Ross, T. S. (New Mexico Institute of Mining & Technology) | Rahnema, H. (New Mexico Institute of Mining & Technology) | Nwachukwu, C. (New Mexico Institute of Mining & Technology) | Alebiosu, O. (ConocoPhillips Co) | Shabani, B. (Oklahoma State University)
Steam injection—a thermal-based enhanced oil recovery (EOR) process—is used to improve fluid mobility within a reservoir, and it is well known that it yields positive results in heavy-oil reservoirs. In theory, steam injection has the potential of being applied in light-oil reservoirs to enable vaporization of in-situ reservoir fluids, but field developments and scientific studies of this application are sparse. Conventional displacement methods like water-flooding and gas-flooding have been applied to some extent, however, oil extraction in such reservoirs relies on recovery mechanisms like capillary imbibition or gravity drainage to recover oil from the reservoir matrix. Furthermore, low-permeability reservoir rocks are associated with low gravity drainage and high residual oil saturation.
The objective of this study is to evaluate the potential of steam injection for light (47°API) oil extraction in naturally-fractured reservoirs. It is theorized that this method will serve as an effective tool for recovery of light hydrocarbons through naturally-fractured networks with the benefit of heat conduction through the rock matrix. This research investigates the application of light-oil steamflood (LOSF) in naturally- fractured reservoirs (NFR).
A simulation model comprised of a matrix block surrounded by fracture network was used to study oil recovery potential under steam injection. To simulate gravity drainage, steam was injected through a horizontal well completed in the upper section of the fracture network, while the production well was completed at the bottom of the fracture network. The simulation included two different porous media: (1) natural fractures and (2) matrix blocks. Each of these porous media was assumed to be homogeneous and characterized based on typical reservoir properties for carbonate formations. This study also analyzed the impact of different recovery mechanisms during steam injection for a light-oil sample in NFR, with reservoir sensitivity examined, based on varying amounts of vaporization, injection rate, permeability, matrix height and capillary pressure. Of these, vaporization was found to be the dominant factor in the application of LOSF in NFR, as described in detail within the results.
Li, Feng (Southwest Petroleum University) | Li, Xiaoping (Southwest Petroleum University) | Zou, Xinbo (CNOOC China Ltd.) | Duan, Zheng (CNOOC China Ltd.) | Liao, Tian (BHGE) | Lu, Xiaonan (BHGE) | Ren, Yang (CNOOC China Ltd.)
The operator of an offshore oilfield located in South China Sea, has been researching for efficient methods to tackle the production constraints from the increasing produced water amount and maximize oil recovery. An ESP assisted downhole oil and water separation system, known as SubSep system, was designed and successfully installed in year 2014. During the operations, the system achieved designed separation performance but went offline due to heavy sand problem. This paper concentrates on sharing the experience of complete cycle of system design, deployment, operation and post-job investigations, and discussing the lessons learned and future improvements for downhole oil and water separation technology.
The downhole oil and water separation system features in two independent ESP to operate simultaneously: the lower ESP feeds well fluid into multistage hydrocyclone where oil is separated from water, and enters upper ESP to lift to ground, while water is injected to injection layer. Installed in year 2014, the system is the first successful deployment of downhole oil and water separation technology in South China Sea area. The system has totally operated 480 days, during which various operation methodologies were experimented and outcomes analyzed. In normal operation the separated water collected from sample line in water injection zone showed 99ppm oil, and 75% of water was reduced to ground, which signaled the significant success in water and oil separation. The system went offline when surface water rate increased abnormally and injected water with high oil concentration. Further investigation of pulled system showed clear evidence of abrasions from sand and quarts. Future improvement pathways were identified as applying multiple sand control methods, simplifying completion strings, enhancing chemical injection programs and implementing surface experiments.
This paper shares the experience of a complete cycle of design, deployment, operation, and post-job investigations of a downhole oil and water separation system, and provide reference for future improvements and optimizations
Shchetinina, N. V. (Tyumen Petroleum Research Center) | Malshakov, A. V. (Tyumen Petroleum Research Center) | Basyrov, M. A. (Rosneft Oil Company) | Zyryanova, I. A. (Rosneft Oil Company) | Ganichev, D. I. (Rosneft Oil Company) | Yatsenko, V. M. (Rosneft Oil Company)
The article addresses the evolution history of interpretation of logging data from horizontal wells in Russia and abroad. Key problems of interpreting logging data are analyzed. It also describes the application of new technologies and approaches that have increased the validity of logging interpretation. The authors substantiate the need to integrate the full spectrum of geological and geophysical information. Further ways to develop approaches are proposed.
