Offshore Oil Fields Research Articles

Research on the Calculation Method for the Wellbore Temperature of Hot Nitrogen Gas Circulation Wax Removal and Plug Removal in Offshore Oil Fields

The problem of wax deposition widely exists in offshore oil fields; waxing of the oil tubing will lead to a reduction in the cross-sectional area of the flow and, in serious cases, the flow path will be blocked, causing the well to stop production. In order to cope with this problem, a thermal dynamic wax removal method has emerged in recent years that utilizes hot nitrogen gas circulation between the oil tube and annulus to raise the temperature of the oil tube to achieve the purpose of wax removal and plug removal and is quick and easy to operate. Unlike conventional wellbore temperature calculation methods, the wellbore temperature field under hot nitrogen circulation conditions is influenced both by the reservoir temperature gradient and the hot nitrogen injection temperature, injection pressure, and injection rate. In this paper, a temperature calculation model for a wellbore considering both annulus injection temperature and tubing temperature and their interactions is modeled, which can consider the effects of different hot nitrogen injection temperatures, injection rates, and injection pressures. The model is used to calculate the temperature distribution for different injection parameters in order to ensure that the tubing temperature is higher than the wax precipitation temperature and that the annulus temperature is not higher than the maximum temperature resistance of the rubber in the packer. The study provides a design method for wax removal and plug removal with hot nitrogen gas circulation.

Improving the Sealing Efficiency of Compressor Cylinders of Gas Engine Compressors in the System of Gas-Lift Production of Offshore Fields

An increase in the efficiency of gland seals in compressor cylinders with cast iron rings pressed against the contact surface of the piston rod using a steel spring in reciprocating compressors used in offshore oil and gas-condensate fields for gas-lift oil production systems is considered. Studies of a gas engine reciprocating compressor working directly on the operating gas-lift system have shown that in order to increase the time of normal operation of gland seals, it is necessary to adjust the clearance using lubricant up to 0.1 mm. After increasing the spring stiffness, the serviceability and number of working hours of the gland seal increased twofold, from 850 to 1700 h.

A New Approach for Production Prediction in Onshore and Offshore Tight Oil Reservoir

Rapid technological advances have accelerated offshore and onshore tight oil extraction to meet growing energy demand. Reliable tools to carry out production prediction are essential for development of unconventional reservoirs. The existed tri-linear analytical solutions are verified to be versatile enough to capture fundamental flow mechanisms and make accurate production predictions. However, these solutions are obtained in Laplace space with the Laplace transform and numerical inversion, which may lead to uncertainty in the solution. In this paper, a general analytical solution is derived in real-time space through integral transform and average pressure substitution. Namely, the partial differential equations describing subsurface fluid flow are firstly triple-integrated and then the obtained volume average pressure are replaced with the rate-dependent expressions. Furthermore, the ordinary differential equations related to oil rate are solved analytically in real-time space. To validate our model, this derived solution is verified against two numerical models constructed with two typical physical configurations. The great match indicates the accuracy and applicability of the analytical solution. According to the developed workflow, two field cases including offshore and onshore tight oilfield data are selected for history matching and production prediction. This new approach not only makes the obtained solution more simplified, but also helps field engineers diagnose flow patterns more quickly to better optimize production schemes.

Design Methodology for a Low-Shear Rotating Swirler

The tubular dynamic hydrocyclone (TDH) holds great potential for the pre-deoiling of offshore oil platforms. However, the shear and turbulence in the flow field can cause the oil droplets, the dispersed phase in water, to break up when the swirling flow is produced by the swirler. A design method is proposed for the low-shear rotary swirler (LSRS) of TDH, the aim of which is to reduce the shear force and local turbulence during the fluid forming swirling flow. The blade setting angle of the LSRS is calculated based on the relative velocity vector between the fluid and the swirler. The distribution characteristics of the tangential velocity and turbulence in the TDH with LSRS are simulated by Computational Fluid Dynamics (CFD). The maximum stable droplet diameter is analyzed. The results show that the shear stress and turbulence energy dissipation rates are reduced by 74.6% and 68.5%, respectively, and that the stable droplet diameter is increased by more than 60%, compared to the conventional rotating swirler. In addition, a TDH prototype with LSRS was tested in an offshore oil field by continuous operation for more than 36 h. The average separation efficiency was 83%, and the average underflow oil concentration was 27 mg/L. The research also found that the drastic changes in the tangential velocity along the axial direction were critical to shear. Moreover, the results make up for the deficiency of the spatial variation of the tangential velocity in the dynamic cyclone separator.

