Deepwater Operations Research Articles

Dynamic Simulation in Deep Water Enhances Operations From Design to Production

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30838, “Shell Appomattox Model-Based Operations From Design to Production: A Game Changer in Gulf of Mexico Deepwater Operation,” by Robert Tulalian, Shell, and Evan Keever and Ankur Rastogi, Kongsberg, prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. The complete paper discusses how large operations such as Appomattox in the Gulf of Mexico’s deepwater Norphlet formation can use an integrated dynamic simulation-based solution throughout the project life cycle to aid in design verification, operator training, startup support, and real-time surveillance. The authors write that their recommendations and findings can be applied to similar project implementation efforts elsewhere in the industry. Introduction The Appomattox development spans Mississippi Canyon Blocks 348, 391, 392, and 393. Peak production rates are estimated to be approximately 175,000 BOE/D, with water injection planned for the future to support reservoir pressures. Appomattox includes a combined cycle steam system, using process waste heat to generate steam. This steam can be used to drive a generator, providing extra power for the facility. The Appomattox facility can be seen in Fig. 1. A multipurpose dynamic simulator (MPDS) was developed to address the inherent complexities of the Appomattox system, providing a high-fidelity integrated model that simulates both top-sides and subsea process conditions. This model was integrated with the Appomattox control system and deployed in a setup to mimic the offshore control room, creating a realistic training environment for operators. The MPDS was completed over 1 year before first oil, providing ample time for operator training and other use cases such as distributed-control-system (DCS) checkout and engineering studies. Because of the success of the MPDS, the operator applied the existing Appomattox model to the operation phase through the creation of a real-time surveillance system (RTS). Connecting the process model to the facility’s historian by open-platform communications (OPC) enables the RTS to serve as a virtual copy of the live facility, mimicking process conditions in real time. This enables the RTS to serve as a platform for useful surveillance applications such as virtual flow metering, blockage detection, and equipment-performance monitoring. Process Model Development Once the decision to build an MPDS was made, the project team determined which systems would be included in the scope of the model as well as what data would be used for input and validation. Because the MPDS would be used for both engineering and operations use, most systems were included in the scope and modeled at high fidelity to maximize potential benefits.

Alternative configurations to optimize tension in the umbilical of a work class ROV performing ultra-deep-water operation

The utilization of ROV (Remotely Operated Vehicle) for subsea operation has been increasing in the past few years alongside the increasing use of subsea technologies in deep-water oil and gas activities and other maritime operations. While survey class ROVs have reached the deepest depth in the ocean, the work class ROVs are mostly limited to 3 km depth. For a work class ROV operating in deep waters, the excessive static tension due to self-weight of the ROV and its umbilical system leaves small room before the dynamic tension exceeds the safe working load of the umbilical. Snap loads can also exist in the low-tension area of the umbilical when the ROV system is under dynamic motions which can lead to a large tensile load in the line. Therefore, there is a need for a practical solution to ensure that the safe working load is not exceeded during ultra-deep-water operation.This study focuses in reducing the tension in the umbilical hence increasing the operational depth of a work class ROV from deep to ultra-deep waters. Three different configurations, namely the hook, hook & top floaters, and mid-depth hook are numerically investigated and compared with the conventional free-flying ROV configuration. Firstly, deep-water operation of a 3 km ROV system is simulated under combination of a real extreme vertical current profile and various irregular wave conditions. This shows negligible effect of the current profile on umbilical maximum tension.The study also shows that for 3 km ROV operation, the suggested hook configuration is sufficient to effectively reduce the tension load as well as reducing the possibility of snap in the umbilical. Using hook configuration in the umbilical has significant benefits in minimizing ROV motion and also filters out the destructive snap induced high frequency tension fluctuations in the umbilical. For 6 km operation, either hook & top floaters or mid-depth hook can be utilized whereas the mid-depth hook configuration provides a broader environmental operating window for ROV operation. However, installation of floaters on the umbilical to produce the mid-depth hook configuration increases the ROV offset.