Buell, R. S. (Chevron Energy Technology Company) | Gurton, R. (Chevron Energy Technology Company) | Sims, J. (Chevron Energy Technology Company) | Wells, M. (Chevron Energy Technology Company) | Adnyana, G. P. (Chevron Energy Technology Company) | Shirdel, M. (Chevron Energy Technology Company) | Muharam, C. (Chevron Energy Technology Company) | Gorham, T. (Chevron Energy Technology Company) | Riege, E. (Chevron North America Exploration and Production) | Dulac, G. B. (Chevron North America Exploration and Production)
A horizontal steam injection pilot project has been underway for the last four years in the Kern River heavy oil field located in the southern San Joaquin Valley of California. This pilot project was designed to address the following four prioritized learning objectives for horizontal steam injection in a mobile heavy oil reservoir, which were: What is the mechanical reliability and operability of horizontal steam injectors? Can acceptable steam conformance control along the horizontal section be achieved? Can steam conformance along the horizontal section be quantified with surveillance? What is the reservoir response and longer-term operability with horizontal steam injection?
What is the mechanical reliability and operability of horizontal steam injectors?
Can acceptable steam conformance control along the horizontal section be achieved?
Can steam conformance along the horizontal section be quantified with surveillance?
What is the reservoir response and longer-term operability with horizontal steam injection?
The 12-acre pilot area on the northwest flank of section 24 of the Kern River field was equipped with two horizontal steam injectors and nine vertical producing wells. The pilot area also had 12 vertical temperature observation wells (TOW) to understand steam conformance around each of the injectors and in the far-field reservoir. The TOWs were logged frequently to establish temperature trends. Based upon temperature trends steam identification and saturation logs were also acquired periodically.
Five injector completions of increasing complexity were installed to understand the injectors' mechanical integrity, recovery of flow control devices, performance of isolation packers and fiber optic surveillance systems. A history-matched reservoir simulation model with coupled wellbore hydraulics was used for forecasting throughout the project life to conduct operational sensitivity analysis and to improve reservoir characterization. Fiber optic flow profiling methods were developed in the injectors that were validated with the observation wells and reservoir models. During each workover torque and drag measurements were acquired which were analyzed with both soft and stiff string analysis to understand wellbore mechanical conditions in the horizontal section. After each workover, all available reservoir and workover surveillance data, TOW logs and production and injection well information were used in a multidisciplinary review to understand progress against the four prioritized learning objectives. The performance of offsetting traditional, vertical steamflood developments were also evaluated.
Steam injection (including cyclic steam and SAGD) has long been recognized as the favored recovery method for heavy oil, with applications in many fields around the world in particular in California and Canada. More recently, polymer flooding has also become a relatively well accepted method to increase production and recovery in heavy oil fields. Numerous successful pilots have been reported these last few years and field expansions are currently ongoing in Canada, Oman, China and Albania for instance but surprisingly enough, there has been to the best of the author's knowledge no such application in the US. Both steam and polymer injection have their advantages and their limitations and simple screening criteria have been developed by several authors, however there has never been a detailed comparison of the two methods and this is what this paper proposes to do. The pros and cons of both steam injection and polymer flood are reviewed in light of fundamentals and field experience: reservoir depth, thickness, oil viscosity, expected recovery, water usage and economics of both processes (in particular capital requirements) are all addressed.
Field-scale simulations of complex processes, often suffer from long simulation times. One of the main reasons is that the Newton-Raphson (NR) process used to solve each simulation time step requires many iterations and small time-step sizes to converge. Since the selection of solution variables impacts the nonlinearity of the equations, it is attractive to have a practical method to rapidly explore the use of alternative primary variables in general-purpose reservoir simulators.
Many reservoir simulators use pressure, saturations, and temperature in each gridblock as primary solution variables, which are referred to as natural variables. There is also a class of reservoir simulators that uses pressure, total component masses (or moles), and internal energy in each gridblock as primary variables. These simulators are referred to as mass-variable based reservoir simulators. For a given choice of primary variables, most simulators have dedicated, highly optimized procedures to compute the required derivatives and chain rules required to build the Jacobian matrix. Hence, it is usually not possible to switch between mass and natural variables. In this work, however, we establish a link at the numerical solution level between naturaland mass-variable formulations and design a novel (nonlinear) block-local method that transforms mass-variable shifts (computed at each NR iteration) into equivalent natural variable shifts.
We demonstrate on a number of simulation models of various complexity that, by use of the proposed approach, a mass-variable based flow simulator can still effectively use natural variables, where the change of variables can be made locally per gridblock. Results indicate that in some models the total number of NR iterations, linear solver (LS) iterations, and backups are reduced when using natural variables, instead of mass variables. However, the improvement is fairly modest and not generally observed. Our findings also signify that, depending on the specific characteristics of the simulation problem at hand, mass-variable based simulators may perform comparably or outperform natural-variable based simulators.
The proposed variable switching method can be used effectively to evaluate the impact of using different primary solution variables on problem nonlinearity and solver efficiency. With this method, the impact of interchanging primary solution variables on problem nonlinearity can be rapidly evaluated.
