Summary 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.
Summary When a slickline and/or an electrical wireline job is required on offshore oil/gas platforms that have no crane equipment, a helicopter load/unload operation is a common method used for transporting materials such as winch units, power-pack units, blowout-preventer (BOP) units, and lubricators from the platform or from the offshore complex to the platform. A series of materials is transported separately by helicopter so that one lifted material can be within the maximum loading capacity of the helicopter. A materials-transportation package typically consists of four or five load/unload operations for an entire set of materials. These frequent load/unload operations are performed with a hovering action, which has the highest risk among helicopter actions (i.e., taking off, cruising, and approaching/landing). To achieve safety, all risk-mitigating factors are adequately incorporated into a plan that should be shared with all crew (pilot, company supervisor, slickline/wireline operators) in advance of the operation. This paper discusses mitigations from various points of view, in addition to summarizing general safety tips. As a result of considering the psychological response of the ground crew on the basis of actual field experience, this paper recommends how to remove mental factors that silently act on the actions of a helicopter marshaller. Moreover, fundamental measures are recommended to update marshalling methods and to use new-generation helicopters that are designed for improved safety requirements.
Summary 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.
Extending the useful producing life of the growing universe of mature wells has become a hot topic in today's challenging oil production environment. With large reduction in new well and field development, and limited capital expenditure available for facility optimizations, prospects for production increases may appear dismal. But reasonable strategies to unlock stubborn reserves and optimize immediate production do exist.
Why should CFD be part of your separator design? CFD produces a wide range of emotions from abject fear, often involving flashbacks to university class and a dizzying array of partial-differential equations, to curiosity and even enthusiasm. This article’s goal is to allay those fears.
Summary 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.
Summary An experimental study is conducted by use of a 6-in.-inner-diameter (ID) facility to investigate characteristics of three-phase stratified wavy flow in horizontal pipelines. The experiments are conducted under low-liquid-loading condition, which is very commonly observed in wet-gas pipelines. The analyzed flow characteristics include wave pattern, liquid holdup, water holdup, pressure gradient, and wetted-wall fraction. The experimental range covers superficial-gas-velocity (vSg) values of 8 to 23 m/s, superficial-liquid-velocity (vSL) values of 1 to 2 cm/s, and inlet-liquid-stream water-cut values of 0 to 100%. Differential-pressure transmitters, a quick-closing valve and pigging system, and a high-speed camera are used to acquire the data. The trends of the data with respect to input parameters are investigated. The performances of commonly used models are compared with liquid-holdup, pressure-gradient, and water-holdup experimental results. The observed wave patterns include stratified smooth and stratified wavy with 2D waves, 3D waves, roll waves, and atomization flow. The transitions between the flow patterns vary as a function of water cut. The trends of pressure gradient, liquid holdup, and water holdup with respect to vSg, vSL, and water cut are observed, and interpretations on the basis of physics are provided. The predictions of a transient multiphase-simulation software; the Tulsa University Fluid Flow Projects (TUFFP) unified model (Zhang et al. 2003), version 2012; Beggs and Brill (1973); Taitel and Dukler (1976); and Xiao et al. (1990) are compared with the acquired experimental data. The results from the transient multiphase-simulation software, Taitel and Dukler (1976), and Xiao et al. (1990) are in good agreement with experimental liquid-holdup and pressure-gradient data, but the three-phase water-holdup trends are not predicted well. The complicated nature of liquid/liquid interactions in three-phase low-liquid-loading flow causes greater uncertainties in predictions. The number of experimental three-phase data, especially with larger pipe diameters, is very limited. This paper provides comprehensive data for three-phase stratified flow for a 6-in.-ID pipe. In addition, the prediction performance of the commonly used predictive tools in the industry is provided.
Summary 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.
Summary 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.
Summary 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.
Summary Looped gas/liquid multiphase-flow pipelines are used by the oil and gas industry to reduce pressure drop and increase flow capacity. They can be installed alone as a flow splitter or combined in series to form a manifold. Application of looped lines is not unique to the petroleum industry; they are also applied in other industries such as nuclear and chemical. However, there has not yet been a comprehensive fundamental investigation of the flow behavior or predictive methods available for such systems because of the complexity involved with respect to process variables such as flow patterns, fluid properties, phase velocities, and pipe geometry. Uneven splitting of the gas and liquid phases between the two looped lines can cause malfunction of the downstream processing equipment; therefore, a total of 65 experiments at different flow conditions in a looped-lines system using different-diameter looped-line configurations are conducted in this study to investigate the pressure drop during uneven flow splitting. Most of the experiments are carried out with slug flow at the system inlet, while flow patterns such as slug flow, dispersed flow, and stratified flow are observed in the looped pipes. A computational algorithm is developed for predicting gas/liquid two-phase-flow splitting in the looped lines on the basis of energy minimization. The algorithm predicts the uneven splitting of the two phases and the corresponding pressure drop across the loop. Additionally, the model shows that maximum pressure drop occurs when there is equal splitting in the looped lines. Good agreements have been achieved between the measured and predicted flow splitting and pressure drop across the looped lines.
Summary 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.