A comparison of gas-liquid two-phase flow behaviors between two offshore pipeline-riser systems with different geometric parameters: From view of flow pattern identification

The accuracy of data-driven flow pattern identification in gas-liquid two-phase flow depends on the quality of training data. If a high similarity of input parameters exists between the training and the application conditions, then, the trained identification model would be applicable. Aiming at pipeline-riser systems in offshore oil and gas fields, a comparative study of different laboratorial two-phase flow loops with different geometric parameters is performed. Statistical parameters commonly used for flow pattern identification are examined. Similarities and differences of parameter distribution in the feature domain are discussed. By analyzing the mean and amplitude scatter distributions, the feature region divisions for identification are determined. First through conditional judgment, and then through LS-SVM recognition, the identification model is constructed. The shortest sample length for effective identification of each flow pattern is analyzed through the relationship between the identification accuracy and the sample length. The typical severe slugging could be easily identified under different pipe geometry conditions even when the sample length is 1 s. The identification accuracies of oscillation, irregular and stable flow patterns vary under different application conditions.

Influence of metallurgical factors on the hydrogen induced cracking of carbon steel wires in H2S-containing environments

Flexible pipes armor wires used in offshore oil and gas fields can corrode if water and acid gases, such as H2S, build up in the annulus. Such an environment may provide the conditions for hydrogen-induced cracking (HIC) depending on the corrosive solution composition and the metallurgical characteristics of the armor wire, such as microstructure and microhardness. The critical zones of HIC incidence were investigated for tensile and pressure armor wires with carbon content of 0.7 and 0.3 wt% C, respectively. Results were obtained through immersion testing and hydrogen permeation measurements in near neutral substitute ocean water (solution A) and standard acid solution (solution B) at ambient temperature bubbled with a gas mixture (1 % H2S + 99 % N2). Scanning electron microscope (SEM) and computed tomography (CT) evidenced the microstructure and microhardness features associated to crack morphology and location. According to the results, the increase of carbon content in cold drawn steels promoted the accumulation of hydrogen mainly in regions of high microhardness, inducing a high density of cracks in a stepwise cracking (SWC) propagation. This indicates that the driving force for HIC was associated with metallurgical factors, such as microhardness, the presence of hydrogen trapping sites of high energy, dislocations and ferrite/cementite morphology and distribution, occurring even in the absence of non-metallic inclusions. Additionally, environmental conditions, such as the low pH found in solution B, increased the criticality of HIC. Both materials presented a crack sensitivity ratio (CSR) that grew over time in solution B, but no cracks were observed in the pressure armor wire tested in solution A. Hydrogen permeation curves were delayed for both tested armor wires in solution A due to its near neutral pH characteristic. Hydrogen diffusivity (Deff) of the tensile armor wire was lower than the pressure armor wire, indicating the presence of a higher density of hydrogen trapping sites in a harder and elongated pearlite.

TECHNICAL REQUIREMENTS FOR FIBERGLASS HULLS IN OFFSHORE OIL AND GAS OPERATIONS

This article notes the operation of auxiliary vessels in harsh, aggressive offshore oil and gas field conditions. These vessels transport the necessary equipment and tools, etc. to the oil and gas field trestles. That is, there is wear and tear and ageing of hull structures after a long period of time. As a rule, ship hull structures are made of steel and metals of a certain grade. The aggressive sea water causes corrosion which leads to hull deterioration and gradual destruction. To prevent corrosion, fiberglass material or fiberglass plastics are used. This material is known to be the basic construction material created by scientists and technologists. Fiberglass material, as described in the article, must meet the technical requirements for the operation of auxiliary vessels with hulls made of this material. It is noted that fiberglass material is used in order to save metal and steel. Which is of scientific and practical importance. This material is also used in other areas of engineering and technology. The weight of the material is relatively small compared to metal and steel. According to the technical requirements for the operation of auxiliary vessels, an example is given for increasing the strength of fiberglass material by treatment with a reinforcing agent. The hulls of vessels when transporting the necessary equipment and tools to the trestles of offshore oil and gas fields, are subjected to shock loads of sea waves, as well as the load from the weight of the transported cargo. Consequently, the article notes that hull structures made of fiberglass material, can be one or two or three layers. This gives the ship's hull shock resistance. In this case, the requirement for durability during operation of auxiliary vessels is observed. The scheme of these hulls in cross-sectional view is given. It is noted that repair of hulls made of fiberglass material is easier in comparison with other materials. Deck coating is described, which increases the strength of the running surface of the deck and ensures its durability and carrying capacity. In general, the article describes all the technical requirements for fiberglass hulls and their advantages over materials like metals and steel. It is said that the operation of auxiliary vessels with fiberglass hulls in adverse oil and gas field conditions with the technical requirements for these hulls described in the article, will be of high quality and economical. Keywords: technical requirements, vessel hulls, offshore oil and gas field conditions, fiberglass material.

