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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31940, “Repurposing Gulf of Mexico Oil and Gas Facilities for the Blue Economy,” by Roy Robinson, SPE, Excipio Energy; Georg Englemann, Diamond Infrastructure Development; and Kent Saterlee, Gulf Offshore Research Institute. The paper has not been peer reviewed. _ This synopsis presents portions of the results of a Department of Energy (DOE) study of the potential for repurposing legacy oil and gas facilities in the Gulf of Mexico (GOM) for uses in a blue economy. The study was limited and was designed to summarize practical options for repurposing. The conclusions list those areas in which further modeling or studies are warranted, with the objective of building an integrated modeling tool to assist companies, government agencies, and nongovernmental organizations in assessing benefits and risks of repurposing facilities. Scope Limits of the Repurposing Study The term “blue economy” is defined by the World Bank as a sustainable use of ocean resources for economic growth, improved livelihoods and jobs, and ocean ecosystem health. The study upon which the paper is based was confined to the repurposing of oil and gas facilities in the GOM, specifically platforms, wells, pipelines, and rights of way. Producing, idle, and abandoned assets were considered. The objective was to explore how leveraging these existing facilities can reduce the carbon load of offshore oil and gas production, speed the energy transition by tapping the tremendous energy potential of the ocean, reduce US dependence on imported seafood and minerals, and create secure long-term employment along the Gulf Coast. Energy Resource Potential and Definition In 2020, the US National Renewable Energy Laboratory (NREL), at the request of the Bureau of Ocean Energy Management (BOEM), produced a report on the renewable energy potential of the GOM. NREL divides resource assessments into gross and technical potential. “Gross” is intended to be the total available resource. “Technical” is based on NREL’s assessment of how much of the resource could be captured economically using proven technology. Details are included in the complete paper because the NREL/BOEM report has caused some questions to be raised by those reviewing the DOE study. The authors’ commentary on this report is detailed in the complete paper.
- Energy > Renewable > Ocean Energy (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.75)
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30709, “The Spar Platform: Transforming Deepwater Development,” by Anil Kumar Sablok and Tim Otis Weaver, TechnipFMC/Genesis, and John Edwin Halkyard, Deep Reach Technology, 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 spar is the only successful dry-tree solution for deepwater production that can operate successfully in the deepest fields and the most severe environments. Its deep draft results in natural periods outside the range of waves, which has led to its wide acceptance for different field scenarios. The complete paper is an extensive review of the evolution of spar designs, focusing on the progression of work that ultimately led to the application of a transformative concept to the oil industry. Introduction The spar can support a drilling rig as well as top-tensioned production risers in water depths thousands of feet greater than the water depth limit for a tension-leg platform (TLP). It is especially well equipped to support steel catenary risers (SCRs) using the pull-tube option, which allows the SCR to serve as a continuous welded steel containment for hydrocarbons from the seafloor to the topsides and protects the riser from vortex-induced vibration in the fastest part of the current profile. Broadly speaking, there are three configurations of spars: classic, truss, and cell, with the common feature being that the center of buoyancy is higher than center of gravity. Table 1 of the complete paper lists all oil and gas spar production platforms that have been installed at the time of writing, in chronological order of installation. The complete paper devotes several pages to the spar’s initial development, including the crucial role of Edward Horton, the inventor and designer behind the spar production and storage concept and the TLP, and some of his colleagues. Years of development and navigation of various design challenges culminated in the installation of the Neptune spar in 1996 on time and budget. After the installation and success of Neptune, several other classic-design spars were implemented. The riser system on the Neptune spar had two unique features: buoyancy cans provided the tension, and the riser passed through a point of high bending and potential wear at the keel. The keel joint was a straightforward design; a sleeve around the main riser pipe pro-vided wear protection and distributed the bending in the riser to two endpoints rather than at a single contact point.