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Grace Murungi is "fanatical about energy generation". As a Rwandese growing up in a region with constant power cuts, she dreamt of contributing to the creation of a constant energy supply which sparked her interest in engineering. Grace later obtained a BSc. Grace then joined Schlumberger Oilfield Services as an Artificial Lift Field Engineer based in West Africa. My role involved design, installation/retrieval of Electrical Submersible Pump and Gas Lift Systems in offshore and onshore environments.
Decisions in E&P ventures are affected by Bias, Blindness, and Illusions (BBI) which permeate our analyses, interpretations and decisions. This one-day course examines the influence of these cognitive pitfalls and presents techniques that can be used to mitigate their impact. Bias refers to errors in thinking whereby interpretations and judgments are drawn in an illogical fashion. Blindness is the condition where we fail to see an unexpected event in plain sight. Illusions refer to misleading beliefs based on a false impression of reality. All three can lead to poor decisions regarding which work to undertake, what issues to focus on, and whether to forge ahead or walk away from a project. Strategic thinking and planning are key elements in an organisation’s journey to maximise value to shareholders, customers, and employees. Through this workshop, attendees will go through the different processes involved in strategic planning including the elements of organisational SWOT, business scenario and options development, elaboration of strategic options and communication to stakeholders. Examples are provided including corporate, business unit and department case studies. This seminar will teach participants how to identify, evaluate, and quantify risk and uncertainty in everyday oil and gas economic situations. It reviews the development of pragmatic tools, methods, and understandings for professionals that are applicable to companies of all sizes. The seminar also briefly reviews statistics, the relationship between risk and return, and hedging and future markets.
Challenges In Drilling and Completion Of Extended Reach Drilling Wells with Landing Point Departure more than 10,000ft in Light/ Slim Casing Design. New Generation of HTHP Water Based Drilling Fluid Changing Conventional Drilling Fluids Solutions. Take Back Control of Your Capital Project with an EPC 4.0 Strategy Stratigraphical - Sedimentological Framework for the Thamama Group Development in the Western UAE Based on the Legacy Core Data: How the Key to the Future is Found in the Past. Ultra-deep Resistivity Technology as a Solution for Efficient Well Placement; Geosteering and Fluid Mapping to Reduce Reservoir Uncertainty and Eliminate Pilot Hole-first Time in Offshore Abu Dhabi, UAE. Performance Comparison of two different in-house built virtual metering systems for Production Back Allocation.
Hassi Messaoud is a mature oil field with more than 1,100 production wells. Approximately half of the wells are natural flow and the other half use continuous gas lift (CGL) with concentric (CCE) strings. This paper investigates novel approaches to sour-gas treatment for use in the Middle East that are outside the common oil and gas market and compares them with traditional techniques. In the complete paper, a new, fully coupled implicit tool was used to model an onshore Omani asset with multiple reservoirs, each featuring different fluids and multiple networks. Processing sour natural gas is a challenge.
This paper describes a coiled tubing gas lift (CTGL) technique successfully used to restart production from two pilot wells in a mature field in Pakistan that had been shut in since 2015. The industry has very limited experience in shuttering production on a large scale in unconventional reservoirs. Many questions remain on how stimulated, nanodarcy shale reservoirs may respond. George King discusses the paradigm shifts needed in the industry. As tight-oil producers move to curtail production, hard-to-answer questions are being raised about how shuttered wells will come back.
Use of surfactants and gas lift in combination to suppress severe slugging were tested. Surfactants were able to suppress severe slugging for most of the cases, and gas lift helped significantly. The presence of slug flow in the riser of the sunken Deepwater Horizon could make a significant difference in financial penalties for BP in the wake of the Macondo incident, an expert said. Riser slugging can restrict production and cause problems for downstream equipment. This paper discusses a simplified modeling approach to control of riser slugging.
The purpose of this paper is to highlight the results of a comprehensive investigative study that quantifies the multiphase flow-related differences in multiphase hydrostatic pressure gradient, oil holdup and gas velocities as the gas injection depth is lowered from vertical to higher angles along the heel and into the lateral sections of horizontal wells. The results of this work enable a deeper understanding of gas slippage under gas lift operation at high angle sections of horizontal wells.