Study on Fracturing Parameters Optimization of Horizontal Wells in Low-Permeability Reservoirs in South China Sea

The oil and gas resources in the deep Paleogene system of the South China Sea are abundant. However, due to its poor reservoir physical properties and strong heterogeneity, the deep Paleogene system needs to be commercially exploited by hydraulic fracturing technology. In view of the challenges of offshore low-permeability reservoirs, large-scale fracturing is not allowed because of the limited operation sites and complex string structure. Taking the H oilfield in the South China Sea as the target, based on the concept of the integration of geologic and engineering techniques, parameters such as the number of fracturing stages and the fracture length were optimized by a numerical simulation, and a study on the slurry rate and fracturing scale was carried out based on the type of fracturing and the pipe string structure. The results show that multistage fracturing technology is available in low-permeability offshore oil fields. It is suggested to adopt networking fracturing technology with a “slick water + high slurry rate” framework. A higher rate is recommended, and the fracturing scale of each stage should be 50 m3 of the sands and 700 m3 of the fluids. This research provides a new model for offshore low-permeability oilfield development.

Application of Integrated Evaluation on Seawater Injection to Improve Injectivity for Carbonate Reservoir in Offshore Oilfield

Seawater flooding is popular for carbonate reservoirs in offshore oilfields and seawater is sometimes the unique choice of injection water source due to the lack of surface water supply. Seawater is injected into reservoirs to maintain reservoir pressure after water treatment for technically and economically effective field development. Uneven injection and production in B oilfield caused unbalance of pressure distribution and poor injection performance. It is essential to improve the injectivity of single well to a satisfied level through a integrated workflow on the basis of performance analysis, brine compatibility study, core flooding experiment, strategy and solution optimization. In this paper, the injection status has been analyzed and the decisive impacting factors were given including formation properties, stimulation activity, the brines compatibility and pre-treatment of injection water, which play a very important role in injection performance sustainability as the seawater injection continues. Scale modelling was done with formation water, mud filtrate, injection water and stimulation fluid for self-scaling assessment. Mixing experiment of two of the brines of four introduced at either atmospheric or reservoir condition. Core flooding experiment was carried out with formation water and filtered injection water after critical velocity for core flooding is confirmed. Then the injectivity for each wells have been analyzed at different locations of the reservoir with different formation properties, solutions have been subsequently put forward and the improvement on injectivity of injectors before and after the stimulation or even re-stimulation and the effect of cleanup after the stimulation was also compared. It was concluded that injectivity could be enhanced through stimulation and the cleanup after stimulation and the sulfate should be removed or reduced in the process of the pre-treatment of injection water from the remote terminal to ensure desirable water injection and production performance.

Preparation and Performance Evaluation of Quaternary Ammonium Cationic Clay Stabilizer for Oilfield Use

Acidizing is a crucial technique in the development of low permeability reservoirs in offshore oil fields. The introduction of acid into the formation can lead to the degradation of the clay mineral structure, causing the expansion and migration of clay particles that obstruct the flow of acid channels. The addition of a clay stabilizer with excellent properties can prevent the hydration and expansion of clay, as well as recover damage caused by long-term acidification, such as expansion, dispersion, and migration. To achieve this, the dendritic quaternary ammonium salt ZS-A was synthesized through a quaternization reaction, and subsequently used to develop the clay stabilizer ZSFP. In this study, the properties of clay stabilizer were investigated, including anti-swelling, acid and alkali resistance, water washing resistance, mudstone loss rate, and permeability retention. The results demonstrate that the ZSFP clay stabilizer performs well in terms of anti-swelling, acid-base compatibility, water washing resistance. This clay stabilizer can effectively reduce water-sensitive damage to the reservoir and protect it during acidizing operations.