Offshore China in the Cao Fei Dian 11-2 field (CFD 11-2), Bohai Bay, Joint Venture Partners Kerr-McGee China Petroleum Ltd (KMCPL) and China National Offshore Oil Corp. (CNOOC) were looking for original solutions to manage their water handling constraints. Downhole oil and water separation was investigated, with the goal of injecting most of the produced water downhole to alleviate surface processing requirements. This paper presents the completion design selected,results and equipment performance (to date), lessons learned and future applications.
Downhole separation is not a new idea. The technology has existed for many years, although most previous installations experienced issues which resulted in limited application of the technology. These issues are reviewed in detail because they were the driving force behind developing a new approach to overcome
water handling constraints. To implement the technology at CFD 11-2, a candidate well had to be identified and a new SubSep completion designed. It used two independently controlled ESPs operating simultaneously to provide maximum control and flexibility. Chemical injection was incorporated to enhance separation efficiency using a fast-acting phase separation chemical. Monitoring systems were installed on both ESPs and at the downhole separator to survey all key parameters. A sample line was also included in the completion, and ported to the discharge stream of the hydrocyclone. This enabled real-time monitoring of oil ppm levels in the injected water, and facilitated timely optimization ofESP operating parameters and chemical performance.
The installation reduced the water-to-surface by 8,000 to 9,000 bwpd and achieved an oil carry over of 690 ppm, which was subsequently optimized to less than 300 ppm. The reduced water-volume-to-surface relieved process system pressure and provided an opportunity to increase production from other wells, delivering potential incremental production of up to 500 bopd.
Sarapardeh, A. (Sharif University of Technology) | Kiasari, H. Hashemi (Amir-Kabir University of Technology) | Alizadeh, N. (Schlumberger) | Mighani, S. (University of Oklahoma) | Kamari, A. (Omidiyeh Branch of Islamic Azad University)
Steam injection process has been considered for a long time as an effective method to exploit heavy oil resources. Over the last decades, Steam Assisted Gravity Drainage (SAGD) has been proved as one of the best steam injection methods for recovery of unconventional oil resources. Recently, Fast-SAGD, a modification of the SAGD process, makes use of additional single horizontal wells alongside the SAGD well pair to expand the steam chamber laterally. This method uses fewer wells and reduces the operational cost compared to a SAGD operation requiring paired parallel wells one above the other. The efficiency of this new method in naturally fractured reservoir is not well understood. Furthermore, how operational parameters could affect the efficiency of this method is a topic of debate. In this study, Fast-SAGD is compared through numerical reservoir simulations with standard SAGD in an Iranian naturally fractured heavy oil reservoir and additionally some operational parameters including initiating time of steam injection in offset well, number of cycles assuming the same total period of steam injection, offset injection pressure, elevation of offset well from the bottom of reservoir and vertical distance of production and injection SAGD well pairs have been evaluated in Fast-SAGD process. The operational parameters have been optimized based on Recovery Factor (RF) and economical points. The results of this study demonstrated the exceptional performance of Fast-SAGD process in naturally fractured reservoirs and the RFand thermal efficiency of Fast SAGD are enhanced tremendously comparsed to SAGD. In addition, the results indicated that the most important parameters that should be optimized before Fast-SAGD is initiating time of steam injection in offset wells. This study reveals improved efficiency and lower extracting costs for heavy oil in naturally fractured reservoirs applying Fast-SAGD process. Also it is indicated that optimization of operational parameters significantly improves Fast-SAGD performance in such reservoirs.
Cyclic steam EOR pilot project has been deployed in sandstone reservoir type, heavy oil field of Petroleum Development Oman, South Operation, and recently within August to October 2011 showing an interesting CO2 increase from 1% to the level of 25% mol in gas phase as phenomena. This paper discuss the implementation of Root Cause Analysis, developing steam core flood techniques to understand the increasing mechanism of CO2, and the proactive well surveillance will help to monitor accurately the increasing level and the impact. The impact of high CO2 to well and operation integrity also have been studied. The Low GOR (<25 scf/bbl) found to be a limitation of reservoir, while the heavy oil characteristics 14 API will limit a level increase from the well. The only possible CO2 increased are coming from a thermal evaporation mechanism of formation water and rock mineralogy. The basis simplified chemistry model have been developed as steam energy reaction, one mole of CO2 was produced for each mole of H2O injected at steam temperatures. From the detail mineralogy study found that the sandstone reservoir from the field containing Dolomite and Calcite. The surface CO2 found to be the total amount of evaporation from rock mineralogy, Calcite from formation water and from origin associate reservoir gas. And finally, the CO2 percentage increase in the surface will be less than 3 scf/bbl.
The heat may be supplied externally by injecting a hot fluid such as steam or hot water into the formations, or it may be generated internally by combustion. In combustion, the fuel is supplied by the oil in place and the oxidant is injected into the formations in the form of air or other oxygen-containing fluids. In principle, any hot fluid can be injected into the formations to supply the heat. The fluids used most extensively are steam or hot water because of the general availability and abundance of water. Hot water injection has been found to be less efficient than steam injection and will not be discussed here.