Akbary, Hamid (Petropars) | Mousavi Khoshdel, Seyed H. (Petropars) | Bolouki Azari, Mohammad R. (Petropars) | Saeedi, Alireza (Petropars) | Hosseinzadeh, Mohammad (South Pars Gas Company) | Ehsaninejad, Akbar (South Pars Gas Company) | Bahmannia, Gholamreza H. (South Pars Gas Company) | Babu, Dasari R. (DHST Consultants)
Sea lines transporting gas toward the north (Iran) and south (Qatar and Saudi Arabia) and originating from fields located in the central parts of the Persian Gulf exhibit different thermal regimes. The lowest reported arrival temperatures of the gas were 18 and 11°C for the sea lines transporting gas to the northern and southern shores, respectively. The difference between the two is significant and could radically alter the hydrate-mitigation strategy and the associated economics. Metocean data reported in this study and from previous studies (Appendix A) show that the northern part of the Persian Gulf, which is also deeper, attains a well-mixed state during winter months. During this phase, the arrival temperature of the gas for South Pars (SP) sea lines decreases steadily and goes through a minimum at approximately the middle of February every year. In the southern region, the sea is shallow and water is more saline. Sinking of saline water when exposed to cool and dry ambient winter conditions is probably responsible for the reported abrupt decrease in arrival temperatures in the case of the Karan gas line. The immediate recovery of the same may be caused by the local wind/tide conditions. The likely origins of the observed lowest temperatures in the north and south regions are Arctic winds of short duration and desert winds of fairly long duration, respectively. This study summarizes hydrate-inhibition practices for these sea lines, and indicates a possibility of using the sea lines as “indirect thermometers” to provide important physical oceanographic data for long terms in a limited but economical way with fewer interruptions.
Reusing waste water from the oil field for hydraulic fracturing has become an important topic in the oil and gas industry, and it requires a thorough understanding of both the quality and quantity of the waste water. In this paper, water production from horizontal shale wells in five sections of the Wattenberg field in northeastern Colorado was analyzed. Models were developed for these wells for future water-production prediction. A spatial analysis was also conducted by comparing water production from each section with the gas/oil-ratio (GOR) value for each well. Results indicate that the GOR value of wells has a significant impact on water production in the first year of operation. Wells with low GOR value tend to have higher fracturing-flowback volume and, furthermore, water-recovery rate. Results from this study also provide valuable information for estimating water production from unconventional shale fields, which is critical for the design of wastewater collection and treatment facilities in the field.
Fang, Jilei (Yantai Jereh Oilfield Services Group) | Meng, Xianghai (Yantai Jereh Oilfield Services Group) | Xu, Guoling (Yantai Jereh Oilfield Services Group) | Yue, Yong (Yantai Jereh Oilfield Services Group) | Cong, Peichao (Yantai Jereh Oilfield Services Group) | Xiao, Chao (Yantai Jereh Oilfield Services Group) | Guo, Wenhui (Yantai Jereh Oilfield Services Group)
Oily waste, as the intrinsic byproduct of the oil and gas industry, is considered hazardous waste, and thermal-desorption units (TDUs) have been applied widely to process this waste under an environmentally sound protocol.
A TDU is used to separate hydrocarbons, water, and solids by indirect heating. In the process, the base oil and chemical additives are fractured and dissociated with the increasing temperature, resulting in a pungent odor from the recovered hydrocarbons. It is this odor that has restricted the reuse of the recovered hydrocarbons. After analysis, it is determined that the pungent odor is caused by the presence of sulfur and nitrogen compounds. Consequently, an odor-treatment system that is based on the catalytic cracking and preferential adsorption method has been developed and introduced into the TDU for the removal of the odor. The sulfur and nitrogen compounds are cracked into a broken-chain structure under the action of a catalyst, and then they are adsorbed selectively by adsorbing material. After treatment, the removal rate of total sulfur and total nitrogen reaches 93.74 and 98.41%, respectively, realizing the elimination of the pungent odor. Furthermore, the color of the recovered hydrocarbons fades away.