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 27183, “Current State of the One-Trip Multizone Sand-Control-Completion System and the Conundrum Faced in the Gulf of Mexico Lower Tertiary,” by Bruce Techentien, Tommy Grigsby, and Thomas Frosell, Halliburton, prepared for the 2016 Offshore Technology Conference, Houston, 2–5 May. The paper has not been peer reviewed. Copyright 2016 Offshore Technology Conference. Reproduced by permission. This paper provides perspective on the current state of multizone completion technology and issues encountered in the industry with developing a system that offers increased capabilities to meet the increasing challenges presented by the Lower Tertiary in the Gulf of Mexico (GOM). The multizone technology has proved to be an enabler for cost-efficient completions in the shallow-well environment and in the high-cost ultradeepwater environment requiring high-rate fracture-stimulation treatments. Lower Tertiary GOM The Lower Tertiary play is south and west of the Miocene area in the GOM and is, consequently, in deeper water. The Lower Tertiary is located approximately 175 miles offshore and is estimated at 80 miles wide and up to 300 miles long. Water depths are from 5,000 to 10,000 ft. Production targets are at depths of 10,000 to 30,000 ft subsea. The Tertiary trend is from 66 million to 38 million years old. Within the Lower Tertiary, the Lower Wilcox portion presents sheet to amalgamated-sheet sands considered to be part of a regional basin floor fan system. The Late Paleocene to Early Eocene (Wilcox equivalent) reservoirs are considered to be laterally extensive sheet sands that were deposited in deep water. These reservoirs are distributed across an area largely covered by the allochthonous Sigsbee salt canopy. It is this canopy that causes additional problems beyond merely the water depth and the well depth required to reach the reservoirs. These exploration plays depend on understanding the updip fluvial/deltaic stratigraphic architecture and the potential for partitioning of reservoir-quality sandstones across the depositional shelf into the slope and basin floor environments. The Lower Tertiary is estimated to contain up to 15 billion bbl of oil. Current State of Multizone Technology The Generation IV multizone system has been deployed successfully in the Lower Tertiary by multiple operators. To the authors’ knowledge, the multistage completion system and enhanced single-trip multizone fracturing systems had been installed in 10 wells as of the summer of 2015, with additional well installations planned. These systems are rated to 10,000 psi, and the enhanced single-trip multizone tool system offering an open-hole variant was installed in one five-zone completion.
- North America > United States (1.00)
- North America > Mexico (0.82)
- Phanerozoic > Cenozoic > Paleogene > Eocene (0.75)
- Phanerozoic > Cenozoic > Paleogene > Paleocene (0.55)
- North America > United States > Texas > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Mississippi > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Louisiana > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Gulf of Mexico > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- Well Completion > Sand Control (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Completion Selection and Design > Completion equipment (1.00)
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 26270, “A Case Study on the Implementation of an Acoustic Automatic Leak-Detection Sonar (ALDS) in the Gulf of Mexico and Its Application to Current and Future Brazilian Fields,” by G. Brown, S. Fasham, P. Tomlinson, and R. Crook, Sonardyne, prepared for the 2015 Offshore Technology Conference Brasil, Rio de Janeiro, 27–29 October. The paper has not been peer reviewed. The authors have developed an active acoustic automatic leak-detection sonar (ALDS) designed to detect hydrocarbon leaks (mono- and multiphase oil and gas) at significant ranges, allowing coverage of wide areas from a single sensor. The system’s single subsea sensor offers 360° continuous coverage, providing automatic, robust detection and localization of any leak, followed by an alert within tens of seconds of a leak developing. This paper provides a case study of an experimental program in which the system underwent trials in deep water (2000 m) at the Thunderhorse field in the US Gulf of Mexico (GOM). Introduction Most methods for detecting small leaks— for example, passive acoustic detectors that “listen” for the sound of a leak— have very limited range, which makes them suitable for applications such as pipeline surveys but not for wider field coverage. ALDS was developed to address the requirements for a system that can provide leak detection, including the ability to localize the leak, from a single point for a whole drill center. The typical requirements for such a system include Continuous and automatic detection and localization of oil and gas leaks across a drill center in both cluttered and uncluttered seabed regions with full 360° coverage Automatic elimination of transient acoustic targets to ensure low false-alarm rates Alarm on leaks within a few minutes of their initiation Ensuring that the system is reliable, networkable, compatible with subsea power-distribution requirements, and deployable across the full depth range of producing oil fields (4000 m) Principles of Operation The system is an active sonar that transmits ultrasonic pulses or “pings” at 70 kHz into the water and listens for reflections from objects within its field of view. This system is a phased-array processor capable of looking at returns from 360° of azimuth coverage simultaneously. Hydrocarbons have different acoustic properties from the surrounding seawater, notably a different acoustic impedance, which means that a sound wave encountering the boundary between seawater and hydrocarbon will be partially reflected and therefore “seen” by the sonar head. To determine if a reflection is from leaking hydrocarbons, the sonar map for each ping is compared with a reference map to see if the scene has changed. Data processing is then used to assess any changes from the reference map to see if they match the characteristics of a hydrocarbon leak or those of other objects such as remotely operated vehicles (ROVs), which might be operating within the ALDS field of view.