When used for optimizing horizontal well liquids unloading, gas lift valves are placed as low in the well as operationally allowable. But what happens if gas lift is applied along the bend or lateral? To help address this important question, we first leverage the vast knowledge gained from the inclined multiphase flow literature. The scientific knowledge base for up/down inclined multiphase flows reveals why such behaviors in laterals are so complex, namely, the extreme slip effects that exist.
In this work, we start with selecting published lab experiments in this area, and then simulate their flow behaviors using an advanced, cutting-edge analytical multiphase flow simulator. Next, we extend our validation to the field-scale using actual horizontal well gas lift field datasets sourced from different unconventional shale oil plays. With this detailed flow modeling substantiated, we then conduct the principal investigation of this work by quantifying the horizontal well gas lift performance at various representative inclinations (0, 30, 60, 88, 90 and 92 degrees from vertical) to better understand how changes in four major sensitivity variables, namely, diameter, gas injection rate, total liquids rate and water cut, impact the effectiveness of the gas lift process. Then, for each of these sensitivities and at each inclination, we analyze and compare the difference in value (value before gas lift - value after gas lift) of the multiphase hydrostatic pressure gradient, oil holdup, wellbore gas velocity and critical gas velocity.
A new learning from this work is that the prior vertical well experience and basis for gas lift being more effective at deeper depths does not translate to horizontal wells. The experience-driven industry viewpoint that gas lift is unaffected by inclination is not supported by both controlled inclined flow loop lab data and horizontal well field data. From the multiphase view, gas lift optimization is governed by the slip behaviors and it is demonstrated in this work that the multiphase hydrostatic pressure gradient reduction will be much lower at horizontal well inclinations of greater than 45 degrees from vertical, meaning the gas lift technique becomes less effective at these higher inclinations deep in the heel and lateral regions. Our results show that in this latter scenario, most of the gas will slip past the liquids, and increasingly so at higher angles (the pipe acts as a separator at these higher angles) and the effectiveness of the gas lift significantly lowers as the flow starts to undergo slugging and other high-slip transitional flow patterns. This has a significant practical impact to operators trying to optimize end-of-tubing (EOT) placement in conjunction with the gas lift lowest valve placement. Summarily, the results from our detailed modeling are used to demonstrate what is and what is not possible in terms of liquids evacuation from horizontal wellbores using gas-assisted lift at up/down inclined angles - and specifically - how gas injection rates affect hydrostatic pressure gradients, oil holdups, wellbore gas velocities and critical unloading gas velocities along the bend and lateral.
Parra, José Ernesto (Instituto Mexicano del Petróleo) | Rosales Arias, Fermín (Instituto Mexicano del Petróleo) | Soto-Castruita, Enrique (Instituto Mexicano del Petróleo) | Jiménez de la Cruz, Guillermo (Instituto Mexicano del Petróleo) | Ramírez-Pérez, Jorge Francisco (Instituto Mexicano del Petróleo) | Cerón-Camacho, Ricardo (Instituto Mexicano del Petróleo) | Cisneros-Dévora, Rodolfo (Instituto Mexicano del Petróleo) | Servín-Nájera, Ana Graciela (Instituto Mexicano del Petróleo) | Zamudio-Rivera, Luis Silvestre (Instituto Mexicano del Petróleo)
We describe the first field applications of a new multifunctional foaming agent (MFA) for production enhancement in oil wells with gas lift. The tests were conducted in three wells with water cuts from 40 to 90%, depth (>5000 m), bottomhole temperature (150°C), and brine hardness and salinity up to 180,000 ppm and 310,000 ppm TDS, respectively. The MFA was coinjected with lift gas via the annulus and generated foam downhole as it mixed with reservoir fluids in the tubing. Tested MFA concentrations ranged from 160 to 750 ppm. The field tests demonstrated that the MFA was able to increase the oil production for a fixed gas lift injection volume. The MFA also enabled to reduce lift gas consumption, while maintaining or even increasing the original oil production.