Yu, Tao (PetroChina) | Lei, Zhengdong (PetroChina) | Li, Jiahong (PetroChina) | Hou, Jianfeng (PetroChina) | An, Xiaoping (PetroChina) | Zhou, Xiaoying (PetroChina) | Deng, Xili (PetroChina) | Wang, Jinfang (PetroChina)
Objectives/Scope: Waterflood development in low permeability sandstone reservoir is characterized by poor sweep efficiency and fast water breakthrough. Infill drilling has been developed in China for decades as a method of accelerating production and increasing ultimate recovery for such mature waterflooded field. However, optimizing infill drilling pattern entails additional challenges because of the complicated remaining oil distribution affected by reservoir heterogeneity and multi-scale fractures after long-lasting production.
Methods, Procedures, Process: The proposed workflow is a four-step methodology based on a case study of tight oil sandstone reservoirs (average permeability between 0.3mD to 10mD) in Ordos Basin, which is the second largest oil-bearing basin in China. Firstly, a statistical analysis and dynamic diagnosis using real data were applied in order to evaluate waterflood performance. Secondly, the dynamic characteristics of each category were identified by integrating decline analysis, injection/production profile, tracer monitoring and well testing interpretation etc. Moreover, the densely- spaced inspection well core data indicating remaining oil distribution and flush zone was observed. Thirdly, the dominant factors influencing production were investigated considering geological features, waterflooding injection intensity, in-situ stress field etc. Finally, different infill drilling scenarios were simulated and optimized based on the understandings and the field implementation results were presented.
Results, Observations, Conclusions: Three typical production modes and a diagnosis chart were presented indicating effective drive, watered out and poor drive, respectively. The watered out producers performs as drastic water breakthrough, sudden drop of hall plot, sharp spike of GR curve in injection profile and significant amount of tracer production, whereas, poor drive wells act like depletion mode with continuous production drop and extremely low pressure maintenance. Multi parameter analysis explains fracture propagation and reservoir heterogeneity are the dominant factors in watered out region, while oversized well spacing results in poor drive performance, which is testified by real core samples from newly drilled inspection wells. Numerical simulation results indicates that: an optimized staggered line-drive pattern gave the best result for watered out region and the predicted recovery at 95% water cut improved 6.6% of OOIP. This infill drilling optimization methodology was successfully implemented in WY Reservoir and resulted in 6% decrease in water cut and 13% increase in production rate. The estimated ultimate recovery (EUR) improved about 5% of OOIP.
Novel/Additive Information: This paper provides an optimized infill drilling methodology and a case study for better understanding the production performance and infill drilling workflow in waterflooded tight oil sandstone reservoirs. It offers a guidance for future infill drilling of similar reservoirs.
In Deep Water (DW) turbidite reservoirs in the Gulf of Guinea (GoG), waterflooding is deployed to maintain reservoir pressure and improve hydrocarbon recovery. The overall recovery from a reservoir under waterflooding is the product of displacement efficiency (DE), which is a function of remaining oil saturation (ROS) of the swept region, the vertical efficiency, and the pattern efficiency. Analysis of open hole logs from recent infill wells in the Eko field that penetrated swept intervals provided useful insight into in-situ ROS values. The found ROS of between 0.05 to 0.11 were significantly lower than the 0.2 observed from core. The resulting DE of 87% estimated on the basis of the ROS data across these swept intervals has the potential to significantly improve economic robustness of some DW projects if proven correct.
An efficient way to increase oil production in heavy oil reservoirs is by the In Situ Combustion (ISC) process implementation. Part of the oil in place is oxidized, generating heat that increases mobility by reducing oil viscosity. The increase in oil production is associated with displacement mechanisms such as flue gas flooding, steam drive, viscosity reduction by oil swelling and temperature increase, among others. However, not all reservoirs are suitable for an ISC process. Therefore, prior to the implementation of an ISC project, the reservoir properties and reactive characteristics of oil should be evaluated.
The isoconversional principle is a technique to obtain information about oil oxidation characteristics, using the kinetic of the oil oxidation/combustion reactions. The isoconversional methods obtain the kinetic from different Ramped Temperature Oxidation (RTO) tests, usually three to five; this technique provides direct information of the effective activation energy. In addition, the technique can be used as a screening tool to identify good candidates to an ISC process and allow recognition of the number of dominant reactions to model the process in numerical simulators.
This paper presents the results obtained after applying the isoconversional principle in a Colombian heavy oil. Furthermore, a reaction scheme to model the process in a commercial numerical simulator is proposed. The reaction scheme was validated by matching the experimental results in a numerical thermal simulator.
