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ABSTRACT The industry is facing significant challenges due to the recent downturn in oil prices, particularly for the development of tight reservoirs. It is more critical than ever to 1) identify the sweet spots with less uncertainty and 2) optimize the completion-design parameters. The overall objective of this study is to quantify and compare the effects of reservoir quality and completion intensity on well productivity. We developed a supervised fuzzy clustering (SFC) algorithm to rank reservoir quality and completion intensity, and analyze their relative impacts on wells' productivity. We collected reservoir properties and completion-design parameters of 1,784 horizontal oil and gas wells completed in the Western Canadian Sedimentary Basin. Then, we used SFC to classify 1) reservoir quality represented by porosity, hydrocarbon saturation, net pay thickness and initial reservoir pressure; and 2) completion-design intensity represented by proppant concentration, number of stages and injected water volume per stage. Finally, we investigated the relative impacts of reservoir quality and completion intensity on wells' productivity in terms of first year cumulative barrel of oil equivalent (BOE). The results show that in low-quality reservoirs, wells' productivity follows reservoir quality. However, in high-quality reservoirs, the role of completion-design becomes significant, and the productivity can be deterred by inefficient completion design. The results suggest that in low-quality reservoirs, the productivity can be enhanced with less intense completion design, while in high-quality reservoirs, a more intense completion significantly enhances the productivity. Keywords Reservoir quality; completion intensity; supervised fuzzy clustering, approximate reasoning,tight reservoirs development
Formation damage in gas/condensate reservoirs can be caused by a buildup of fluids (condensate) around the wellbore. This reduces the relative permeability and therefore gas production. This page discusses condensate banking and how to overcome its effects. As shown in Figure 1, gas/condensate reservoirs are defined as reservoirs that contain hydrocarbon mixtures that on pressure depletion cross the dewpoint line. In such instances as when the bottomhole pressure is reduced during production, the dewpoint pressure of the gas is reached in the near-wellbore region.
Producing formation damage has been defined as the impairment of the unseen by the inevitable, causing an unknown reduction in the unquantifiable. In a different context, formation damage is defined as the impairment to reservoir (reduced production) caused by wellbore fluids used during drilling/completion and workover operations. It is a zone of reduced permeability within the vicinity of the wellbore (skin) as a result of foreign-fluid invasion into the reservoir rock. Typically, any unintended impedance to the flow of fluids into or out of a wellbore is referred to as formation damage. This broad definition includes flow restrictions caused by a reduction in permeability in the near-wellbore region, changes in relative permeability to the hydrocarbon phase, and unintended flow restrictions in the completion itself. Flow restrictions in the tubing or those imposed by the well partially penetrating a reservoir or other aspects of the completion geometry are not included in this definition because, although they may impede flow, they either have been put in place by design to serve a specific purpose or do not show up in typical measures of formation damage such as skin.
Formation damage has received significant attention over many decades, but what about completion damage? Before we discuss this question, we first need to define these terms. Formation damage could be considered as damage to the near-wellbore (e.g., mud solids invasion, plugging). In contrast, completion damage is damage to the lower completion (e.g., plugging of screens). The combined effect of formation and completion damage is the observed well productivity development with associated skin and productivity index.
Formation damage has received significant attention over many decades, but what about completion damage? Before we discuss this question, we first need to define these terms. Formation damage could be considered as damage to the near-wellbore (e.g., mud solids invasion, plugging). In contrast, completion damage is damage to the lower completion (e.g., plugging of screens). The combined effect of formation and completion damage is the observed well productivity development with associated skin and productivity index. Completion damage has the potential to affect well productivity to the same degree as formation damage. However, at a basic level, there is not even a classification system for completion damage, and yet one has been available for formation damage at least 30 years, possibly longer. Within Equinor, we are trying to address this imbalance by having increased focus on completion damage. We have an ongoing project to develop the following: A classification system—We have focused on lower completion design and damage that can occur over a well’s lifetime. A review of testing procedures used and development of new ones where appropriate. Use of computation fluid dynamics (CFD) more in completion damage evaluations—This approach has provided invaluable new insights. We are using CFD, for example, to visualize displacement efficiency from drilling to completion fluids. We also are incorporating data from coreflooding and completion-damage testing into a single CFD simulation that will enable us to assess what effect formation and completion damage will have on future well productivity.
