Pilot Trial of New ES-HR-PCP Technology for Heavy Oil Reservoir

2016 ◽  
Author(s):  
Prasanna Mali ◽  
Abdulmuhsen Yousef Abdulmuhsen Hashim Al-Ali ◽  
Srinivas Rao Kommaraju ◽  
Ali Mussaed Al-Rushoud ◽  
Jignesh Shah ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Pilot Trial ◽  
Cost Effective ◽  
Operating Conditions ◽  
Oil Reservoirs ◽  
Pilot Studies ◽  
Free Gas ◽  
Strategic Objective ◽  
Artificial Lift ◽  
Heavy Oil Reservoirs

Abstract Kuwait Oil Company (KOC) has a vast pool of heavy oil reservoirs. Cost-effective artificial lift technologies, are required to produce these reservoirs, optimally. With this strategic objective, pilot of newly developed ‘ES-HR-PCP’ (Electrical Submersible Hydraulically Regulated PCP) technology, is carried out in KOC. Scope of this technical paper is to highlight significance of this technology and to share results of our pilot studies, which are carried out to maximize cold heavy oil production. With regard to our methodology, initially, techno-economic evaluation of ‘ES-HR-PCP’ system, is carried out. Selected well for the pilot, is having horizontal completion, with 3-1/2″ tubing and 7″ casing. Perforation is at 1900 feet MD (TVD at 686 feet). Oil API gravity is 17. Target liquid production rate is 200 b/d. After finalization of design, pilot of ‘ES-HR-PCP’ system is commissioned and pump performance is monitored for 6 months. Results are analyzed to determine success of the pilot. This study is based on actual field implementation and does not include lab studies. Technology evaluation has shown that ‘ES-HR-PCP’ system has definite edge over conventional PCP system. Standard PCP can handle only 25% of free gas; while ‘ES-HR-PCP’ can handle 90% of free gas, due to its unique design concept. ‘ES-HR-PCP’ system uses electric cable (and not sucker rods) and down- hole permanent magnet motor (PMM), to transmit power. PMM system can deliver more production, at higher speed; while expending less power. All these factors enable ‘ES-HR-PCP’, to be installed, near to the perforation zone, especially, in horizontal wells, thereby, allowing to attain lowest possible pump intake pressure and maximize production. During the pilot, peak liquid rate of 270 b/d (at 220 rpm), is achieved with installed ‘ES-HR-PCP’ system. Simulation studies also indicated that this technology could handle more than 40% of free gas, for given operating conditions. It is relevant to note that peak liquid rate of 223 b/d (at 375 rpm), is achieved, when this particular well, was installed with standard PCP, earlier. Substantial savings in power consumption is also witnessed by using ‘ES-HR-PCP’ system. Overall, performance of ‘ES-HR-PCP’ system, is observed highly encouraging during the pilot period. It is inferred from our studies that ‘ES-HR-PCP’ technology can offer distinct advantages over standard PCP, to accomplish, enhanced oil gain, operational flexibility and savings in operating expenses. Findings of this study can serve, as a valuable reference, for effective exploitation of heavy oil reservoirs of similar nature.

Pressure Maintenance and Improving Oil Recovery by Means of Immiscible Water-Alternating-CO2 Processes in Thin Heavy-Oil Reservoirs

2013 ◽  
Vol 16 (01) ◽  
pp. 60-71 ◽  
Author(s):  
Sixu Zheng ◽  
Daoyong Yang
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Production ◽  
Horizontal Wells ◽  
Operating Conditions ◽  
Oil Reservoirs ◽  
Oil Saturation ◽  
Water Alternating Gas ◽  
Heavy Oil Reservoirs ◽  
Water Cut