Currently, odor-treatment technology is applied directly in situ, where the oily cuttings are stored, and more than 1,300 bbl of acceptable hydrocarbons have been recovered. These recovered hydrocarbons meet all operating requirements, and have been reused for oil-based mud (OBM) or sales. Because of the operation, the recovered hydrocarbons could have a higher price for sales, which proves the process to be not only environmentally sound, but also valuable to the bottom line of the operator’s production.
A TDU with odor-treatment system can bring technical and economic advantages to the user. Not only has the process proved to be very economical for recovered hydrocarbons, it is also preventive and can mitigate potential environmental liabilities.
The Hail 3D transition-zone seismic survey, carried out by Abu Dhabi National Oil Company (ADNOC) in 2013–14, was located within an area considered to be of significant national and international environmental importance. Falling within a designated marine protected area (MPA) that was ratified by Abu Dhabi ministerial decree, as well as in a United Nations Educational, Scientific, and Cultural Organization (UNESCO) world-biosphere reserve, high standards of environmental and ecological management throughout the acquisition program were of paramount importance.
Effective environmental and ecological management throughout the project was attained through the design and implementation of numerous working procedures and monitoring programs. These included the development of specific sets of mitigation guidelines for use during transition-zone surveys for minimizing disturbance and injury to marine mammals and turtles and for operating within mangrove areas, and the use of environmental profiling, auditing, and post-operational monitoring in both the terrestrial and marine environment for collecting new data on the biodiversity and ecology of the area.
For the first time, we present ecological and environmental data collected over a period of 12 months within the Hail shoal area. In addition to data on species numbers and distributions, we present a method for effectively managing complex seismic surveys being carried out simultaneously in both the marine and terrestrial environment.
For marine-mammal and turtle species, visual observations were compared over time and analyzed against seismic activity by use of a regression analysis. Our results demonstrate seasonal variation in total numbers throughout the year, with no significant reduction in observed numbers occurring as a result of seismic-exploration activities.
We further demonstrate how a complex seismic survey can be managed and supervised to mitigate and minimize the environmental footprint or negative impacts on biodiversity as a result of the exploration and resource development considered crucial to the socioeconomic development of Abu Dhabi.
The entrainment of solid particles in crude oil occurs during production from reservoirs with low formation strength. The stationary solid-particles bed at the horizontal pipe bottom can cause operational problems such as production decline, excessive pressure loss, equipment failure, erosion, and corrosion. Solid-particles deposition can be managed by operating above the critical solid-particles-deposition velocity, which is the velocity that maintains the continuous movement of particles at the pipe bottom. Here, a comprehensive analysis of solid-particle flow regimes in stratified flow in a horizontal pipeline is presented, which is a novel contribution because it is applied to multiphase flow. The effect of concentration on the solid-particle flow regimes and identification of the critical solid-particles-deposition velocities for various particle concentrations are also investigated.
The understanding of solid-particle flow regimes in pipelines for any given set of operational conditions is important for identifying the nature of particle interaction and movement. Experimental studies are conducted in a 4-in. horizontal pipeline for a stratified flow regime that uses air, water, and glass beads at relatively low solid-particles concentrations (<10,000 ppm). The effects of different experimental conditions, such as gas velocity, solid-particles concentration, and particle size, are investigated in this study. Six main solid-particles flow regimes in horizontal air/water flow are identified, and can be distinguished visually: fully dispersed solid flow, dilute solids at wall, concentrated solids at wall, moving dunes, stationary dunes, and stationary bed. Therefore, the critical solid-particles-deposition velocities are determined on the basis of the transition between moving (concentrated solids at wall/moving dunes, as appropriate) and stationary (stationary dunes/bed, as appropriate) solid particles. The experimental data show that with small particle size, the critical solid-particles-deposition velocity is almost independent of concentration, while with larger particle sizes, the critical velocity increases with the concentration.
