Temizel, Cenk (Aera Energy) | Irani, Mazda (Ashaw Energy) | Canbaz, Celal Hakan (Schlumberger) | Palabiyik, Yildiray (Istanbul Technical University) | Moreno, Raul (Smart Recovery) | Balikcioglu, Aysegul (USC) | Diaz, Jose M. (VCG O&G Consultants) | Zhang, Guodong (China Petroleum Eng and Construction Corp.) | Wang, Jie (College of Technological Studies) | Alkouh, Ahmad
As major oil and gas companies have been investing in renewable energy, solar energy has been part of the oil and gas industry in the last decade. Originally, solar energy was seen as a competing form of energy source as a threat that may replace or decrease the share of fossil fuels as an alternative energy resource in the world. However, oil and gas industry has adapted to the wind of change and has started investing and utilizing the solar energy significantly. In this perspective, this study investigates and outlines the latest advances, technologies, potential of solar both as an alternative and a complementary source of energy in the Middle East in the current supply and demand dynamics of oil and gas resources.
A comprehensive literature review focusing on the recent developments and findings in the solar technology along with the availability and locations are outlined and discussed under the current dynamics of the oil and gas market and resources. Literature review includes a broad spectrum that spans from technical petroleum literature with very comprehensive research to non-technical but renowned resources including journals and other publications including raw data as well as forecasts and opinions of respected experts. The raw data and expert opinions are organized, summarized and outlined in a temporal way within its category for the respective energy source.
Solar energy is discussed from a perspective of their roles either as a competing or a complementary source to oil and gas. In this sense, this study goes beyond only providing raw data or facts about the energy resources but also a thorough publication that provides the oil and gas industry professional with a clear image of the past, present and the expected near future of the oil and gas industry as it stands with respect to renewable energy resources.
Among the few existing studies that shed light on the current status of the oil and gas industry facing the development of the renewable energy are up-to-date and the existing studies within SPE domain focus on facts only lacking the interrelationship between solar energy and oil and gas such as solar energy used in oil and gas fields as a complementary green energy.
Zhang, Lufeng (China University of Petroleum) | Zhou, Fujian (China University of Petroleum) | Wang, Jie (China University of Petroleum) | Wang, Jin (China University of Petroleum) | Mou, Jianye (China University of Petroleum) | Zhang, Shicheng (China University of Petroleum)
ABSTRACT: Acid propped fracturing is a valid stimulation technique applied in deep carbonate reservoirs and its effect mainly depends on the conductivity. However, short-term conductivity experimental data used in existing acid propped fracturing design may not be directly applicable to real case. Aiming at this problem, this paper investigates impacts of acid-rock contact time, acid etched fracture creep, proppant size and concentration on the long-term conductivity. The study shows that the acid propped fracture retained enough conductivity under high closure stress. Gelled acid fracture conductivity increases with the longer time until it reached the upper limit when the contact time is 60 minutes. The long-term conductivity experiments show that conductivity decreased sharply in the 48 hours and underwent a gradual decline from 48 hours to 96 hours followed by the steady state after 120 hours. The ideal combination of proppant size and concentration are optimized at different stress level. An acid propped fracture conductivity correlation was also developed for calculating the conductivity. This study provides an insight of optimizing acid propped fracturing design and predicting well performance.
As significant domains of oil and gas exploration and development, carbonate reservoirs constitute almost 60% of the world's remaining oil and gas. Acid fracturing, as a conventional and effective stimulation method, has been widely used in carbonate formation (Amirhossein and Maysam, 2016). However, due to serious acid leakage and rapid acid-rock reaction speed resulting from high temperature and closure stress in deep well, the length of effective acid etched fracture is limited and the effective duration of acid etched fracture is short (Li Y et al., 2009; Suleimenova A et al., 2016;). Consequently, uniting the deep penetration of acidizing with proppant fracturing is a natural progression toward great effective stimulation of deep carbonate reservoirs. Acid propped fracturing, combining the advantages of propped fracturing and acid fracturing, is the technology that can not only readily carry proppant but also react with the carbonate formation to eliminate the formation damage. It also can connect natural fracture, maximizing the drainage area and the stimulation reservoir volume (SRV).
Tang, Xueqing (RIPED, PetroChina) | Dou, Lirong (RIPED, PetroChina) | Wang, Ruifeng (Petro Energy Co.) | Wang, Jie (RIPED, PetroChina) | Wang, Shengbao (RIPED, PetroChina) | Wang, Jianshun (RIPED, PetroChina) | Shi, Junhui (RIPED, PetroChina)
Jake field, discovered in July, 2006, contains 10 oil-producing and 12 condensate gas-producing zones. The wells have high flow capacities, producing from long-perforation interval of 3,911 ft (from 4,531 to 8,442 ft). Production mechanisms include gas injection in downdip wells and traditional gas lift in updip, zonal production wells since the start-up of field in July, 2010. Following pressure depletion of oil and condensate-gas zones and water breakthrough, traditional gas-lift wells became inefficient and dead. Based on nodal analysis of entire pay zones, successful innovations in gas lift have been made since March, 2013. This paper highlights them in the following aspects:
As a consequence, innovative gas-lift brought dead wells back on production, yielding average sustained liquid rate of 7,500 bbl/d per well. Also, the production decline curves flattened out than before.
Discovered in July, 2006, Jake field is situated at the north part of Fula Western trend with oil-bearing area of approximate 45,714 acres. This field contains two distinct productive formations in the Early Cretaceous age: Bentiu oil reservoir at the average depth of 4,724 ft plus Abu Gabra gas-condensate reservoir at the average depth of 8,425 ft. The producing reservoirs are normally pressured, and the field has a normal geothermal gradient of approximately 2.60℉/100 ft.