Cold heavy oil production with sand (CHOPS) involves the deliberate initiation of sand influx during the completion procedure, maintenance of sand influx during the productive life of the well, and implementation of methods to separate the sand from the oil for disposal. No sand exclusion devices (screens, liners, gravel packs, etc.) are used. The sand is produced along with oil, water, and gas and separated from the oil before upgrading to a synthetic crude. To date, deliberate massive sand influx has been used only in unconsolidated sandstone (UCSS) reservoirs (φ 30%) containing viscous oil (μ 500 cp). It has been used almost exclusively in the Canadian heavy-oil belt and in shallow ( 800 m), low-production-rate wells (up to 100 to 125 m3/d).
There are many possible causes of formation damage. In addition to the numerous sources identified in separate articles (see See Also section below), other, less common causes include emulsions and sludges, wettability alteration, bacterial plugging, gas breakout, and water blocks. The presence of emulsions at the surface does not imply the formation of emulsions in the near-wellbore region. Most often, surface emulsions are a result of mixing and shearing that occur in chokes and valves in the flow stream after the fluids have entered the well. It is uncommon to have emulsions and sludges form in the near-wellbore region without the introduction of external chemicals.The
Behera, Chaitanya (Petroleum Development Oman) | Mahajan, Sandip (Petroleum Development Oman) | Annia, Carlos (Petroleum Development Oman) | Harthi, Mahmood (Petroleum Development Oman) | Obilaja, Jane-Frances (Petroleum Development Oman) | Abri, Said (Petroleum Development Oman) | Hamdoun, Lana (Petroleum Development Oman)
Abstract This paper presents the results of a comprehensive study carried out to improve the understanding of deep bottom-up water injection, which enabled optimizing the recovery of a heavy oil field in South Oman. Understanding the variable water injection response and the scale of impact on oil recovery due to reservoir heterogeneity, operating reservoir pressure and liquid offtake management are the main challenges of deep bottoms-up water injection in heavy oil fields. The offtake and throughput management philosophy for heavy oil waterflood is not same as classical light oil. Due to unclear understanding of water injection response, sometimes the operators are tempted to implement alternative water injection trials leading to increase in the risk of losing reserves and unwarranted CAPEX sink. There are several examples of waterflood in heavy oil fields; however, very few examples of deep bottom water injection cases are available globally. The field G is one of the large heavy oil fields in South Oman; the oil viscosity varies between 250cp to 1500cp. The field came on-stream in 1989, but bottoms-up water-injection started in 2015, mainly to supplement the aquifer influx after 40% decline of reservoir pressure. After three years of water injection, the field liquid production was substantially lower than predicted, which implied risk on the incremental reserves. Alternative water injection concepts were tested by implementing multiple water injection trials apprehending the effectiveness of the bottoms-up water injection concept. A comprehensive integrated study including update of geocellular model, full field dynamic simulation, produced water re-injection (PWRI) model and conventional field performance analysis was undertaken for optimizing the field recovery. The Root Cause Analysis (RCA) revealed many reasons for suboptimal field performance including water injection management, productivity impairment due to near wellbore damage, well completion issues, and more importantly the variable water injection response in the field. The dynamic simulation study indicated negligible oil bank development due to frontal displacement and no water cut reversal as initial response to the water injection. Nevertheless, the significance of operating reservoir pressure, liquid offtake and throughput management impact on oil recovery cann't be precluded. The work concludes that the well reservoir management (WRM) strategy for heavy oil field is not same as the classical light oil waterflood. Nevertheless, the reservoir heterogeneity, oil column thickness and saturation history are also important influencing factors for variable water injection response in heavy oil field.
The number of professionals specializing in pressure-transient testing is relatively small. Thus, those who become proficient in it will likely remain in demand throughout their careers as key technical resources in operating or service companies. What would you be doing should you decide to look further into a career focused on this specialty? Traditionally, pressure-transient testing means testing for drawdown or buildup in a production well, or injection or falloff in an injection well. Transient tests are conducted both in newly drilled exploration and development wells and in wells that have been on production for a long time.