Assessment of the Acoustic Reflectometry Technique to Detect Pipe Blockages

Abstract Flow assurance is an important aspect of deepwater pipeline design and operation since one of the critical issues is the eventual initiation and growth of hydrate or paraffin blockages under certain conditions. Another relevant problem is the incidence of inorganic scale deposition in oil well production tubes during operation. Offshore operators can obtain enormous benefits if information regarding the position and extent of an eventual blockage is available since mitigation measures can be optimized. This work deals with experimental and numerical simulations of an acoustic system to identify and measure blockages. The technique uses a short duration acoustic pulse that is injected into the pipe. When the pulse encounters an impedance discontinuity, a portion is reflected toward the acoustic source. The analysis of the measured signal reflections can provide valuable data related to the location and size of the blockages. An experimental setup with a steel pipe of 4 in. internal diameter and length of 100 m was developed to evaluate the suitability of the technique for gas pipelines. In parallel, finite element analyses were performed using the commercial software abaqus to simulate the same physical parameters. The experiments were numerically reproduced with good correlation proving the potential of the technique. Subsequently, a parametric study was carried out to examine the acoustic detection capability using different blockage types. Finally, a prototype of the acoustic reflectometry detection system was developed and tested in a full-scale onshore water-filled pipeline to show the feasibility of the method for detecting blockages.

Technology Focus: High-Pressure/High-Temperature (March 2021)

For the past several months, the rig count in North America has been slowly but steadily improving and some pockets of deepwater operations are finally showing some activity, especially in Central and South America and Africa, where interesting discoveries continue. Arctic operations also are picking up, though not in North America, where a new administration in the US is bringing some uncertainty to upstream operations. Looking at leasing activity in 2020, however, the operators on federal land seem to have built up a backlog, so the immediate consequences of recent executive action seem not to be significant, though they do set an important precedent. More significant seems to be the opposition to pipelines, which are the most-efficient and safest way to transport any form of bulk material, be it gas, liquid, or slurry. Even if the most-stretched targets of an energy transition become reality, the need for pipeline transport will remain, and even increase, if the gas transported is biogas and hydrogen, where much larger volumes must be transported for the same calorific value of natural gas. In my tenure as a reviewer for JPT, I had refrained from a materials-focused special simply because high-pressure/high-temperature (HP/HT) conferences and sessions seem to be dominated by them and I wanted to demonstrate a wider spectrum of the challenges of HP/HT operations. With the energy transition leading to the possibility of free hydrogen being introduced into the energy system outside of established chemical feedstock installations (which are all low-pressure), this is a good time to remind our industry (and the outside world) that vast experience exists in the oil and gas industry on the interaction of hydrogen and metal (at very high pressures), a challenge that is still not completely understood and that is still a large cause of pressure-vessel failures (e.g., in refineries). Also, if carbon dioxide is intended to be captured and contained in metal vessels, another set of metallurgical challenges emerges. This Technology Focus looks at two papers from Asia, where these challenges were discovered and mitigated, and one paper from Gulf of Mexico deepwater operations. Many learnings can be taken from these papers, and extremely costly and safety-critical failures and loss of containment can be avoided. Addressing technical risk, thorough and detailed front-end engineering is a cost-effective and cost-saving activity, and this applies especially for front-end corrosion engineering and testing, as we have seen from several megaprojects in the past where this was not done to the extent finally understood to have been required. So, I invite you all to understand and embrace the fact that sound and competent engineering, as well as communicating learnings across functions and industries, is the key enabler for future success in our stressed industry, and to use our engineering brainpower and imagination to bring those HP/HT projects currently deemed too expensive to develop within the realm of the current oil-price environment.