Zhang, Qingchen (China University of Petroleum) | Zhou, Hui (China University of Petroleum) | Wang, Jie (SINOPEC Geophysical Research Institute) | Zuo, Anxin (China University of Petroleum) | Xia, Muming (China University of Petroleum)
Due to the gradient calculation requiring cross-correlation of the forward wavefields and back-propagated residual wavefields at each time step, the great storage amount becomes an obstacle of practical application of full-waveform inversion, especially in three-dimensional elastic case in time domain. In this paper we extend the efficient boundary storage to the time domain three-dimensional elastic full-waveform inversion on multi-GPU. Based on the efficient boundary storage strategy, the storage amount can be reduced dramatically. As a result, we can save the partial forward wavefields directly on the GPU memory and reconstruct the full forward wavefields synchronized with back-propagated residual wavefields along the reverse time direction. This strategy avoids frequent CPU-to-GPU or GPU-to-CPU memory copy (extremely time-consuming) at the cost of the recomputation (little time-consuming) of the forward wavefields. Our forward simulation tests show that the GPU’s supercomputing effect can be fully exploited with this strategy. In addition, we perform a three-parameter simultaneous inversion of P-, S-wave velocities and density. The favorable inversion results verify that our algorithm is feasible and efficient.
Annular flume has been widely applied in researches of the laws of sediment motion for its favorable features: it meets the distance requirement of fine sediment settlement without the influence of inflow and outflow; meanwhile, it has such advantages as simple structure and easy operation. In this study, propeller current meter is used to measure the layering current velocity of an annular flume under different water depths and rotating speeds, by which we can obtain the characteristics of the flow field. There exists nonnegligible secondary flow in the annular flume, and its maximal reduction can be achieved by rotating the channel and the top ring in contrary directions. In this experiment, a proper selection of the speeds of the channel and the ring is provided. Based on the analysis of experimental data, it can be seen that the vertical velocity distribution of the annular flume follows the S-shape distribution law. The flow rate has a larger velocity gradient only at boundaries, while in the central area of the flow field, the velocity gradient remains small and the curve fits a cubic function. The radial distribution of velocity is linear and the velocity decreases from the outer edge to the inner edge, which leads to the same distribution of each cross section. So the two-way annular flume can be used to simulate an infinite long straight flume.
With the depletion of conventional oil resources, heavy oil and bitumen play an increasingly important role as the main resources for crude oil. This is particularly true in Alberta since it has in excess of 400 x 109m3 of heavy oil and bitumen. In Canada, most of heavy oil and bitumen resources are developed with thermal methods. Thermal methods for heavy oil and bitumen recovery include the injection of steam in the form of SAGD (steam assisted gravity drainage), CSS (cyclic steam stimulation), and steam flooding, whereby thermal energy is given to the oil, reduces its viscosity and allows it to flow towards a production spot. These methods have not been yet investigated for the large fraction (in excess of 50%) of oil sands that are thinner, less permeable, heterogeneous, or contacted by water. Electrothermal methods have attracted more and more attention as an alternative to conventional thermal methods for the difficult reservoirs where conventional thermal methods are not expected to work well.
In this study, a series of comparative studies are carried out using a simulation tool developed by CMG (Computer Modeling Group). In a series of marginal reservoirs such as thin reservoirs, low permeability reservoirs, and reservoirs with bottom water, both the SAGD process and the electrothermal process are applied. The resulting recoveries are compared and economics are evaluated for both methods for each case. The typical SAGD problem of the McMurray oil sands is used as the base case benchmark.
Our results to date indicate that under favorable conditions, electrothermal methods have the potential to recover thin bitumen reservoirs that cannot economically be produced by the SAGD process. Furthermore, electrothermal methods can achieve recovery factors superior to SAGD in terms of the production of thin bitumen reservoirs with bottom water and low permeability bitumen reservoirs. Controlled heating seems to be beneficial in electrothermal processes. Innovative well placement also appears to have favorable effects.
Thermal methods for heavy oil and bitumen recovery include the injection of steam as in the SAGD (Steam Assisted Gravity Drainage), CSS (Cyclic Steam Stimulation), and steam flooding processes. Thermal energy increases the temperature of the oil, reducing its viscosity and thereby allowing it to flow efficiently towards a production well. The electro-thermal process is an alternative (possibly a compliment) to steam injection processes. With ever-increasing natural gas prices, or corresponding reduction of natural gas supply, electro-thermal processes can be economically competitive compared to other thermal methods. An optimized electrothermal process can bring over 75% of heavy oil or bitumen to the surface as demonstrated by a recent field pilot in the Athabasca oil sands.
This study aims at optimizing electrothermal processes by vaporizing water in-situ. The Computer Modeling Group (CMG) reservoir simulation software is used to perform a series of preliminary simulation studies of electro-thermal heating in the Athabasca oil sands. First of all, the incremental oil recovery by vaporization is estimated based on a three block conceptual model. Secondly, a field scale model is set up to evaluate the effect of electrode spacing, water injection rate and electrical heating rate on the ultimate bitumen recovery. A statistic tool is used to analyze the simulation results in order to spot the optimum condition for maximizing bitumen production with water vaporization in-situ.
Simulation results showed that the incremental recovery brought by the water vaporization could be as high as 25% OOIP for Athabasca oil sands reservoirs based on the conceptual model. A sensitivity study on the field scale model, showed that the combination of medium electrical heating rate, low water injection rate, and small electrode spacing can maximize bitumen production economically with mild water vaporization in-situ.
The study demonstrated a promising technique for the future heavy oil / bitumen production. It also showed that electrothermal processes could be operated independently and produce considerable amount of bitumen economically.