Wang, Zhihua (Northeast Petroleum University) | Lin, Xinyu (Northeast Petroleum University) | Yu, Tianyu (University of Western Australia) | Hu, Zhiwei (Daqing Oilfield Company Limited) | Xu, Mengmeng (Northeast Petroleum University) | Yu, Hongtao (Northeast Petroleum University)
High-concentration polymer flooding (HCPF) is an enhanced-oil-recovery (EOR) method that has been used since conventional polymer flooding was applied in the main reservoirs of the Daqing oil field because its higher viscoelasticity can improve the oil-displacement efficiency. However, as a result of more produced hydrolyzed polyacrylamide (HPAM), the oil/water mixture is emulsified easily and separated with more difficulty.
In this work, a case history of dehydration technology for HCPF production in the Daqing oil field is reviewed, and a laboratory investigation to assess the emulsification behaviors of HCPF-produced emulsions is conducted. Besides the dehydration-mechanism description of a high-voltage pulsed electrical field, electrostatic-demulsification performance for produced liquid from HCPF production is improved, and the operation parameters are optimized. Recent actual acceptance of the optimization recommendations is presented, and the field-application results are also discussed. The results indicate that dehydration technology for the Daqing oil field has been innovated with the industrialization of the EOR process. Traditional methods of gravity or centrifugal settling are replaced; this upgraded freewater knockout (FWKO) has the functions of adsorption, wetting, collision and coalescence, and oil pretreating for HCPF production. Because it is dominated by periodic vibration as its main mechanism, the pulsed-direct-current (DC) electrostatic-demulsification technique has some advantages in overcoming the obstacles encountered by regular types of electrical-field dehydration processes at strong emulsification stability. Compared with previous dehydration processes having complex alternating-current (AC)/DC electrical fields, the process with a pulsed-DC electrical field shows a unique advantage in terms of emulsified water-separation efficiency, energy conservation, environmental protection, lower labor intensity, and more-stable operation, and the dehydration performance meets the oil-treating standards.
As the surface-matching technology of EOR, this improvement in dehydration technology is significant for promoting the construction of an HCPF demonstration project and accelerating petroleum development and production efficiently.
Experimental and numerical heat-transfer analysis was conducted on a T-shaped acrylic-glass pipe, representing a production header in a subsea production system with a vertical deadleg. The header was insulated, while the deadleg was not insulated and carried a cold spot on the top. The experimental conditions were set to mimic those of steady-state production, followed by a 3-hour shutdown (cooldown). The internal fluid temperature and the wall temperature were measured by use of resistance temperature detectors (RTDs) and thermocouples, respectively, while particle image velocimetry (PIV) was used to measure the velocities in the deadleg. It was shown that the mean velocity field during both steady state and cooldown was periodic, with a clockwise and counterclockwise rotation along the deadleg wall. By use of a k–ω shear-stress transport (SST) Reynolds-averaged Navier Stokes (RANS) model in ANSYS CFX (2013a, b), the thermal field was correctly predicted for 3 hours of cooldown by modeling the cold spot as an isothermal wall. The RANS model was unable to recreate the periodic velocity field observed in the experiment.
Because of its efficiency, cleanliness, and reliability, natural gas is an important sector in global energy consumption. It supplies nearly one-fourth of all energy used in the United States and is expected to increase 50% within the next 20 years. More gas-delivery infrastructure is being constructed to meet the transportation requirement of the ever-increasing demand for natural gas, while at the same time, the existing gas infrastructure is aging. Ensuring natural-gas-infrastructure reliability is one of the critical needs for the energy sector. Operators prefer to capitalize on the transportation capacity of these old pipeline systems to reduce the cost for building new pipelines, but they run a high risk of encountering partial blockage in the pipeline, which can cause operating pressure to exceed the safety specification. Therefore, the reliable and timely detection of a partial blockage in a gas pipeline is critical to ensuring the reliability of the natural-gas infrastructure.