Research on Prediction Model of Interlayer Leakage in Separate Injection Wells in Offshore Oilfields

In order to ensure effective layered water injection, it is of great significance to establish the functional relationship among the equivalent diameter of damage, leakage and pressure of sealing cylinder. In this paper, the experimental and numerical simulation experiments were carried out to study the relationship between gap flow rate, pressure drop and equivalent diameter of sealing cylinder under the conditions of uniform corrosion, fracture non-uniformity and random groove non-uniform distribution and scratches in different tubing, equivalent diameters and gap widths. Through a lot of data analysis, the relationship between the damage state and the leakage quantity is established and evaluated by physical simulation test. The research shows that the error between the established model function relation and the test data is no more than 10%. By simulating the damage condition of the shock sealing cylinder and quantitatively detecting the defect of the sealing cylinder, the model function relation can well predict the corresponding damage situation. Therefore, this model function can be used to solve sealing cylinder inspection problem, so as to judge the seal defect and leakage quantity which is independent of the experience of the person in charge of the site and able to use the data as a basis for judgment. This research provides a new technology for the effective prediction of the damage of sealing cylinder, and provides theoretical guidance for selecting matching sealing tools and realizing layered mining.

Machine-Learning Algorithms Optimize Drilling-Center Locations Offshore

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 211772, “Optimizing Future Drilling-Center Locations Using Advanced Analytics and Machine-Learning Algorithms Offshore Abu Dhabi,” by Rail Salimov, Benoit Jaffres, and Jamal Alblooshi, ADNOC, et al. The paper has not been peer reviewed. _ Long-term development planning requires infill drilling. Because of the limited number of slots in the offshore environment, new drilling centers (wellhead towers) are required. Optimized location of drilling centers can play a major role in reducing drilling expenses. Two main challenges related to wellhead-tower placement are discussed in the complete paper: first, where to place future drilling centers based on subsurface coordinates and drilling constraints; and second, how to allocate dozens of subsurface targets to multiple drilling centers. The drilling-center placement optimization algorithm developed by the authors is based on multiple optimization parameters related to well cost. Introduction To finalize well trajectories, and thus best manage well costs, before the drilling phase, the following detailed analyses are required: - Evaluation of horizontal trajectory in terms of landing point and total depth - Optimization of horizontal drain length - Optimization of the horizontal drain length in the best oil-bearing zone - Torque-and-drag evaluation - Anticollision assessment - Selection of optimal completion accessories However, for most giant offshore fields with complex plans, hundreds or even thousands of infill developments are required. Definition of optimal locations and allocations of wells to drilling centers will require multiple iterations of already tedious work. An alternative methodology is described in the complete paper that allows finalization of future facility placement with the use of open-source machine-programming tools and applied mathematics. The presented methodology was deployed successfully on two major offshore fields where current production is connected through wellhead towers. Evolution of the development plan and the ramp-up of production means that additional drilling is planned during the next 10 years. Approximately 100–150 development wells are planned to be drilled from yet-to-be-constructed wellhead towers. One of the main challenges in achieving cost efficiency is effective placement of the new towers to minimize the total drain length of all development wells. The methodology covers the two most important aspects of facility construction that play vital roles in optimization of capital investment in facility expansions of offshore oil and gas fields. These aspects are optimized allocation of future wells to drilling centers and placement of those drilling centers.

Technology Focus: Sand Management (October 2023)