Vibration characteristics of marine riser groups considering the coupled action of cross-flow and in-line

Fluid-induced vibration (FIV) prediction is an important prerequisite work in wear and fatigue analysis of multi-wellhead marine risers in deepwater operation condition. A two-way fluid-structure coupling method (CFD/CSD) is used to establish a numerical model vibration of the marine riser groups, taking into account the interaction between two physical fields of fluid-structure, the combined effects of ocean eddy-induced force and wave-induced force. The model is solved numerically by ANSYS Workbench and Fluent software and verified preliminarily by a classical example in literature in which considering vibration response of a single riser. The effects of number, spacing, and arrangement of risers on the vibration response characteristics of marine riser groups are analyzed by established mode. It is found that with the increase of the number of risers, the vibration of the front risers is mainly cross-flow (CF), while the vibration of the rear risers is mainly in-line (IL). Therefore, the influence of incoming flow should be taken into account in the front risers, and the disturbance of wake should be taken into account in the rear risers. With the increase of the distance between risers, the interaction between risers groups affects CF and IL. The critical spacing of the interaction is between 3.5D and 4D. The arrangement of marine risers mainly affects the CF vibration of risers, especially the upstream and downstream risers. The research results can provide theoretical support for the design and vibration control of multi-wellhead marine risers.

Wind and current loads on a pipelaying crane vessel

Wind and current loads have a significant effect on crane vessel and pipelaying operations. This study analyzes a pipelaying crane vessel performing deep-water operations, and uses a computational fluid dynamics code to calculate the wind and current load and moment coefficients of the vessel during its operations. The simulation conditions are set to be identical to those of wind tunnel tests, and the crane vessel hull is divided into upper and lower parts, with the upper part influenced by the wind loads and the lower part influenced by the current loads. In this work, 3D hull models were constructed, and k-ε turbulence models were solved by the Reynolds-Averaged Navier–Stokes Equations. The wind and current loads on the hull model are obtained for 50 wind and current angle combinations. The simulation results are found to be in good agreement (within 10%) with the wind tunnel test results for most headings, verifying the feasibility of the numerical simulation method. Finally, the characteristics of the load coefficients are generalized.

Quantitative risk analysis on an FSO crude oil storage tank

The industry of oil and gas are blooming in a rapid rate as time goes by because of the massive use of fuel oil and natural gas in this age of time. However, as more fuel oil are produced the industry is moving away from onshore to offshore and towards the ultra-deep-water region, where vessel like FSOs are introduced. FSO are short for Floating Storage and Offloading which are vessels used in deep water operation. The FSO plays an important role in the business where a single disastrous incident will affect the industry and the company. The focus of the research will be on the FSO that holds million barrels of crude oil. In this work, fire risk analysis is used to assess the crude oil storage tank on a typical FSO as this is a relatively new mode in exploration and production (E&P) activity. By calculating the individual risk per annum (IRPA) and potential loss of life (PLL), methods are introduced to mitigate fire risk on FSOs. The results show that the level of failure is low and requires less action for the FSO crude oil storage tank to stay safe during operation in the offshore environment.

Economic and Risk Analysis to Deep Water Operations

The exploration and production (E&P) operations of oil and gas project in deep waters, is associated with risks. These risks affects return on investment if they are not identified and analyzed to reduce their impact on the project. This study seek to apply Discounted Cash Flow (DCF) analysis, Monte Carlo Simulation and Sensitivity analysis, to an existing field in the Niger Delta region in Nigeria, to ascertain the viability of deepwater project when it is affected by government fiscal terms and technical terms. Economic and risk models were developed to determine profitability indicators and risk associated with the project. Risk simulator software was used to carry out Monte Carlo simulation and the sensitivity analysis. Results obtained showed that the project was economically viable with a Net Present Value (NPV) of $1,621.8 million and Internal Rate of Return (IRR) of 34%. The Monte Carlo Simulation and the sensitivity analysis showed that the Contractor’s NPV and percentage take were most sensitive to tax (under the fiscal terms) with an range of $639.27 million for a variation of by +/- 10% and crude price (under the technical term). The model developed can easily be applied in investment selections and decision makers should make decision based on the outcome of both economic model (cash flow analysis) and the risk model (Monte Carlo Simulation).