To design proper pigging tools, it is important to detect the location and size of partial blockages. Physical inspection and mathematical-model simulation are used to identify partial blockage in gas pipelines. Generally, the physical method can result in an accurate detection of the location and size of the partial blockage, but at the expense of production shutdown and high cost/long time to run the physical detection, which is a very expensive measure in a long-distance gas pipeline. The mathematical simulation detects partial blockage through numerical modeling, which could provide a quick evaluation at a much lower cost, but with higher uncertainties. Our literature review indicates that a simple, practical, and reliable method to detect partial blockage without a recorded inlet or outlet pressure is in great demand.
In this study, we develop a multirate test method to detect partial blockage in a gas pipeline. By conducting multirate tests, the location and size of the partial blockage can be evaluated. The new method can be applied under the conditions of no measured inlet or outlet pressure, which have not been investigated before. It is worth locating a partial blockage under these conditions because as oil and gas exploration and production move to harsh environments, no pressure gauge being installed at the inlet or outlet of the pipeline can be a common circumstance in the fields. Even for onshore fields or fields with easy access, pressure is not transferred to the central office in real time. In addition, the metering equipment and pressure gauges installed in the pipeline may not be working. Therefore, our method provides a practical, quick, and low-computational-cost approach to estimate partial blockages corresponding to these conditions.
The partial blockages in a single pipeline and in parallel/looped pipelines were evaluated in this project by use of the proposed method. Considering that most of the complicated pipeline systems under operation can be decomposed into basic units, such as single pipeline and parallel/looped pipelines, the proposed model can realistically and feasibly identify partial blockage in a complex pipeline network. Furthermore, existing studies assume only single partial blockage in the pipeline, which limits the application of available models because the detection will be misleading if there is more than one partial blockage in the pipeline. To fill this gap, we developed a model to differentiate the single-partial-blockage scenario from the multiple-partial-blockage scenario on the basis of multirate tests. The identification is critical because it guides partial-blockage detection in the right direction.
The importance of tuning injection-water chemistry for upstream is moving beyond formation-damage control/water incompatibility to increasing oil recovery from waterflooding and different improved-oil-recovery (IOR)/enhanced-oil-recovery (EOR) processes. Smart waterflooding through tuning of injection-water salinity and ionic composition has gained good attention in the industry during recent years for IOR in carbonate reservoirs. The water-chemistry requirements for IOR/EOR have been relatively addressed in the recent literature, but the key challenge for field implementation is to find an easy, practical, and optimum technology to tune water chemistry. The currently available technologies for tuning water chemistry are limited, and most of the existing ones are adopted from the desalination industry, which relies on membrane-based separation. Even though these technologies yield an achievable solution, they are not the optimum choice for altering injection-water chemistry in terms of incorporating selective ions and providing effective water management for large-scale applications. In this study, several of the current, emerging, and future desalination technologies are reviewed with the objective to develop potential water-treatment solutions by use of both seawater and produced water that can most efficiently alter injection-water chemistry for smart waterflooding in carbonate reservoirs.
Standard chemical-precipitation technologies, such as lime/soda ash, alkali, and lime/aluminum-based reagent, are only applicable for removing certain ions from seawater. The lime/aluminum-based reagent process looks interesting because it can remove both sulfates and hardness ions to provide some tuning flexibility for key ions included in the smart water. There are some new technologies under development that use chemical solvents to extract salt ions from seawater, but their capabilities to selectively remove specific ions need further investigation.