As drilling and completion activity resumes post-pandemic, the sand-control market faces several logistical challenges. Inflation and supply-chain interruption concerns are expected to continue into 2024 because of high volatility in raw material pricing amplified by geopolitical tensions in Europe and the South China Sea. As oil price strengthens, consumer preferences shift and more operators investigate newer technology and focus more on performance than price. Despite these factors, the fundamentals of sand control and sand management remain the same. As more-challenging reservoirs are being developed and new difficulties arise, however, more engineers are questioning the conventional sand-control aperture-sizing wisdom. Any sand-control effort aims to manage solids production while creating the fewest restrictions to fluid flow. To assure that sand-control efforts meet these goals throughout the life cycle of the wells, engineers must design them in a way that can withstand the forces of nature, doesn’t erode with high and localized flow, doesn’t corrode with the harshness of produced fluid, and doesn’t mechanically deform during installation and life-cycle loads. If you are interested in diving into these design processes, paper IPTC 21158 provides insight. With the higher adaptation of flow-control devices in recent years to improve flow segmentation and reduce the premature failure of sand control because of highly localized flow, flow-control-device implementation is becoming an integral part of sand-management strategy. More papers every year discuss the design process and field implementation of various kinds of flow-control devices along with sand controls. Paper SPE 210299 provides good insight into some of the field challenges and results of implementing flow-control devices with sand control. As always, monitoring for sand and solid production is key in any sand-management effort to assure the integrity of the system and maintain the containment of the fluids. In the past year, several papers focused on monitoring, including discussions of new technologies and presentations of field case studies. Paper IPTC 22989 is among the interesting papers in this subject. Recommended additional reading at OnePetro: www.onepetro.org. IPTC 21223 Lesson Learned From First Application of Openhole Standalone Screen With Autonomous Inflow Control Devices in Oil Field Offshore East Malaysia by Catherine Ye Tang, Petronas, et al. SPE 210128 Erosion-Resistant Sand Screen: Development and Deployment by Antonio Lazo, Chevron, et al. SPE 208162 Prediction of Threshold Sand Rates From Acoustic Monitors Using Artificial Intelligence by Ronald E. Vieira, University of Tulsa, et al.

Spatial distribution, source apportionment, and assessment of marine water quality parameters in the Bohai Sea, China

A two–year (2020−2021) survey dataset of six water quality parameters (pH, dissolved oxygen (DO), chemical oxygen demand (COD), dissolved inorganic nitrogen (DIN), soluble reactive phosphate (SRP), and petroleum pollutants) was used to investigate their spatial distribution in the Bohai Sea and quantify their potential sources. There were significant differences in spatial distribution of the parameters. High concentrations of COD, DIN and SRP were found in three bays, with terrestrial input being the main pollution source. Phosphorus–limiting conditions were present in the Bohai Sea. High petroleum pollutant concentrations were identified in port areas, offshore oilfields, and adjacent areas. The pH was above the global oceanic average and there were no signs of acidification. The contribution of the mixed terrestrial inputs, maritime transportation, and offshore oil exploitation sources, oceanic and associated biotic sources, and seawater–atmosphere exchange and atmospheric deposition sources to water quality were 63.4 %, 8.0 %, and 28.6 %, respectively.

Towards a low-carbon future for offshore oil and gas industry: A smart integrated energy management system with floating wind turbines and gas turbines

Decarbonizing offshore oil and gas fields is crucial in the global fight against climate change. To achieve this objective, the offshore oil and gas industry has embraced innovative energy systems, including microgrids that seamlessly integrate renewable energy sources like floating wind turbines. This study presents a comprehensive investigation into an integrated energy management system for an offshore microgrid, encompassing three platforms and a floating wind farm, along with green hydrogen production and storage facilities.The operational decision-making process for such a complex microgrid, involving numerous assets, presents notable challenges. To address this, a sophisticated smart management system is employed, enabling efficient optimization with advanced forecasting capabilities to identify the most cost-effective and environmentally friendly version of the microgrid's operation. To overcome the intricacies of optimization and computational constraints, a novel hybrid optimization approach, with a platform-centric strategy, is utilized. Leveraging real-world operational data, the study harnesses an innovative online optimization method fortified with state-of-the-art AI algorithms.The results of the optimization are benchmarked against a rule-based operation, wherein no formal optimization occurs, but the most economically viable decisions are made. The findings underscore the effectiveness of the developed optimization method, leading to a significant 16% reduction in operational costs and carbon-based emissions compared to the rule-based approach.This study effectively demonstrates the real-world applicability of the developed method by applying and testing the smart management system on an actual offshore platform with minimal simplifications. The investigation provides valuable evidence of the method's adaptability to complex operational scenarios, highlighting its potential for practical implementation in the offshore oil and gas industry.