Technology Focus: Drilling Innovation (February 2020)

Technology Focus Summer jobs working on drilling rigs in western Oklahoma and California in 1980 and ’81 were great adventures. High oil and gas demand meant major and independent operators used some of the latest, state-of-the-art rigs to probe deep into high-pressure reservoirs. Planning and executing wells back then was a manual process with experience, horsepower, pencil, and calculator. My adventures continued after I graduated from college in 1982. Ever-evolving drilling, completion, and subsurface technology characterized the years that followed. Fast forward to February 2020. “The more things change, the more they stay the same,” the old-timers might say. In many field locations today, old-school machinery and processes remain in place. However, we see artificial intelligence (AI), data analytics, machine learning, and related advancements transforming our industry. These developments have been headlines for several years now but will take more time to reach full fruition. Experts agree this is just the beginning. Jensen Huang, chief executive officer and founder of Nvidia, highlighted this during a CNBC interview in November. “We are at the beginning of the AI revolution, one of the most powerful technological forces of all time,” he said. “We’ve created the ability for computers to understand the code of human knowledge. All industries will be transformed.” Huang, an AI visionary, showed a 4D simulation of an unmanned Mars landing craft on final approach going from 12,000 mph to zero in 6 minutes. Such visionaries are also working in upstream exploration and production to achieve remarkable advancements. A focus on drilling innovation reveals no shortage of SPE papers that exemplify these exciting trends. Without exception, the featured articles reflect increased volumes of surface and downhole data that are being captured and analyzed to enable deep learning, improved efficiency, safety, and value. As noted in paper OTC 29487, oil and gas companies are creating layers of digital knowledge enabling a new generation of AI-driven applications. New insights into mitigation of drillstring vibration, well-control events, and rate-of-penetration optimization follow. Managed-pressure drilling remains a persistent trend that continues to evolve across onshore, offshore, and geographical boundaries, opening new frontiers once seen as out of reach. One need not look to outer space to imagine the extent of breakthroughs to come in the not-too-distant future. Recommended additional reading at OnePetro: www.onepetro.org. SPE/IADC 194535 Nitrogen-Cap Drilling: A Managed-Pressure-Drilling Alternative for Highly Fractured Carbonate Reservoirs by Alexey Podust, Tengizchevroil, et al. SPE 196166 Standardization: Successful Implementation of Driving Consistency in Deepwater Operations by Daniel A. Durey, Shell, et al. SPE 197942 Innovative Digital Well-Construction-Planning Solution Enhances Coherency and Efficiency of the Drilling-Design Process by Waldemar Szemat-Vielma, Schlumberger, et al.

Deep Water Oil & Gas: New Opportunities and Suggestions for Chinese Oil Companies

The rising production of Deepwater are reshaping the global market landscape. Global Deepwater production will account for 22% to 25% of international supply in 2035. The role of Deepwater is significant in the future. The oil companies have entered Deepwater fields extensively. New opportunities are emerging, and the number of tenders for deep water blocks is increasing. Deepwater terms are changed to attract more exploration investment to the sector. The efficiency of Deepwater operation has been greatly improved through project optimization and technological progress. Chinese oil company should participate in international competition and cooperation actively, extend and upgrade the whole offshore industry chain to seize the new opportunities.

Structural integrity of deepwater composite pipes under combined thermal and mechanical loading

Thermoplastic composite pipe (TCP) is an ideal candidate to replace traditional steel pipes in deepwater applications where high specific strengths and moduli and corrosion resistance are desirable. TCP consists of three layers: an inner thermoplastic liner; structural fibre-reinforced multi-ply laminate; and an outer thermoplastic liner. During deepwater operation the pipe is subjected to thermal gradient, arising from the mismatch between internal fluid and external ocean temperatures, in combination with mechanical loads. In the present work, a 3D finite element (FE) model is used to investigate structural integrity of TCP under combined pressures, tension and thermal gradient by considering yielding of isotropic liners and failure of the laminate at ply-level according to existing stress-based criteria. Different orientations of reinforcing fibres are investigated.