Forward osmosis (FO) and membrane distillation (MD) are the two emerging technologies, and they can provide good alternatives to reverse-osmosis (RO) seawater desalination for the near-term. These technologies can offer a more cost-effective solution in which there is availability of low-grade waste heat or steam. The two new desalination technologies, based on dynamic vapor recompression and carrier-gas extraction (CGE), are well-suited to treat high-salinity produced water for zero liquid discharge (ZLD), but they may not be able to provide an economical solution for seawater desalination. Carbon nanotube-based desalination, graphene sheet-based desalination, and capacitive deionization are the three potential future seawater-desalination technologies identified for the long term. Among these, carbon nanotube-based desalination is more attractive, although the technology is still largely under research and development.
The results of this review study show that there is no commercial technology yet available to selectively remove specific ions from seawater in one step and optimally meet the desired water-chemistry requirements of smart waterflooding. As a result, different conceptual process configurations involving selected combinations of chemical precipitation, conventional/emerging desalination, and produced-water-treatment technologies are proposed. These configurations represent both approximate and improved soutions to incorporate specific key ions into the smart water selectively, besides presenting the key opportunities to treat produced-water/membrane reject water and provide ZLD capabilities in smart-waterflooding applications. The developed configurations can provide an attractive solution to capitalize on existing huge produced-water resources available in carbonate reservoirs to generate smart water and minimize wastewater disposal during fieldwide implementation of smart waterflood.
In a carbonate field under high pressure and high temperature (HP/HT), a gas-injection scheme has been assessed to improve oil recovery through pressure maintenance and miscible displacement. The potential study assumed sequential application of several gas-injection concepts, including raw-gas injection (RGI) and acid-gas injection (AGI). Flow-simulation studies of these concepts revealed a variety of compositional changes to the in-situ fluid, depending on the injection scheme and composition of the injected gases. Fluid compositional change is a common trigger of asphaltene instability; therefore, to ensure a robust gas-injection development, it is important to evaluate the risk of asphaltene precipitation. Because of high hydrogen sulfide (H2S) concentrations of AGI fluid under HP/HT in-situ reservoir conditions, it is difficult to take an experimental approach for evaluating gas-mixed asphaltene-flow assurance at a normal laboratory. Hence, at the concept-selection stage, this paper focuses on an alternative approach for numerical-modeling analysis of the AGI scenario, and presents the way in which AGI impacts asphaltene-precipitation behavior. On the basis of the asphaltene model established by applying a cubic-plus-association (CPA) equation of state (EOS), which was calibrated with the experimentally measured asphaltene-onset pressure (AOP), a new binary-interaction-parameter (BIP) correlation between H2S and hydrocarbons was incorporated to evaluate variation of the asphaltene-precipitation envelope (APE) with periodic compositional change observed from the AGI-flow simulation. In the AGI scenario, injection gas was assumed to be 90 mol% H2S and 10 mol% carbon dioxide (CO2). The original reservoir fluid contains 15 mol% H2S concentration. During the 3D reservoir-simulation study for the AGI scenario, H2S concentration in produced fluid was observed to increase up to 76 mol% at a well located near acid-gas injectors. In the APE sensitivity analysis that was conducted independently for each composition of H2S and CO2, the asphaltene model revealed that the base APE decreased as the H2S concentration increased and expanded as the CO2 concentration increased. As a result, for the mixed compositions, the opposing effects on the APE offset each other, and the acid-gas addition produced a subsequent decrease of the APE. In summary, this work supported a relative merit of AGI from a thermodynamic asphaltene-flow-assurance point of view, while verification is needed with experimental data in the next defined/detailed engineering stages.
From stage-gate process-engineering points of view, this case study is also worthy to appropriately estimate potential concepts that have complexity of technical evaluation. Such complexity might be encountered when assuming an emerging condition or when introducing emerging technologies. In such cases, potential concepts are often difficult to evaluate fairly with existing technologies, but can possibly be evaluated with newly introduced or developing evaluation measures. However, these new and developing measures require cost that can be justified at the matured stage of development, but that cannot be justified at the concept-screening stage. In the future, the exploration and production (E&P) industry will be required to access more emerging fields of lesser easy oil; thus, this case study will be an example engaging a similar situation.