Summary Techniques have been developed to experimentally and numerically evaluate performance of water-alternating-CO2 processes in thin heavy-oil reservoirs for pressure maintenance and improving oil recovery. Experimentally, a 3D physical model consisting of three horizontal wells and five vertical wells is used to evaluate the performance of water-alternating-CO2 processes. Two well configurations have been designed to examine their effects on heavy-oil recovery. The corresponding initial oil saturation, oil-production rate, water cut, oil recovery, and residual-oil-saturation (ROS) distribution are examined under various operating conditions. Subsequently, numerical simulation is performed to match the experimental measurements and optimize the operating parameters (e.g., slug size and water/CO2 ratio). The incremental oil recoveries of 12.4 and 8.9% through three water-alternating-CO2 cycles are experimentally achieved for the aforementioned two well configurations, respectively. The excellent agreement between the measured and simulated cumulative oil production indicates that the displacement mechanisms governing water-alternating-CO2 processes have been numerically simulated and matched. It has been shown that water-alternating-CO2 processes implemented with horizontal wells can be optimized to significantly improve performance of pressure maintenance and oil recovery in thin heavy-oil reservoirs. Although well configuration imposes a dominant impact on oil recovery, the water-alternating-gas (WAG) ratios of 0.75 and 1.00 are found to be the optimum values for Scenarios 1 and 2, respectively.

scholarly journals Downhole electric heating of heavy-oil wells

2020 ◽  
Vol 10 (2) ◽  
pp. 61-72
Author(s):  
John Karanikas ◽  
Guillermo Pastor ◽  
Scott Penny
Keyword(s):  
Heavy Oil ◽  
Horizontal Wells ◽  
Electric Heating ◽  
Optimization Method ◽  
Economic Benefits ◽  
Production Optimization ◽  
Operating Conditions ◽  
Oil Reservoirs ◽  
Oil Well ◽  
Heavy Oil Reservoirs

Downhole electric heating has historically been unreliable or limited to short, often vertical, well sections. Technology improvements over the past several years now allow for reliable, long length, relatively high-powered, downhole electric heating suitable for extended-reach horizontal wells. The application of this downhole electric heating technology in a horizontal cold-producing heavy oil well in Alberta, Canada is presented in this paper. The field case demonstrates the benefits and efficacy of applying downhole electric heating, especially if it is applied early in the production life of the well. Early production data showed 4X-6X higher oil rates from the heated well than from a cold-producing benchmark well in the same reservoir. In fact, after a few weeks of operation, it was no longer possible to operate the benchmark well in pure cold-production mode as it watered out, whereas the heated well has been producing for twenty (20) months without any increase in water rate. The energy ratio, defined as the heating value of the incremental produced oil to the injected heat, is over 20.0, resulting in a carbon-dioxide footprint of less than 40 kgCO2/bbl, which is lower than the greenhouse gas intensity of the average crude oil consumed in the US. A numerical simulation model that includes reactions that account for the foamy nature of the produced oil and the downhole injection of heat, has been developed and calibrated against field data.  The model can be used to prescribe the range of optimal reservoir and fluid properties to select the most promising targets (fields, wells) for downhole electric heating as a production optimization method. The same model can also be used during the execution of the project to explore optimal operating conditions and operating procedures. Downhole electric heating in long horizontal wells is now a commercially available technology that can be reliably applied as a production optimization recovery scheme in heavy oil reservoirs. Understanding the optimum reservoir conditions where the application of downhole electric heating maximizes economic benefits will assist in identifying areas of opportunity to meaningfully increase reserves and production in heavy oil reservoirs around the world.

Novel Techniques for Measuring Heavy-Oil Fluid Properties

SPE Journal ◽  
2007 ◽  
Vol 12 (03) ◽  
pp. 305-315 ◽  
Author(s):  
Nina Naireka Goodarzi ◽  
Jonathan Luke Bryan ◽  
An Thuy Mai ◽  
Apostolos Kantzas
Keyword(s):  
Heavy Oil ◽  
Ct Scanning ◽  
Oil Reservoirs ◽  
Oil Viscosity ◽  
Free Gas ◽  
Foamy Oil ◽  
Heavy Oil Reservoirs ◽  
Fluid Properties ◽  
Oil Density

