Hassan, Amjed (King Fahd University of Petroleum & Minerals) | Alade, Olalekan (King Fahd University of Petroleum & Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum & Minerals) | Al-Majed, Abdulaziz (King Fahd University of Petroleum & Minerals)
In the petroleum industry, deposition of hydrocarbon wax is one the critical problems. Wax can deposit and accumulate inside the well completion, surface facilities and transportation pipelines. Wax deposition can lead to significant pressure drop in the production system and may result in stopping the hydrocarbon production. Several treatments are used to remove the deposited wax and improve the hydrocarbon flow. This paper presents a new and cost-effective technique for removing the wax deposition from the production system. In this work, inexpensive and environmentally-friendly fluids have been used for wax removal. Chemicals that able to generate heat and pressure at certain condition were used.
In this study, thermochemical fluids were utilized to remove the accumulate wax in the production tubing. Actual wax from Arabian oil field was used to mimic the real condition of wax deposition. Thermochemical solutions that consist of two chemical reagents were used to remove the accumulated wax in a production tubing. The used chemical can react at certain condition and generate significant amount of heat and pressure. Temperature up to 500°F and pressure up to 2000 psi can be in-situ generated due to the thermochemical reaction. The chemical reaction can be triggered using acetic acid as an activating agent, to reduce the operational time for wax removal.
The results showed that, more than 95% of the deposited wax can be removed using thermochemical solutions. The in-situ generated heat is able to liquefy the precipitated wax, then, the induced pressure due to the chemical reaction can flush the wax out of the production tubing. The used chemicals did not result in any damage in the pipeline, no corrosion or precipitation was observed in the production tubing. Also, the generated pressure due to thermochemical treatment did not reduce the pipe integrity, no pipe enlargement or damage was induced in the treated samples.
This study presents a novel and high-performance treatment for wax removal using thermochemical fluids. The used chemicals can remove the wax from production tubing, surface facilities, and transportation pipelines; without affecting the integrity of the production system. The thermochemical fluids can be used at harsh situation of high temperature and high salinity condition. The obtained results show that there is a good potential for field application of this work in the next few months.
While the first subsea production system was installed in a shallow water environment (West Cameron field in Gulf of Mexico, by Shell in 55ft water depth, 1961), subsea development concept has been more synonymous with deepwater development. It has not been a development concept of choice for shallow water development in Middle East and Asia mainly due to the perception that it has higher life cycle cost and difficult to intervene. Subsea production concept can be a competitive option vis-à-vis topsides production concept in certain circumstances. More often than not, project economics dictates that development capital expenditure (CAPEX) requires to be as low as practicable; and pre-investment in the initial phase of the project development needs to be carefully managed to minimize its impact on CAPEX and net present value (NPV). Subsea production system are inherently fit-for-purpose and provide an ideal opportunity for project owners to assess the potential of the particular field before deciding to proceed with full-scale development in the subsequent phase. The fact that there is a large number of shallow-water subsea production systems installed and operated worldwide in the last 30 years provide sufficient track record, lifecycle cost and reliability data that could be used by field development and front end engineers in coming up with a feasible development concept with attractive NPV. Subsea production system in a shallow water environment is a proven concept predominantly due to the following factors: 1. Provide alternative development option where fixed structures are not cost-effective: a) Where development costs may not justify the CAPEX for a platform b) Where brownfield expansion requires low well counts 2. Optimize drilling program: a) If field reservoir areas are not reachable by deviated drilling from surface wells, producing hydrocarbon from multiple fixed structures might not be economically feasible b) Subsea completion and production system offer better flexibility in term of field layout and well top-hole positioning 2 SPE-197604-MS
In 1993, Richard D’Souza (Fellow), the principal author and his co-authors presented a landmark paper reviewing the Semisubmersible Floating Production System (FPS) technology at the SNAME centennial meeting in New York. (D’Souza et al., 1993a). The paper captured the twenty year progression of the FPS beginning with the Argyll field in the UK Sector of the North Sea in 80 meters of water that was converted from a semisubmersible Mobile Offshore Drilling Unit (MODU) and began producing in 1975. During this period about twenty five FPSs were installed, primarily in the North Sea and Brazil. Most were converted from semisubmersible MODUs. The deepest was in 625 m, the largest displacing 45,000 mt and the maximum oil rate was 70,000 bopd.