- North America > United States (1.00)
- North America > Mexico (0.82)
- South America > Brazil > Rio de Janeiro > Rio de Janeiro (0.24)
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 173647, ’Crown-Plug Pulling Performed as Riserless Light Well Intervention in the Gulf of Mexico - Overcoming the Challenges,’ by Garry Andrews and Angel Luviano, Welltec, prepared for the 2015 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 24-25 March. The paper has not been peer reviewed. In a riserless-light-well-intervention (RLWI) operation in the Gulf of Mexico (GOM), a crown plug failed to release. Slickline (SL) was the first method to be put into action. It was believed that repetitive attempts had broken the seal, resulting in saltwater inflow that had created hydrates. Twenty-five percent methanol/ethanol/ glycol was pumped while jarring, but eventually the contingency plan was activated. This consisted of a hydraulic stroking tool, which managed to remove the upper crown plug successfully and allowed the operation to continue. Introduction Electric line (e-line) has become the preferred method of intervention in the industry for a number of tasks with a growing array of lightweight solutions available to operators as an alternative to the heavy-duty approach of coiled tubing (CT) or the limited approach of SL. With the growing number of subsea wells and the greater efficiency of RLWI, logic dictates that the industry will see more and more e-line interventions for subsea wells in place of heavier interventions. The Hydraulic Stroking Tool The hydraulic stroking tool used during the operation presented here provides the necessary force for most mechanical-intervention jobs. It can push or pull a number of times, in spite of well depth or lateral deviation, during the same run. The particular tool used for this operation was designed to pull with a force of 33,000 lbf. Since this operation was completed, this hydraulic stroking tool has been redesigned to apply up to 60,000 lbf of axial force downhole with its bidirectional hydraulic ram. When plugs or stuck tools need to be pulled, specific tools and adapters can be attached to the actuator piston. All mechanical operations are run from the surface, and operations begin after the stroking tool has anchored itself. The design of this particular hydraulic stroking tool presents operators with a number of advantages, including the ability to perform mechanical interventions without “killing” the well. Additionally, the tool contains fail-safe measures that allow the system to default to a safety mode if any operational problem occurs. The hydraulic stroking tool can be used for a number of services, including opening and closing valves and sliding sleeves, retrieving and setting gas lift valves and plugs, setting straddle packers, and fishing operations. The tool is deployed stand-alone in vertical wells or conveyed by tractor and can provide services to both horizontal and extended-reach wells onshore and subsea.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.55)
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 25392, “Efficient Drilling of Ultra-HP/HT Wells in the Gulf of Thailand,” by Joy Araujo, Schlumberger; Keittipong Kaotun, PTTEP; and Panupun Dumrongthai and A. Adrian, Schlumberger, prepared for the 2014 Offshore Technology Conference, Houston, 5–8 May. The paper has not been peer reviewed. A new measurement-while-drilling (MWD) tool has been designed that can operate reliably at 200°C and 207 MPa, providing real-time direction and inclination surveys, azimuthal gamma ray, annular and internal pressure while drilling, and shock and vibration measurements. An operator in the Gulf of Thailand used this new MWD technology to drill wells in ultrahigh-pressure/high-temperature (HP/HT) reservoirs without the need to stop operation because of temperature limitations. Savings of ½ day per well have been achieved. Introduction Offshore drilling in