soft water is used. This is a significant limitation of sodium carbonate. The present research both advances our understanding of the use of chemicals to enhance oil recovery from fractured carbonate reservoirs and indicates how the process can be optimized using novel chemicals. This research applies to the improvement of oil recovery from mixed wet and oil wet fractured carbonate reservoirs.
We show how to select and evaluate new chemicals as natural imbibition enhancers in carbonate rocks. A novel experimental method has also been developed to quantify the significance of capillary and emulsification driven imbibition due to the presence of the chemical imbibition enhancers. An in situ imbibition profile was visualized using a CT X-ray scanning technique. The results show that formation of microemulsion strongly promotes water imbibition. The rate was highest for Winsor Type II microemulsion and lowest for Winsor Type I microemulsion. The alkalis exhibited a striking imbibition enhancement driven mainly by alteration of capillary pressure. The performance of the imbibition enhancers was found to be consistent for different core plug sizes and boundary conditions. A novel alkali has been tested that shows a high tolerance for hardness and thus may be a good alternative to sodium carbonate under some conditions.
The application of low-cost chemicals to enhanced oil recovery from fractured carbonates is an extremely significant development due to the vast volumes of oil in such reservoirs and the lack of practical alternative methods of recovering such oil.