Impacts of sea-access roads on wetland landscape dynamics in the Yellow River Delta front

The coevolution between oilfield development and deltaic wetlands is critical for ensuring environmental sustainability in mega-deltas. In the Yellow River Delta (YRD), the construction of offshore artificial islands and their sea-access roads (SARs) in delta fronts, providing accommodation for oilfields development of oilfields influences the evolution of adjacent wetland landscapes. This study utilized the threshold segmentation method based on MNDWI and the object-oriented random forest algorithm to extract the shoreline and classify typical wetland vegetation in the study area. It also analysed the impact of SAR on the landscape dynamics of coastal wetlands from 2004 to 2020. The results show that the SAR significantly affected the local sediment transport and erosion and accretion patterns in its adjacent coast, which has gone through accretion-domination, erosion, and continuous accretion stages, with significant accretion and erosion on the north and south sides of the SAR, respectively. From 2004 to 2020, 13.74 km2 of new-born wetland was formed, and the vegetation dynamics in the study area transformed from primary succession to human-disturbed succession. Spartina alterniflora (S. alterniflora) grew rapidly from 4.15 km2 to 18.04 km2 during 2010–2016, showed an imbalanced distribution on both sides of the SAR. This research can provide references for the sustainable coevolution of offshore oilfields and coastal environments.

Technology Focus: Offshore Facilities (September 2023)

Today, if one looks out at the vast offshore oil fields of the Gulf of Mexico, Venezuela, Brazil, the North Sea, West Africa, and the Arabian Gulf, it is hard to imagine that, at some point, all that mass oil and gas production for our energy and transport needs will come to an end. So, what will take its place? We have dabbled with nuclear power, but that is potentially more harmful than a carbon-based energy source and, in most quarters, definitely less popular. Hydroelectric power stations were once the darling of the alternative energy brigade of the mid-20th century, but flooding fertile valleys, displacing whole populations, and adversely affecting fauna and flora has cost that option its environmentally friendly status. Besides, demands on fresh water in many parts of the world have added another dimension to the issue. As we moved into the 21st century, the landscape began to fill with wind farms and fields full of solar panels; significant gains in green energy were being made. But did that satisfy everyone? No, of course not. The Not In My Back Yard culture took effect, and protests against solar farms and wind turbines on land and near shore became as vociferous as those of the anti-nuclear and anti-oil groups. Does this mean that we have run out of alternatives? No, not yet, because there is still an abundant energy source all around us that does not necessarily need carbon in the equation. Green hydrogen (i.e., hydrogen produced through electrolysis using electricity generated from the likes of wind turbines and solar panels) is growing rapidly in popularity as a successor to hydrocarbon fuel. Hydrogen can be used in a fuel cell or burned in a turbine or internal combustion engine with the resulting exhaust being water vapor. Energy can be stored in the form of liquid hydrogen or piped from the source to the place of use. It is worth noting that hydrogen does have some issues, which, to be fair, have yet to be overcome. Hydrogen does have to be chilled significantly to be stored in liquid form and does have a tendency to permeate carbon steel. It is highly likely that, in the future, we will see a derivative of hydrogen in the form of ammonia that will become more prominent. Ammonia also can be used in a fuel cell to generate electricity and also can be used in a turbine or combustion engine. Ammonia has very similar physical properties to propane and is significantly easier to store and transport than hydrogen. On our route to Green Utopia, there are still some significant hurdles to overcome. Installing new offshore wind farms and laying new electricity cables to shore is expensive. There still must be improvement in green hydrogen storage and transport technology, and, if we are to branch down the ammonia path, there definitely has to be significant improvement in green ammonia production rates. Coming back to offshore oil and gas, much of the massive infrastructure of offshore platforms and pipelines is nearing the end of its production life. The original plan for the myriad of platforms and pipelines is to decommission, remove, and scrap. This original plan is flawed. Removal of platforms has the most negative environmental impact. The successful Rigs to Reefs plan in the US Gulf of Mexico offers a viable alternative, but full repurposing of platforms and pipelines is probably the best solution—a solution that could have a positive effect on the fledgling offshore wind-to-hydrogen (ammonia) industry. If we are to achieve the goals of significant carbon reduction this century, then a holistic approach to the environment must be considered. I hope that you enjoy this month’s selection of technical papers. Recommended additional reading at OnePetro: www.onepetro.org. OTC 30993 The Use of Offshore Wind To Reduce Greenhouse Gas Emissions in Offshore Hydrocarbon Production—A Case Study by David McLaurin, Intecsea, et al. SPE 205446 Feasibility of Repurposing Offshore Decommissioned Gas Rigs Into Fish Farms by Saptarshi Pal, University of Strathclyde, et al. SPE 205439 Initiatives in UK Offshore Decommissioning Following the Wood Review: Applicability for Decommissioning in Norway by Rune Vikane, University of Stavanger, et al.