Experimental Investigation of Methane Hydrate Induction Time in the Presence of Cassava Peel as a Hydrate Inhibitor

The oil and gas industry faces numerous problems, from the exploration to the production phase. One of the most common problems faced by the industry is the formation of gas hydrates in the pipeline during the deep-water operation. The advancement of kinetic hydrate inhibitors (KHIs) has been rapid. However, as the natural degradation of conventional KHIs, such as polyvinylpyrrolidone (PVP) and polyvinylcaprolactam (PVCap), is challenging, there is a need to develop environmental-friendly KHIs with enhanced biodegradability to improve possible environmental risks. Thus, green inhibitors have been developed as a new class of KHIs. Research for enhancement of green hydrate inhibitors, as an alternative for existing low dosage hydrate inhibitors (LDHIs), has increased. In this paper, the effect of induction time with presence of cassava peels on the formation of methane hydrate was studied and compared with commercialized inhibitor, PVP. The performance of cassava peels as a kinetic hydrate inhibitor was investigated using high pressure micro differential scanning calorimetry (µ-DSC). For the induction time measurement, linear cooling ramps at a constant cooling rate of 0.5 K/min were used under isobaric conditions. Aqueous solutions of 0.5 wt % and 1.0 wt % of cassava peels were prepared and the induction time of methane hydrate formation in these solutions was measured at pressure ranges from 4.0 to 10.0 MPa. One of the characteristics to be a good kinetic inhibitor is the presence of hydroxyl functional group in inhibitors, which assist to form hydrogen bonds with water molecules, thus preventing hydrates formation. Fourier transform infrared (FTIR) analysis confirms the presence of hydroxyl groups in cassava peels with wavenumber value of 3370.68 cm−1. Cassava peel solution is observed to delay the induction times at all pressure settings and it is better at 1.0 wt % concentration. However, at lower pressures of 4 and 6 MPa, the performance is less effective when compared to a commercial inhibitor, PVP. At high pressures of 8 and 10 MPa, it can be seen that the performance is as effective as PVP. This research paper shows that cassava peels have high potential to be developed as a gas hydrate green kinetic inhibitor that can be applied for industry usage in the future.

Corrosion Behavior of Ni-Mo Alloys in CO2-Saturated Salinity Environment at Gas Hydrate Formation Temperatures

Gas hydrate formation and corrosion can cause serious safety and flow assurance problems in deep water environments. One aspect that has been given less attention is the corrosion behavior of materials in salinity environment where gas hydrate formation and CO2 (sweet) corrosion can simultaneously occur. This type of environment is common in oil and gas deep water environments. The aim of this work is to investigate the corrosion behavior of Ni-Mo alloy coatings in an environment containing salt and dissolved CO2 gas at gas hydrate formation temperature (5 oC). Even though materials exposed to deep water operations can still experience corrosion at gas hydrate temperatures (low temperatures), previous research have done similar studies in room or higher temperatures using other test materials. Ni-Mo coatings were selected as the test material due to its excellent corrosion resistance in aggressive environments and serves as a based material for many oil and gas materials. A specialty designed jacketed glass cell was used to conduct the immersion test. The immersion test solutions were sweet low-salinity (CO2 + 1 wt% salt + 5 oC) and sweet high-salinity (CO2 + ~24 wt% salt + 5 oC) test solutions, respectively. The as-deposited Ni-Mo alloy coating has the highest corrosion resistance of 33.28 kΩ cm2. The corrosion resistance dropped to 14.36 kΩ cm2 and 11.11 kΩ cm2 after 20 hrs of immersion in the sweet low-salinity and sweet high-salinity test solutions, respectively. From grazing incidence XRD, the (111) reflection peak of the Ni-Mo coating was depressed and broaden after immersion in both test solutions due to increase in oxide layer formation on the surface Ni-Mo coating. SEM revealed a cracked surface morphology after immersion in sweet high-salinity test solution and elemental analysis shows the presence of oxygen after immersion in both test solutions, which is an indication of the formation of oxygen containing compounds on the surface of the Ni-Mo coating. The oxygen content increased from 1.70 wt% after immersion in sweet low-salinity test solution to 2.37 wt% after immersion in sweet high-salinity test solution. This work provides a new corrosion design consideration and solution, and will help in designing models and corrosion prediction software used for simulating materials exposed to salinity environment where gas hydrate formation and CO2 corrosion can both occur. Incorporating this consideration into corrosion design of pipeline will improve offshore pipeline performance and serve as a baseline for initial corrosion allowance for materials exposed to this type of environment. Figure 1