Zhang, K. (University of Calgary) | Sebakhy, K. (University of Calgary) | Wu, K. (University of Calgary) | Jing, G. (University of Calgary) | Chen, N. (University of Calgary) | Chen, Z. (University of Calgary) | Hong, A. (University of Stavanger) | Torsæter, O. (Norwegian University of Science and Technology (NTNU))
In this paper, production characteristics of tight oil reservoirs are summarized and analyzed, the investigated reservoirs include Cardium sandstone reservoir and Pekisko limestone reservoir. The phenomenon that gas and oil or water and oil are co-produced at an early stage of exploitation has been observed. In addition, water cut of many tight oil producers remains constant or undergoes reduction as production proceeds within first 36 months.
Since an oil rate drops quite a lot in the first year's production of tight oil reservoirs, reservoir simulations are run to investigate an effect of different parameters on tight oil production. Randomized experiments are created with geological and engineering parameters as uncertain factors and an oil rate as the response factor. The method of analysis of variance (ANOVA) is used to analyze the difference between group means and to determine statistical significance.
Reservoir properties such as permeability, pressure, wettability, oil API, and oil saturation and engineering parameters including a fracture stage and well operations have tremendous effects on oil production. Oil recovery factor increment in tight oil reservoirs highly depends on enlarging a contact area, improving oil relative permeability, reducing oil viscosity and altering wettability. Future research and development trends in tight oil exploitation are highlighted.
As primary recovery is quite low in tight oil reservoirs, the multistage fracturing technology is a necessity and it must be conducted based on a deep understanding of petrophysical and geomechanical properties. Water alternating gas (WAG) seems the best fit for tight oil exploitation. The way to improve WAG performance, including CO2 foam stabilized with surfactant or nanoparticles, low salinity water or nanofluids alternating CO2, will earn more and more attention in the future of tight oil development.
One method to access unconventional, heavy-oil resources is to apply in-situ combustion (ISC) to oxidize in place a small fraction of the hydrocarbon thereby providing heat and pressure that enhances recovery. ISC is also attractive because it provides the opportunity to upgrade oil in-situ by increasing the API gravity and decreasing, for instance, sulfur content. Despite a considerable literature on ISC dynamics, the propagation of a combustion front through porous media has never been visualized directly. We use X-ray computed tomography (CT) to monitor ISC movement, displacement-front shape, and thickness in a 1m long combustion tube. Temperature profile history, liquid production, and effluent gas data are also obtained. Tests employ a 8.65 °API (at 21.6 °C) heavy crude oil and representative sand. The general trend of saturation profiles are defined through spatially and temporally varying CT numbers. The role of initial oil and water saturations is examined by packing the combustion tube with either multiple samples with different saturations or filling it with a uniform sample. Our work quantifies that ISC fronts display instabilities on a very fine scale (cm). ISC reactions appear to add to front instability in comparison to inert gas advance. The pressure gradients during ISC appear to influence grain arrangement for loose packing. These grain arrangements cause combustion front fingering suggesting that the geomechanical state is relevant to combustion. This new data advances the knowledge base significantly by providing a data set for benchmarking of ISC simulations.
The Buffalo Field enhanced oil recovery project is the oldest, still active, air injection project in the United States. The combination of depth (8,500 ft), high pressure (4,200 psi), light oil (32 °API), high reservoir temperature (215 °F) and low permeability (1 to 20 md) carbonate formation makes this a unique air injection project, covering a large area (33,160 acres). The project's longevity attests to both its technical & economic success.
Laboratory studies (combustion tube, miscibility pressure and swelling tests for various CO2-N2 mixtures) and feasibility studies including air injectivity testing were completed in mid-1977. The result of the pilot test was promising and the 2,240-acre Buffalo Red River Unit (BRRU) was formed in November 1978. As production response continued to be encouraging, the BRRU was expanded to 7,680 acres in May 1981. Two other EOR units, South Buffalo Red River Unit (20,800 acres) and West Buffalo Red River Unit (4,680 acres) were formed adjacent to BRRU, in 1983 and 1987 respectively.
The three units currently have a total of 59 producers and 20 injectors. Oil production in all units has shown significant increase over its historical decline under continued primary. Peak production reached 3,030 BOPD in June 1991. Current production is 1,500 BOPD and injection is 30,500 Mcfd. Cumulative air injection through December 2009 is 262 Bcf and the incremental production due to air injection is about 18.1 Million barrels resulting in cumulative air utility of 14.5 Mcf/incremental barrel.