Research on Lifting Technology for High Sand Content Wells in Offshore Oilfield

Research on Lifting Technology for High Sand Content Wells in Offshore Oilfield

Review of Offshore Chemical Flooding Field Applications and Key Lessons Learned

Summary This paper presents an overview of both current advancements and field applications of offshore chemical flooding technologies. Along with offshore oilfield development strategies that require the maximization of oil production in a short development cycle, chemical flooding can become a potential avenue to accelerate oil production in secondary oil recovery mode. This makes it different from onshore chemical flooding processes that mostly focus on enhanced oil recovery in mature or maturing reservoirs. The advancements in offshore chemical flooding field applications are reviewed and analyzed. By summarizing offshore application cases, the presented analysis also assesses the chemical formulations applied or studied and injection/production facilities required in offshore environments. The main technical challenges are also discussed for scaling up the applications on offshore platforms or floating production storage and offloading (FPSO) systems. The chemical flooding technologies reviewed include polymer flooding, surfactant-polymer (SP) flooding, and alkaline-surfactant-polymer (ASP) flooding. By assessing the technology readiness level of these technologies, this study presents their perspectives and practical relevance for offshore chemical flooding applications. It has been long realized that chemical flooding, especially polymer flooding, can improve oil recovery in offshore oil fields. The applications in Bohai Bay (China), Dalia (Angola), and Captain (North Sea) provide the know-how workflows for offshore polymer flooding from laboratory to full-field applications. It is feasible to implement offshore polymer injection either on a platform or in an FPSO system. It is recommended to implement polymer flooding at an early stage of reservoir development to maximize the investment in offshore facilities. By tuning the chemistry of polymer products, they can present very good compatibility with seawaters. Therefore, choosing a proper polymer is no longer a big issue for offshore polymer flooding. There are also some interesting findings reported on the development of novel surfactant chemistries for offshore applications. The outcome from a number of small-scale trials, including the single-well chemical tracer tests on surfactant, alkaline-surfactant (AS), and SP in offshore Malaysia, Abu Dhabi, Qatar, and South China Sea, provided valuable insights for the feasibility of chemical flooding in offshore environments. However, the technology readiness levels of surfactant-based chemical flooding processes are still low, partially due to their complex interactions with subsurface fluids and the lack of interest in producing residual oil from matured offshore reservoirs. Based on the lessons learned from offshore applications, it can be concluded that several major challenges still need to be overcome in terms of large well spacing, reservoir voidage, produced fluid treatment, and high operational expense to successfully scale up surfactant-based chemical flooding processes for offshore applications. Key Terms and Phrases offshore chemical flooding; polymer flooding; surfactant-based chemical flooding; offshore application cases; lessons learned

Time-Lapse 3D CSEM for Reservoir Monitoring Based on Rock Physics Simulation of the Wisting Oil Field Offshore Norway.

The marine controlled-source electromagnetic (CSEM) method has been used in different applications, such as oil and gas reservoir exploration, groundwater investigation, seawater intrusion studies and deep-sea mineral exploration. Recently, the utilization of the marine CSEM method has shifted from petroleum exploration to active monitoring due to increased environmental concerns related to hydrocarbon production. In this study, we utilize the various dynamic reservoir properties available through reservoir simulation of the Wisting field in the Norwegian part of the Barents Sea. In detail, we first developed geologically consistent rock physics models corresponding to reservoirs at different production phases, and then transformed them into resistivity models. The constructed resistivity models pertaining to different production phases can be used as input models for a finite difference time domain (FDTD) forward modeling workflow to simulate EM responses. This synthetic CSEM data can be studied and analyzed in the light of production-induced changes in the reservoir at different production phases. Our results demonstrate the ability of CSEM data to detect and capture production-induced changes in the fluid content of a producing hydrocarbon reservoir. The anomalous CSEM responses correlating to the reservoir resistivity change increase with the advance of the production phase, and a similar result is shown in anomalous transverse resistance (ATR) maps derived from the constructed resistivity models. Moreover, the responses at 30 Hz with a 3000 m offset resulted in the most pronounced anomalies at the Wisting reservoir. Hence, the method can effectively be used for production-monitoring purposes.