Undrained shear strength evaluation for hydrate-bearing sediment overlying strata in the Shenhu area, northern South China Sea

The undrained shear strength of shallow strata is a critical parameter for safety design in deep-water operations. In situ piezocone penetration tests (CPTU) and laboratory experiments are performed at Site W18-19 in the Shenhu area, northern South China Sea, where China’s first marine hydrate exploitation operation is due to be located. The validation of the undrained shear strength prediction model based on CPTU parameters. Different laboratory tests, including pocket penetrometer, torvane, miniature vane and unconsolidated undrained triaxial tests, are employed to solve empirical cone coefficients by statistical and mathematical methods. Finally, an optimized model is proposed to describe the longitudinal distribution of undrained shear strength in calcareous clay strata in the Shenhu area. Research results reveal that average empirical cone coefficients based on total cone resistance, effective resistance, and excess-pore pressure are 13.8, 4.2 and 14.4, respectively. The undrained shear strength prediction model shows a good fit with the laboratory results only within specific intervals based on their compaction degree and gas-bearing conditions. The optimized prediction model in piecewise function format can be used to describe the longitudinal distribution of the undrained shear strength for calcareous clay within all depth intervals from the mud-line to the upper boundary of hydrate-bearing sediments (HBS). The optimized prediction result indicates that the effective cone resistance model is suitable for very soft to firm calcareous clays, the excess-pore pressure model can depict the undrained shear strength for firm to very stiff but gas-free clays, while the total cone resistance model is advantageous for evaluating the undrained shear strength for very stiff and gassy clays. The optimized model in piecewise function format can considerably improve the adaptability of empirical models for calcareous clay in the Shenhu area. These results are significant for safety evaluations of proposed hydrate exploitation projects.

Reservoir forming conditions and key exploration technologies of Lingshui 17-2 giant gas field in deepwater area of Qiongdongnan Basin

On September 15, 2014, China National Offshore Oil Co., Ltd announced that a high production of oil and gas flow of 1.6 × 106 m3/d was obtained in Well LS17-2-1 in deepwater area in northern South China Sea, which is the first great oil and gas discovery for self-run deepwater exploration in China sea areas, and a strategic breakthrough was made in natural gas exploration in deepwater area of Lingshui sag in Qiongdongnan Basin. Under the combined action of climax of international deepwater exploration, high oil prices, national demands of China, practical needs of exploration, breakthroughs in seismic exploration and testing technologies, innovations in geological cognition and breakthroughs in deepwater operation equipment, Lingshui 17-2 gas field is discovered. Among these factors, the innovation in reservoir forming geological cognition directly promotes the discovery. The quality of seismic data in the early time is poor, so key reservoir forming conditions such as effective source rocks, high quality reservoirs and oil-gas migration pathways are unable to be ascertained; with support of new seismic acquisition and processing technology, some researches show that Lingshui sag is a successive large and deep sag with an area of 5000 km2 and the maximum thickness of Cenozoic stratum of 13 km. In the Early Oligocene, the Lingshui sag was a semi-closed delta-estuarine environment, where the coal-measure and marine mudstones in Lower Oligocene Yacheng Formation were developed. The Lingshui sag is a sag with high temperature, and the bottom temperature of source rocks in Yacheng Formation can exceed 250 °C, but the simulation experiment of hydrocarbon generation at high temperature indicates that the main part of this set of source rock is still in the gas-generation window, with resources of nearly 1 trillion cubic meters, so the Lingshui sag is a hydrocarbon-rich generation sag. In the Neogene, the axial canyon channel from the Thu Bon River in Vietnam passed through the Lingshui sag, and five stages of secondary channels were developed in the axial canyon channel, where four types of reservoirs with excellent physical properties including the axial sand, lateral accretion sand, natural levee sand as well as erosion residual sand were developed, and lithologic traps or structural-lithologic traps were formed. The diapiric zone in the southern Lingshui sag connects deep source rocks in Yacheng Formation and shallow sandstones in the channels, and the migration pattern of natural gas is a T-type migration pattern, in other words, the natural gas generated from Yacheng Formation migrates vertically to the interior of the channel sandbody, and then migrates laterally in the channel reservoirs and forms the reservoirs. Innovations of geophysical exploration technologies for complicated geological conditions of deepwater areas are made, such as the detuning comprehensive quantitative amplitude hydrocarbon detection technology, which greatly improves the success rate of deepwater exploration; key technologies of deepwater safety exploratory well testing represented by the platform-dragged riser displacement technology are developed, which greatly reduces the drilling test cost. The above key exploration technologies provide a strong guarantee for the efficient exploration and development of Lingshui gas field.