Summary Investigating the properties of live heavy oil, as pressure declines from the original reservoir pressure to ambient pressure, can aid in interpreting and simulating the response of heavy-oil reservoirs undergoing primary production. Foamy oil has a distinctly different and more complex behavior compared to conventional oil as the reservoir pressure depletes and the gas leaves solution from the oil. Solution gas separates very slowly from the oil; thus, conventional pressure/volume/temperature (PVT) measurements are not trivial to perform. In this paper, we present novel experiments that utilize X-ray computerized assisted technology (CT) scanning and low field nuclear magnetic resonance (NMR) techniques. These nondestructive tomographic methods are capable of providing unique in-situ measurements of how oil properties change as pressure depletes in a PVT cell. Specifically, this paper details measurements of oil density, oil and gas formation volume factor, solution gas/oil ratio, (GOR), and oil viscosity as a function of pressure. Experiments were initially performed at a slow rate, as in conventional PVT tests, allowing equilibrium to be reached at each pressure step. These results are compared to non-equilibrium tests, whereby pressure declines linearly with time, as in coreflood experiments. The incremental benefit of the proposed techniques is that they provide more detailed information about the oil, which improves our understanding of foamy-oil properties. Introduction Understanding fluid behavior of heavy oils is important for reservoir simulation and production response predictions. In heavy-oil reservoirs, the oil viscosity and density are commonly reported, but there is little experimental data in the literature reporting how oil properties change with pressure. This information would be especially useful for production companies seeking to understand and improve their primary (cold production) response. It is already widely known that foamy-oil behavior is a major cause for increased production in cold heavy-oil reservoirs along with sand production. Therefore, it would be valuable to first study the bulk fluid properties of live heavy oil prior to sandpack-depletion experiments. If the response of these properties to incremental pressure reduction can be established, this can be compared with fluid expansion during pressure depletion in a sandpack. CT scanning is useful in studying high-pressure PVT relationships. Images of a pressure vessel filled with live oil can be taken as the volume of the vessel is expanded and used to calculate bulk densities and free gas saturation. Also, CT images allow us to visually see where free gas is formed in the vessel. For example, CT scanning can be used to provide an indication of whether or not small bubbles nucleate within the oil and then slowly coalesce into a gas cap, or if free gas forms straight away. CT scanning provides much more information than conventional PVT cells. Uncertainties about where gas is forming in the oil, its effect on oil properties, and transient behavior cannot be reconciled in conventional PVT cells. Also, from CT images, the formation of microbubbles could be inferred based on the density of the oil with the dissolved gas. If the oil density decreases below the bubblepoint pressure, then it is likely that gas has come out of solution but remains within the oil; therefore, the resulting mixture is less dense than the original live oil. However, if oil density increases as the gas evolves, then the oil does not contain small gas bubbles, and gas has separated from the oil. Also, the free gas saturation growth with time, and comparison of images at equilibrium vs. immediately after the expansion of the vessel, can provide mass transfer information about gas bubble growth, supersaturation, and gravity separation. When characterizing heavy oil and bitumen fluid properties, oil viscosity is one of the most important pieces of information that has to be obtained. The high viscosities of heavy oil and bitumen present a significant obstacle to the technical and economic success of a given enhanced oil recovery option. As a result, in-situ oil viscosity measurement techniques would be of considerable benefit to the industry. In heavy-oil reservoirs that are undergoing primary production, this problem is further complicated by the presence of the gas leaving solution with the oil. Above the bubblepoint, the gas is fully dissolved into the oil; thus, the live oil exists as a single-phase fluid. Once the pressure drops below the bubblepoint and gas begins to leave solution, the oil viscosity behavior is no longer well understood. In addition to our CT analysis, this work also presents the use of low field NMR as a tool for making in-situ viscosity estimates of live and foamy oil. NMR spectra change significantly as pressure drops and gas leaves solution, and these changes can be correlated to physical changes in the oil viscosity.

scholarly journals Artificial Lift and Mobility Enhancement of Heavy Oil Reservoirs Utilizing a Renewable Energy-Powered Heating Element

ACS Omega ◽  
2019 ◽  
Vol 4 (22) ◽  
pp. 20048-20058 ◽  
Author(s):  
Murtada Saleh Aljawad ◽  
Saad Alafnan ◽  
Sidqi Abu-Khamsin
Keyword(s):  
Renewable Energy ◽  
Heavy Oil ◽  
Heating Element ◽  
Oil Reservoirs ◽  
Artificial Lift ◽  
Heavy Oil Reservoirs

Experimental study and numerical simulation of urea-assisted SAGD in developing exra-heavy oil reservoirs

2021 ◽  
Vol 201 ◽  
pp. 108436
Author(s):  
Daode Hua ◽  
Pengcheng Liu ◽  
Peng Liu ◽  
Changfeng Xi ◽  
Shengfei Zhang ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Experimental Study ◽  
Heavy Oil ◽  
Oil Reservoirs ◽  
Heavy Oil Reservoirs
Sign in / Sign up

Export Citation Format

Share Document