the Gulf of Thailand increasingly challenges logging operations, with temperatures greater than 200°C. Hundreds of wells need to be drilled per year in this environment to fulfill long-term gas contracts. High efficiency is required in such a high-volume operation. Existing commercial MWD and logging-while-drilling (LWD) technologies are only capable of operating up to 175°C, with an inherent decrease in reliability at higher temperatures. In the planned ultra-HP/HT projects, the bottomhole assembly (BHA), which includes an MWD tool for directional and inclination measurements in real time, will be pulled out of the hole once the circulating temperature reaches 175°C. Then, a new BHA, without measurement tools, will be used to continue drilling to total depth. This “blind” drilling section could be several hundred meters long, introducing risks associated with well control and well collision. The main limiting factors in having MWD/LWD tools operating in these ultra-HP/HT environments are the downhole electronic components. Industry research studies show that plastic-encapsulated components have a life expectancy of approximately 1,000 hours at 150°C; this drops to less than 100 hours at 175°C. Ceramic-encapsulated components last longer at 175°C, but they are bigger and heavier than their plastic counterparts. Because space is restricted in these tools, the best compromise yields a mix of both ceramic- and plastic-encapsulated components. To find a solution to this industrywide problem, significant effort was made over the last decade to develop custom electronics that can withstand high downhole temperatures. The newly developed MWD tool equipped with these novel electronics components was deployed in ultra-HP/HT wells. In these wells, the real-time measurements were necessary to drill the sections with operating temperatures greater than 175°C. It allowed minimization of drilling risks, enabled proper well placement, and improved drilling efficiency by eliminating one run.
- Asia > Thailand > Gulf of Thailand > Nang Nuan Project (0.99)
- Asia > Thailand > Gulf of Thailand > Arthit Field (0.99)
- Asia > Thailand > Gulf of Thailand > Bongkot Field (0.89)
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164631, ’Overcoming Challenges While Acidizing Sandstone Formation Successfully in the Gulf of Cambay, Offshore India,’ by Sergey Stolyarov and Anwar Alam, Baker Hughes, prepared for the 2013 SPE North Africa Technical Conference and Exhibition, Cairo, 15-17 April. The paper has not been peer reviewed. This paper describes a matrix-acidizing campaign executed successfully in the Gulf of Cambay on the west coast of India. In initial laboratory tests and during simulation runs, the goal was to design a preflush/ acid/post-flush system to best suit challenging reservoir conditions while also considering offshore logistics. After pumping the system in one well, the system design, pumping procedures, and volumes were modified to improve results further in the next well. Introduction The offshore field, located in the Arabian Sea off the western coast of India, has been on production since 1997 (Fig. 1). The field covers an area of 1471 km2 and lies 160 km north/northwest of Mumbai. The reservoir consists of a stacked series of sands deposited in the Lower Miocene and Oligocene. The field has up to 13 different Olio-Miocene gas-bearing sands separated by shales. Reservoir-sand permeability ranges from 100 md (in shaly beds) up to 5,000 md in clean sand beds. Because of the unconsolidated nature of the reservoir sands, gravel-pack screens are a typical well completion in the field.
- Asia > India > Maharashtra > Mumbai (0.24)
- Africa > Middle East > Egypt > Cairo Governorate > Cairo (0.24)
- Well Completion > Acidizing (1.00)
- Well Completion > Sand Control > Gravel pack design & evaluation (0.73)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.61)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (0.47)