Ethylene glycol injection for hydrate formation prevention in deepwater gas pipelines

The presence of hydrates in deepwater oil-gas-field operations is a fairly frequent issue. It is very important to have a hydrate management strategy for normal operation and while shutdown. The objectives of the work were to mitigate the hydrate formation in the deepwater operation conditions. This study analyzed the sensitivity of the hydrate compound formation process in flow line system with diameter 9.5" with a length of about 22 Km in deep water gas-field, based on actual condition and production rate assumption. Based on the simulation results for the actual production flow rate, hydrate is formed at a distance of about 17991 ft from the wellhead that is in the first segment of the well head to the Pipeline End Manifold (PLEM). For a higher production flow rate, hydrate formation occurs at a distance approaching the wellhead which is part of the first segment. This is because the temperature at the bottom of the deep-water is as low as 40 °F. The addition of MEG to prevent the formation of hydrate compounds was further investigated. Fluid flow modeling was performed under steady state with CH4 levels of about 87%, pressure of 1900 psia, 125 °F temperature and 85 MMSCFD production flow rate as the basic conditions. The data used in this research is taken from one of the deepsea gas field in Makassar Strait. Adding MEG dose of 0.175% mole, lowering the hydrate-forming temperature from 67.8 °F to 3.2 °F. Similarly, for increasing MEG doses, the greater the decrease in hydrate formation temperature. The addition of MEG dose of 0.175% mole at each production flow rate gives different working fluid temperature with hydrate formation temperature of 5.5 °F to 18 °F, so it is safe from the risk of hydrate formation.

Technology Focus: Well Integrity (January 2019)

Technology Focus Since the beginning of deepwater operations, hydrocarbons in the riser, especially natural gas, have been a plague to the oil and gas industry. The reports of gas-in-riser-related accidents are many, including deaths, blowouts, damage to multimillion-dollar facilities, collapsing risers, and environmental effects. Most infamous was the Deepwater Horizon blowout. If there had been any timely means of detecting the gas coming up the riser, all of these events could have been avoided easily by closing the blowout preventer. Since the 1980s, many technical works have focused on improving the ability to detect hydrocarbons inside the riser and safely remove them from the system. This trend gained extra momentum with the advent of systems such as riser-gas handlers and managed-pressure drilling. One very important recent development in terms of research on gas in risers is happening at Louisiana State University (LSU). LSU was awarded a $4.91 million grant by the Gulf Research Program, an independent science-based program managed by the National Academy of Sciences. The 3-year project, currently under way, will use an actual well at the LSU Petroleum Engineering Research and Technology Transfer Laboratory to be recompleted with modern distributed instrumentation in combination with other laboratory-scale experiments being performed at LSU and project partners at Texas A&M University. The experimental data will be very important in verifying the theoretical parts of the project. Faculty members of both institutions will conduct the research studies. This project is expected not only to bring scientific and technical dividends, but also to develop competence and expertise of the personnel involved with the project. Furthermore, it will provide LSU with research facilities that may be used in other related full-scale projects and training of industry personnel in the prevention and controlling of gas-in-riser events. Recommended additional reading at OnePetro: www.onepetro.org. OTC 27242 Mitigating Gas-in-Riser Rapid Unloading for Deepwater Dual-Gradient Well Control by Zhaoguang Yuan, Schlumberger, et al. SPE 180292 Mathematical Modeling of Gas in Riser by Ulf Jakob Flø Aarsnes, IRIS/DrillWell, et al. SPE/IADC 189403 Well Integrity: Next Developments by Bjorn Brechan, Norwegian University of Science and Technology, et al.