Summary Subsea processing is an evolving technology in response to ultradeepwater hydrocarbon development and has the potential to become one of the most attractive methods in the oil industry to economically unlock hydrocarbon resources. The objective of this paper is to examine the features of subsea fluid-processing technologies and capabilities, and compare the advantages and disadvantages of different facility types. The advantage of subsea processing systems is that they allow fluids to be boosted from longer tieback distances. Constraints associated with subsea processing systems include operation efficiency, produced-water and sand-handling capabilities, and the system’s ability to handle hydrates/scale. In this paper, we reviewed the application of subsea systems in 12 deepwater fields and discussed the significance of each. Furthermore, future subsea-technology development and anticipated challenges are outlined in this paper. The significance of this study is to summarize the lessons learned from current available uses so that future decisions regarding the application of these subsea processing technologies can be made appropriately and efficiently.
Summary Exhaust plumes from generators, pumps, and compressors aboard offshore platforms pose a hazard to crew and equipment. Mitigation for exhaust-plume impingement has traditionally been achieved by locating the exhaust uptake away from sensitive areas of the platform by use of long horizontal duct runs, by use of a very tall exhaust stack (> 20 m), or by some combination of the two. These solutions result in an exhaust system that is complicated to design and that adds significant weight to the platform. A more-practical and -weight-efficient alternative exists in the form of plume cooling. Plume-cooling technology has been in use for more than 40 years on military ships for the purpose of infrared (IR) -signature suppression and for the protection of sensitive weapons and communications systems that would otherwise be damaged by hot impinging exhaust gases. The operating principles of a plume cooler for application to the offshore oil industry are the same as for a military ship. The use of a plume cooler allows for a more-compact and -lightweight exhaust, but, surprisingly, this technology has begun to be applied on offshore platforms only within the past couple of years. The authors of this paper have more than 28 years of combined experience in the design and manufacture of plume coolers for diesel and gas-turbine engines. In this paper, the authors present a typical plume-impingement problem aboard an offshore platform—an LM2500 gas-turbine generator (GTG) that is located centrally in close proximity to the helipad, derrick, and deck crane. By use of computer simulation tools that they have developed for plume-dispersion analyses on military ships, the authors present the predicted impingement impact of the baseline exhaust on areas of interest (AOIs) on the platform and the benefit of applying plume cooling. A comparison is also provided between the plume-cooling solution and the traditional solution of raising the exhaust-stack height, with weight being a main point of comparison.
Summary 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.
Summary Carbon dioxide (CO2) capture and usage (CCU) is currently a global topical issue, and is viewed as one possible route to reduction of CO2 concentrations in the atmosphere. The core issues facing the world in current times--development, economy, and environment--are identified as being dependent on the provision of clean, efficient, affordable, and reliable energy services. Currently, the world is highly dependent on fossil fuels for provision of energy services, and the amount of which renewable energies can sufficiently replace is minimal. The deployment of appropriate CO2-separation technologies for the processing of natural gas is viewed as an abatement measure toward global CO2-emissions reduction. Selection of the optimum technology among the several separation technologies for a particular separation need requires special attention to harness the economic and environmental benefits. The captured CO2 would also require appropriate disposal or usage so as to sequester or ’delay’ its re-entry into the atmosphere. These challenges of CCU--involving natural gas particularly during processing, which has become an area of intense research--shall be discussed in the paper with respect to the selected technique for CO2 capture. A typical natural-gas-production scenario in Nigeria shall be analyzed for potential CO2 capture. Further discussion shall be on the identification of the recovered CO2 gas-usage framework, such as CO2 flooding [in enhanced oil recovery (EOR)], for additional revenue generation, assessment of the CO2 savings, and the contribution to the clean development mechanism (CDM).
In this sixth article of the Oil and Gas Facilities Savvy Separator series, underperforming gas scrubbers are discussed, and a case study is used to illustrate how an inadequate sizing methodology hinders scrubber performance.
Summary The vast and diverse spread of the oil and gas pipeline infrastructure makes real-time monitoring of the entire network a very costly task. This topology has provided vandals and crude-oil thieves with the opportunity of tapping the pipelines and successfully stealing crude oil from them unhindered. Nigeria lost more than USD 11 billion to crude-oil theft and pipeline vandalization over a 4-year period (2007 to 2011). The increase in vandalization has led to the divestment of assets by some of these oil companies because it is no longer economical to continue operating the assets. Strategies used by the government and oil companies to tackle these challenges include the deployment of military personnel to these assets and also along their pipeline right of way (ROW). In spite of these attempts, the results show that the deployment of these personnel and the attendant cost have not reduced the quantity and frequency of oil theft because the deployment time to some of these locations also contributes to delay in the response of the security personnel. The deployment of dynamic pipeline-pressure profiles enables the determination of the onset of a leak or a loss of crude oil. This paper presents the deployment plan and communication architecture of the vertical take-off and landing (VTOL) type of unmanned air vehicles (UAVs) for pipeline monitoring. The pipeline network of the company is divided into wide area cells, and each cell is controlled from a facility. Low-power UAVs with directional antennas and long-range zoom cameras are deployed to provide real-time visual monitoring of the pipeline section whenever a pressure drip or any significant third-party activity is detected on a section of the pipeline. Security personnel can then be deployed to the pipeline section if vandal activity is detected. This solution has the capability of reducing crude-oil theft by providing accurate location data in a timely manner to the company with respect to the bunkering activity along its pipeline ROW and also enabling the timely deployment of personnel to contain the situation.
Summary 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.
Summary 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.