Over forty FPSs have been installed since then, most of which are purpose built platforms. The technology has expanded to a maximum water depth of 2400 m, displacements exceeding 150,000 mt and production rates of 300,000 boepd. The inherent versatility and flexibility of the FPS to adapt to a wide range of water depths, payloads, metocean conditions and future expansion, has resulted in the FPS superseding the Tension Leg Platform (TLP) and the Spar platform as the most widely used floating production platform after the Floating Production Storage and Offloading (FPSO) platform. Its field development applications range from marginal reservoirs to giant deepwater oil and gas fields across the globe.
This paper, authored by Richard D’Souza with a new team of co-authors, is a sequel to the 1993 paper and is intended as a historical and technical archive of the evolution of the FPS technology in the ensuing twenty five years. It highlights the importance of the Naval Architect and Ocean Engineer whose role has evolved from a peripheral to a major player in the design, fabrication and installation of the FPS. This paper has two objectives. One is to inform Operators and Contractors engaged in developing deepwater fields by providing a historical overview of lessons learned and technology evolution of the FPS. The other is to inspire graduate and post graduate Naval Architects and Ocean Engineers to consider a career in the offshore industry where they will have an impactful role in shaping the future of deepwater floating production platforms.
The Bureau of Safety and Environmental Enforcement is launching a safety initiative to bring critical information directly to offshore workers on the outer continental shelf. The BSEE!Safe program uses text messages to send links to its published Safety Alerts and Bulletins. The Bureau of Safety and Environmental Enforcement says its final well-control rule removes unnecessary regulatory burdens to responsible offshore development while maintaining safety and environmental protection. The Bureau of Safety and Environmental Enforcement says its staffing and inspections are up, while the environmental group Oceana says that oil and gas drillers have a financial incentive to ignore safety. Ahead of the release of the Trump administration's changes to Obama-era rules governing offshore oil platforms, Michael Bromwich said he is worried.
Regulators say the blowout that killed five workers on a Patterson-UTI rig in Oklahoma was the product of a slow-moving series of missed signals, misleading testing, and miscalculations that failed to control a natural gas influx. The new well control rule is evidence that memories of the Macondo blowout remain a powerful force for caution. Despite the rhetoric on both sides of this hot-button issue suggesting big changes, the final changes were incremental. Nonaqueous drilling fluids, such as synthetic-based and oil-based mud (SBM and OBM, respectively), are used frequently to drill one or more sections of a well to reduce drilling problems such as shale sloughing, wellbore stability, and stuck pipe. Three onshore fields in the Emirate of Sharjah, United Arab Emirates, have more than 30 years of production history from more than 50 gas-condensate wells.
A critical support role within the upstream sector is played by the thousands who work in HSE and sustainability. The HSE performance of the industry has improved dramatically over the decades because of technological advances and a greater understanding of systems, processes, and human performance. Researchers mapped 251 faults in the North Texas home of the Barnett Shale, the birthplace of the shale revolution, finding that wastewater injection there “significantly increases the likelihood for faults to slip.” The new well control rule is evidence that memories of the Macondo blowout remain a powerful force for caution. Despite the rhetoric on both sides of this hot-button issue suggesting big changes, the final changes were incremental.
Australia’s BHP Billiton and the recently acquired Anadarko Petroleum submitted the largest dollar totals of high bids in US Gulf of Mexico Lease Sale 253. Operator Talos Energy now believes Zama’s gross recoverable resource lies in the upper half of its pre-appraisal estimate of 400–800 million BOE. The consortium is working toward a 2020 final investment decision on the project. The deal consists of stakes in nine shallow-water producing fields covering 108,000 gross acres in 10–50 m of water. The new well control rule is evidence that memories of the Macondo blowout remain a powerful force for caution.
Understanding the principles of fluid flow through the production system is important in estimating the performance of individual wells and optimizing well and reservoir productivity. In the most general sense, the production system is the system that transports reservoir fluids from the subsurface reservoir to the surface, processes and treats the fluids, and prepares the fluids for storage and transfer to a purchaser. Figure 1--Production System and associated pressure losses. The reservoir is the source of fluids for the production system. It is the porous, permeable media in which the reservoir fluids are stored and through which the fluids will flow to the wellbore.
For a low-pressure well with solids and/or heavy oil at a depth of less than approximately 6,000 ft and if the well temperature is not high (75 to 150 F typical, approximately 250 F or higher maximum), a PCP should be evaluated. Even if problems do not exist, a PCP might be a good choice to take advantage of its good power efficiency. If the application is offshore, or if pulling the well is very expensive and the well is most likely deviated, ESPCP should be considered so that rod/tubing wear is not excessive. There is an ESPCP option that allows wire lining out a failed pump from the well while leaving the seal section, gearbox, motor, and cable installed for continued use.