Effect of surfactant chemistry on drilling mud performance

Drilling muds used in deepwater operations experience large variations in temperature, as well as pressure, when flowing through the different geometric conduits that are; the drill string, openhole (casing) - riser annuli present when drilling offshore. They behave as viscoelastic mixtures due to the suspension- and emulsion-dispersions used in their preparation. As a consequence, they display liquid-like and solid-like flow properties depending on the time scale of deformation they are subjected to. In addition to rate of deformation, environmental conditions such as temperature, and to a lesser extent pressure, are known to affect their rheological behavior.Nonionic surfactants are commonly used upstream in the stabilization of emulsions in drilling fluids, and in some instances as wetting agents. Inversion of pure emulsions systems stabilized by nonionic surfactants, from one type to another, as a result of temperature changes has been investigated and finds great application in the food and chemical industries.In this study, assessment of phase inversion occurrence in drilling muds, as well as resulting changes in their rheology was experimentally investigated at temperatures ranging from 0 to 90. Water- (WBM) and oil-based muds (OBM) samples were prepared using nonionic and ionic surfactants. Effect of surfactant nature and dispersed phase volume fraction on fluid loss properties of the different mud samples was equally carried at room temperature.Phase inversion of WBM samples stabilized by nonionic polyoxyethylene oleyl ether surfactants was observed for the range of conditions covered in the experimental investigation. Differences in flow behavior and apparent viscosity of the sample, as a result of inversion from one mud type to another, was equally noted.On one hand, the results underscored the importance of assessing potential application of nonionic surfactants to induce phase inversion in drilling fluids used for offshore operations. On the other hand, setbacks observed in the use of complex fluids for offshore drilling could possibly be accounted by the unknown occurrence of this phenomenon.

Composite risers for deep waters using a numerical modelling approach

There has been an increase in the application of composite structures in the oil and gas industry over the past four decades. This is due to more technological advancement and an increase in demand for the oil and gas. This trend has led to offshore exploration to transit from shallow water to deep water operations. Thus the need for more lightweight composite structures to reduce the deck loads and enable ease of operation. Composite risers are important as the properties of composite materials can be harnessed to improve riser performance and weight. This will enhance the development of deep water hydrocarbon reservoirs. In this paper, numerical stress analysis of composite offshore risers for deep water applications is carried out. ANSYS ACP is used for the finite element modelling of the composite riser for six load cases. From the design, recommendations for the design of the composite riser are made.

Contemporary Issues of Climate Change on Oil and Gas Industry Operations

The reality of climate change as an aspect of broader global and environmental change attributable to either natural or anthropogenic cause is becoming more evident. Equally, energy, chiefly oil and gas is not only a major climate change inducer via greenhouse gas emissions anymore, but also a victim of the impacts therein. As such, this paper examines the impact of recorded changes in climatic variables on oil and gas operations categorized into upstream, midstream and downstream operations representing exploration and production, transportation, along with processing and distribution respectively. Identified changes in weather events primarily driven by general climate change having significant impact on oil and gas operations and infrastructure include increasing temperature, increasing flooding, storm surges, sea level rise, coastal erosion, intense winds and waves, drought/water shortage and subsidence/landslides/mudslides and they all pose tremendous risk to onshore and offshore (shallow and deep water) operations and installations. Several adaptation measures are currently being implemented some of which are already yielding positive results. Adaptation measures are being complemented with mitigation strategies as long-term solutions. Sadly, most developing oil producing countries are still way behind in adopting various existing adaptation measures and implementing mitigative strategies due to prevalent low capacity.