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Pemex and Talos Energy have 120 days to decide how to share a massive offshore field that both companies claim they should operate. Failure to come to terms means the government will decide the matter. Putting together the billions of dollars needed to develop deepwater finds has become tougher, but when the discoveries are huge, companies will make every effort to find a way to tap what may be a cheap source of oil. The complete paper analyzes the role of liquefied natural gas (LNG) in balancing the natural gas demand in the Middle East/North Africa (MENA) region. Saudi Arabia offers a seemingly bottomless supply of oil and an equally deep array of exploration challenges as well.
A producer in the Marcellus Basin selected Edge Gathering Virtual Pipelines 2 to capture and liquefy gas from its stranded wells in Tioga County. Initial operation is underway and is set to be ongoing until at least 2022. Researchers at Texas Tech University have released a study into wastewater production and disposal in the Marcellus Shale, proposing disposal hubs across the state of Pennsylvania that could reduce trucking distances. As part of a revised strategic plan, the Spanish company says it will invest more than $9 billion on its overall operations by 2020, with much of it going to its upstream business unit. Predictive models may help in the estimation of produced water volumes and the optimization of the locations for water recycling and disposal facilities to reduce truck hauling distances.
A computational fluid dynamics model is proposed to analyze the effect of hydrate flow in pipelines using multiphase-flow-modeling techniques. The results will identify the cause of pipeline failure, regions of maximum stress in the pipeline, and plastic deformation of the pipeline. The 9th International Conference on Gas Hydrates featured discussions on key advancements in flow assurance, including the concept of risk management and anti-agglomerates being applicable strategies in transient operations. A BP flow assurance manager explains a methodology for determining and mitigating flow assurance risks. A BP flow assurance engineer discusses the shift in hydrate management strategy from complete avoidance to risk mitigation for an offshore dry tree facility.
In tectonically influenced regions, potential hydrocarbon traps are subject to complex states of stress. The cementing services market size in the US is expected to drop 50% year-on-year from 2019. The significant drop in Permian Basin activity will account for 40% of the total market size reduction. The complete paper presents a case study in which offline cementing improved operational efficiency by reducing drilling times and provided significant cost savings. This year, excellent papers have been presented, augmenting our knowledge and responding to the challenges of complex wells and efficiency requirements.
In the complete paper, the authors revisit fundamental concepts of reservoir simulation in unconventional reservoirs and summarize several examples that form part of an archive of lessons learned. Proper lateral and vertical well spacing is critical for efficient development of unconventional reservoirs. Much research has focused on lateral well spacing but little on vertical spacing, which is challenging for stacked-bench plays such as the Permian Basin. Knowing which horizon crude oil flows from and in what proportions has been a major challenge for shale producers. Increasingly, they are turning to new technology to find the answer.
Southwest Research Institute is adding a new facility to its capabilities in testing and evaluating subsea equipment and systems. This review of papers illustrates some of the innovative solutions used in the region. This paper focuses on a numerical-modeling analysis of the acid-gas-injection (AGI) scenario in carbonate HP/HT reservoirs, and presents the way in which AGI impacts asphaltene-precipitation behavior. This paper demonstrates a design methodology that combines the API and American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessels Code (BPVC) for designing an example subsea pressure containing component for HP/HT conditions greater than 15,000 psi and 250°F.
This chapter concerns gas injection into oil reservoirs to increase oil recovery by immiscible displacement. The use of gas, either of a designed composition or at high-enough pressure, to result in the miscible displacement of oil is not discussed here; for a discussion of that topic, see the chapter on miscible flooding in this section of the Handbook. A variety of gases can and have been used for immiscible gas displacement, with lean hydrocarbon gas used for most applications to date. Historically, immiscible gas injection was first used for reservoir pressure maintenance. The first such projects were initiated in the 1930s and used lean hydrocarbon gas (e.g., Oklahoma City field and Cunningham pool in the United States and Bahrain field in Bahrain). Over the decades, a considerable number of immiscible gas injection projects have been undertaken, some with excellent results and others with poor performance. Reasons for this range of performance are discussed in this chapter. At the end of this chapter, a variety of case studies are presented that briefly describe several of the successful immiscible gas injection projects. Gas injection projects are undertaken when and where there is a readily available supply of gas. This gas supply typically comes from produced solution gas or gas-cap gas, gas produced from a deeper gas-filled reservoir, or gas from a relatively close gas field. The primary physical mechanisms that occur as a result of gas injection are (1) partial or complete maintenance of reservoir pressure, (2) displacement of oil by gas both horizontally and vertically, (3) vaporization of the liquid hydrocarbon components from the oil column and possibly from the gas cap if retrograde condensation has occurred or if the original gas cap contains a relict oil saturation, and (4) swelling of the oil if the oil at original reservoir conditions was very undersaturated with gas. Gas injection is particularly effective in high-relief reservoirs where the process is called "gravity drainage" because the vertical/gravity aspects increase the efficiency of the process and enhance recovery of updip oil residing above the uppermost oil-zone perforations. The decision to apply immiscible gas injection is based on a combination of technical and economic factors. Deferral of gas sales is a significant economic deterrent for many potential gas injection projects if an outlet for immediate gas sales is available.
The difficulty in applying traditional reservoir-simulation and -modeling techniques for unconventional-reservoir forecasting is often related to the systematic time variations in production-decline rates. This paper proposes a nonparametric statistical approach to resolve this difficulty. In this work, the authors perform automatic decline analysis on Marcellus Shale gas wells and predict ultimate recovery for each well.
The emphasis of this 1-day course will be on providing practical guidance and understanding. The basic constructs involved in a reservoir simulator and their implications to the approaches that are used in building efficient simulation models for different thermal recovery processes will be discussed. Upon completion of the course, you will be able to build and run simulation-friendly reservoir models that reflect different types of thermal recovery processes. You'll learn the underlying principles of reservoir simulation and how these drive the construction of geological models and the modelling of recovery processes. Reservoir engineers and geologists who are involved in the modelling of thermal processes to recover heavy oil and bitumen.
Unconventional Risk and Uncertainty: What Does Success Look Like? This paper presents approaches for proper risking of uncertain recoverable volumes for an unconventional resource, taking into account the chance of false positives from appraisal-well information. The difficulty in applying traditional reservoir-simulation and -modeling techniques for unconventional-reservoir forecasting is often related to the systematic time variations in production-decline rates. This paper proposes a nonparametric statistical approach to resolve this difficulty. As the drilling industry improves its efforts to capture drilling operation activities in real time, it has generated a significant amount of data that drilling engineers cannot process on their own.