Today, almost half of Western Canada's natural-gas production comes from the Triassic-aged Montney formation, a sixfold increase over the last 10 years while gas production from most other plays has declined. In the last few years, demand for condensate as diluent for shipping bitumen has driven development of liquids-rich Montney natural gas leading to a surge in gas production and gas-on-gas competition in the Western Canadian Sedimentary Basin (WCSB), which has driven local natural gas prices down. This has had a material effect on the operations and finances of companies active in the Western Canada and is reshaping the Canadian gas industry. A significant portion of this growth has taken place in NE British Columbia and with the planned electrification of the industry in British Columbia, including the nascent LNG operations, will influence tomorrow's power industry in this region. NE British Columbia is a geographically large area with sparse population and the power supply into this region has lagged behind development of oil and natural gas resources. The area was originally served from geographically closer NW Alberta. More recently, supply was established from the BC Hydro power grid with the most significant developments being Dawson Creek-Chetwynd Area Transmission (DCAT) completed in 2016 and the additional 230 kV transmission projects scheduled for completion in 2021.
This paper presents a description of the technology for numerical simulation of thermal gas treatment on Bazhenov formation, taking into account features of Bazhenov formation and thermal gas treatment and assumptions of the simulator.
First of all it is required to determine the following parameters: voidness (porosity), permeability, fracturing, free oil (initial oil saturation), TOC (Total Organic Carbon). And also it is important to establish dependence of the parameters on temperature and pressure. Then, the process of thermal gas treatment can be conditionally divided into several stages: Effective production of light oil from drainable (permeable) zones (miscible displacement in front of the combustion front) Involvement of zones of reservoir containing kerogen during to heat treatment (pyrolysis reaction) and liberation of light oil and gaseous hydrocarbons from "locked" zones of reservoir. Involvement of the initially non-drainable (impermeable) zones of reservoir, named matrix (doesn’t mean the same as in dual porosity/permeability system). Especially these zones are the greatest interest among reservoir engineers because it can contain huge reserves of hydrocarbons.
Effective production of light oil from drainable (permeable) zones (miscible displacement in front of the combustion front)
Involvement of zones of reservoir containing kerogen during to heat treatment (pyrolysis reaction) and liberation of light oil and gaseous hydrocarbons from "locked" zones of reservoir.
Involvement of the initially non-drainable (impermeable) zones of reservoir, named matrix (doesn’t mean the same as in dual porosity/permeability system). Especially these zones are the greatest interest among reservoir engineers because it can contain huge reserves of hydrocarbons.
As a result of the steps described above, a 2D model was created, a numerical realization of the key processes taking place during thermal gas treatment on Bazhenov formation was carried out. Further, the main zones characterizing the process were identified and a physical justification for the individual indicators was given. Calculations of variants involving the matrix in the drainage process were carried out.
The calculated technological effect over a 50-year period of thermal gas treatment on the model (involving the production from matrix) was about 50% of the additional oil production, relative to the thermal gas treatment variant without involvement of matrix.
According to the results of the work, an evaluation of the efficiency of wet combustion was carried out during thermal gas treatment. The results of the calculations clearly demonstrate the advantage of using wet combustion. It is as stimulation of production of reservoir oil, as of additional synthetic oil as a result of kerogen pyrolysis reaction.
An experimental study of a gravity-driven downhole separator for a pumped horizontal or deviated well is presented in this study. It considers the effects of the upstream flow, gas and liquid flow rates and deviation angles on the global separation efficiency and the free gas at the pump intake. The efficacy of downhole separators is typically tested under steady-state conditions where the fluids are injected above the separator. A new outdoor facility, which allows the injection of a two-phase mixture below the separator was designed, constructed, and used in this study. Gas and liquid flow rates and deviation angle are varied to study the liquid holdup in the liquid-rich outlet and the separator efficiency. The experimental results demonstrate the effects of the operation conditions and deviation angle on the behavior of downhole separators. It is found that the separator has two regions of performance; namely, high efficiency region and a region where the efficiency decreases with the liquid flow rate. Moreover, the effect of the deviation angle affects the results. The findings provide conditions under which and where the separator can be operated efficiently in the field.