This paper focuses on the technical aspects of the Buffalo EOR project, reviewing laboratory studies, production performance (1978 to 2009) and the impact of short radius horizontal drilling. It also includes estimates of the EOR barrels produced, how air utility and air retention have changed over time, and estimates of the burned volume in each of the units.
Hou, Shengming (China U. of Petroleum East) | Ren, Shaoran (China U. of Petroleum Beijing) | Wang, Wei (China U. of Petroleum) | Niu, baolun (SINOPEC) | Yu, Hongmin (Xinjiang Oilfield Company) | Qian, Genbao (Xinjiang Petr. Admin. Bureau) | Gu, Hongjun (Xinjiang Oilfield Company) | Liu, Baozhen
XinJiang oilfield is located in the Northwest of China, in which large oil reserves have been discovered in reservoirs with very low permeability (<14×10-3µm2). These reservoirs are featured with light oil in moderate depth, high reservoir pressure, but relatively low reservoir temperature (65~78oC) and low oil viscosity (<10mPa•s). Primary production and limited water flooding experience have shown that the recovery factor in these reservoirs is very low due to lack of reservoir energy and poor water injectivity. Gas injection has been optioned as an alternative secondary or tertiary technique to maintain reservoir pressure and/or increase sweeping and displacement efficiency. In this study, the feasibility of air injection via a low temperature oxidation (LTO) process has been studied. Laboratory experiments were focused on LTO characteristics of oil samples at low temperature range and core flooding using air at various reservoir conditions. Reservoir simulation studies were conducted in order to predict the reservoir performance under the air injection scheme and to optimize the operational parameters. The oxygen consumption rates at reservoir temperature and IOR potentials at different reservoir conditions were assessed for a number of selected reservoirs in the region. A pilot project has been designed based on experimental data, reservoir simulation results and field experience of air injection gained in other regions of China. Issues related to safety and corrosion control during air injection and the project economics were also addressed in the paper.
High Pressure Air Injection (HPAI) is a potentially attractive enhanced recovery method for deep, high-pressure light oil reservoirs. The clear advantage of air over other injectants, like hydrocarbon gas, carbon dioxide, nitrogen, or flue gas is its availability at any location. Although, the process has successfully been applied in the Williston Basin for more than two decades, the potential risks associated with the presence of oxygen in air are a significant hurdle for implementation in other locations.
Thermal simulations that include combustion are required to quantify the incremental oil, the oxygen consumption and resulting oxygen distribution from the application of HPAI in a given field. Once such a simulation model is available, it can be used to optimize the injection strategy: strategies that have a good incremental recovery while reducing the amount of gas injected are key to a successful project. The injection rate is bounded by a technical lower limit and an economic upper limit: there is a minimum rate required to maintain the combustion and high rates require larger compressors that are more expensive.
This paper focuses on the optimization of the injection strategy for HPAI in a 3D model with realistic geological features. Numerical simulations with a thermal model that includes combustion were conducted for continuous versus alternating air injection. A critical assumption for alternating air injection in that the remaining oil spontaneously re-ignites.
This study shows that water alternating air injection has a great potential to improve HPAI projects: project life can be extended and incremental recovery is improved when compared with continuous air injection. In addition, the variation in distribution of oxygen between different cycles is presented. This also illustrates that the numerical model can be used as an oxygen management tool. The effects of alternating air injection are comparable to the effects of alternating gas injection: the saturation in the swept areas changes due to the alternating (re-) invasion of gas, oil and water.
This paper illustrates that modeling oxygen consumption is essential for the evaluation of potential risks and optimization of the HPAI process.
High-pressure air injection (HPAI) is an enhanced oil recovery (EOR) process in which compressed air is injected into a deep, light-oil reservoir, with the expectation that the oxygen in the injected air will react with a fraction of the reservoir oil at an elevated temperature to produce carbon dioxide.
Over the years, HPAI has been considered a simple flue-gas flood, giving little credit to the thermal drive as a production mechanism. The truth is that, although early production during a HPAI process is mainly due to re-pressurization and gasflood effects, once a pore volume of air has been injected the combustion front becomes the main driving mechanism.
This paper presents laboratory and field evidence of the presence of a thermal front during HPAI operations, and of its beneficial impact on oil production. Production and injection data from the Buffalo Field, which comprises the oldest HPAI projects currently in operation, were gathered and analyzed for this purpose. These HPAI projects definitely do not behave as simple immiscible gasfloods.
This study shows that a HPAI project has the potential to yield higher recoveries than a simple immiscible gasflood. Furthermore, it gives recommendations about how to operate the process to take advantage of its full capabilities.