Bai, Chunlu (School of Mechanical Engineering, Beijing Institute of Petrochemical Technology) | Liu, Meili (School of Mechanical Engineering, Beijing Institute of Petrochemical Technology) | Chen, Jiaqing (Beijing Key Laboratory of Pipeline Critical Technology and Equipment for Deepwater Oil & Gas Development, Beijing 102617, China) | Wang, Chunsheng (School of Mechanical Engineering, Beijing Institute of Petrochemical Technology) | Shang, Chao (Beijing Key Laboratory of Pipeline Critical Technology and Equipment for Deepwater Oil & Gas Development, Beijing 102617, China) | Zhang, Ming (Beijing Research Center, CNOOC China Co. Ltd)
Efficient and compact separation technology is in urgent need for many oilfield exploitations because of increasing water cut and strict discharge regulations. A compact axial hydrocyclone is presented to pre-separate water from the wellstream. Experimental investigation was carried out to qualify its performance. A test loop is designed to perform experimental investigations. The flow loop is fabricated to manipulate and control various operational variables, such as the oil/water mixture flow rate (0.5-2 m3/h), the oil droplet size, and the water-to-oil ratio (65/35 to 100/0). A combination of venturi tube and static mixer is used to mix oil/water mixture. Dehydration rate and oil concentration at water outlet are used to evaluate the oil/water separation performance. A series of experiments have been carried out to test the performance of the novel hydrocyclone. Inlet parameters, including inlet flow rate, water cut, droplet size and split ratio, have been evaluated. Inlet flow rate, water cut, and droplet size have significant effects on the separation performance. When the oil concentration in the water outlet is controlled to be less than 1,000 ppm, a maximum dehydration rate of 70% can be obtained. The compact axial hydrocyclone exhibits high separation performance and reliability for a wide range of operating conditions. A stable oil core without vortex oscillations is observed. This effect, combined with the low pressure drop, indicates a stable swirl with low turbulence, which enables a higher capacity of the compact axial hydrocyclone compared to traditional hydrocyclone.
Brady, Jerry (Brady Technologies of Alaska) | Passmore, Kevin (Halliburton) | Paskvan, Frank (BP) | Wilkes, Jason (Southwest Research Institute) | Allison, Tim (Southwest Research Institute) | Swanson, Erik (Xdot Engineering and Analysis) | Klein, John (Roto-Therm Incorporated)
This is the first time a compressor and turbo expander have been built small enough to be run through tubing and operated autonomously from the surface. A brief review of the overall system design and critical component design and testing are followed by a detailed review of the surface testing of the entire prototype machine at simulated downhole conditions. The SPARC concept uses the excess production pressure (energy) that is usually wasted across a choke or elsewhere in the production system to generate power through a downhole turbo-expander that runs a downhole gas compressor to reinject a portion of the gas stream. The system consists of a downhole separator, compressor, turbo-expander and other standard downhole equipment for the necessary plumbing. The successful test results of the bearing and thrust disk component testing at up to 1,000 psig and 450 F are provided, followed by the successful yard test results of the entire SPARC prototype machine at downhole flowing conditions, including all the rotating equipment (turbo expander, compressor, and shaft), in situ process-lubrication system, and autonomous controls.
Two mature onshore gas condensate fields, treated in one sour gas plant, are investigated with the objective to increase their recovery and to extend their economic field life. The impact of a surface pressure reduction on both reservoir delivery and facility operability is examined.
A predecessor project successfully proved the capability of the sour gas plant to treat declining gas flow rates under a wide pressure range from some 70 bara down to about 14 bara. This paves the way for an integrated method looking at stepwise pressure reduction in the whole system from the wellheads via the compressor stations and down to the sour gas treatment plant. In an iterative approach the outcomes of a subsurface PETEX model, a surface HYSYS model and compressor capacity calculations are matched. Production rate and system pressure are predicted versus time.
It is fundamental that the capacities of the reciprocating machines in the compressor stations can be increased by lowering their discharge pressures. The higher capacity achieved through lower discharge pressure in turn reduces wellhead pressures and, in consequence, enhances recovery. Respective subsurface and surface modeling and engineering studies indicate the feasibility of a system pressure reduction and the positive effects on recovery and process safety.
In particular, full system test runs covering most of the anticipated pressure ranges and specific compressor tests confirm the modeling and engineering results. Compared to other scenarios involving additional compressors a CAPEX reduction of 85% is achieved. Also 40% OPEX per year are saved. Although these latter scenarios with more/bigger compressors allow for a quicker pressure reduction at the wellheads and higher revenue, their high costs more than offset their revenue advantage over the optimized approach.
The low cost scenario increases ultimate gas recovery by 5% compared to the Asset Base. In total, the economic field life is extended by approximately six years. Additionally, the process safety increases due to the lower system pressure.
Low cost and optimized production solutions in mature onshore gas assets can only be developed using a strongly integrated multidisciplinary approach. The entire production system from the reservoir to the sales gas handover point must be considered. Notably, the suggested system pressure reduction in declining fields works with complex sour gas plants and with reciprocating compressors.
The US Department of Energy (DOE) has announced the selection of six projects to receive approximately $30 million in federal funding for cost-shared research and development in unconventional oil and natural gas recovery. The projects, selected under the Office of Fossil Energy's Advanced Technology Solutions for Unconventional Oil and Gas Development funding opportunity, will address critical gaps in the understanding of reservoir behavior and optimal well-completion strategies, next-generation subsurface diagnostic technologies, and advanced offshore technologies. As part of the funding opportunity announcement and at the direction of Congress, DOE solicited field projects in emerging unconventional plays with less than 50,000 B/D of current production, such as the Tuscaloosa Marine Shale and the Huron Shale. The newly selected projects will help master oil and gas development in these types of rising shales. This cement will prevent offshore spills and leakages at extreme high-temperature, high-pressure, and corrosive conditions.
A numerical simulation model was designed to evaluate the technical viability of in-situ upgrading using dispersed nanocatalysts in heavy oil reservoirs. Aquathermolysis reactions are represented by a practical kinetic model based on SARA analysis, being consistent with the thermodynamic characterization. With this simplified model, the API gravity enhancement in core-flooding tests was reproduced. The mathematical formulation couples mass and energy transport equations along with a rigorous three-phase equilibrium equation of state. Also, a nanoparticle transport equation was coupled to account for reversible and irreversible non-equilibrium retention, and water-oil partitioning. PVT data were matched successfully, including API gravities and oil viscosities. Reaction rates were adjusted by means of batch-reactor information, while nanoparticle retention was validated using reported single-phase core-flooding tests. Different core-flooding experiments from the literature were reproduced to calibrate the phases transport parameters, and further up-scaled to reservoir conditions. Validation of the model with experimental data suggests that the lumping scheme based on SARA analysis and the modeling of nanoparticle transport and retention, capture the most important phenomena occurring during in-situ upgrading processes. Field-scale simulations, of a sector model from an oil reservoir in the Magdalena Medio Valley basin in Colombia, showed that the in-situ upgrading with nanoparticles can increase the recovery factor up to 5% compared with typical steam injection. However, the oil upgrading achieved in the continuous injection was lower than the one obtained in the core-flooding tests. The numerical model presented in this work, which includes a dynamic nanoparticle retention model, changes on relative permeability alteration due to nanoparticle surface deposition, and a suited kinetic-thermodynamic representation, is able to describe correctly the most relevant phenomena observed during nanocatalysts in-situ upgrading process.
Recovery and valorization of wasted gas associated to methane processing (i.e. leakages from rotating equipment and flared gas) has usually been avoided due to the inherently limited amount of gas of these streams. Moreover, the technical complexities are further enhanced when applied to aging infrastructures and old compression unit designs, making the solution complex and less cost-effective.
However, emission control regulation is progressively limiting the atmospheric release of gases from the hydrocarbon production and processing. These requirements have triggered the development of new technical solutions to limit even small gas streams typically neglected in the past. Typical examples of small leakages tolerated in gas processing are associated with the Dry Gas Seals (DGS) primary vents. The limited amount of gas released did not justify a recovery system, leaving flaring as the only viable option.
In this paper, the technical solutions for compressor DGS primary vent recovery are presented, with further discussion on the integration into the gas process. Financial sustainability of the solutions is also presented, with the analysis of two selected cases. The presented solutions are designed to reflect the positive impact of wasted gas reduction, contributing to reaching environmental sustainability targets in oil and gas.