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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.
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 US 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. This page discusses 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 Miscible injection enhanced oil recovery (EOR).
The first hydraulic fracturing treatment was pumped in 1947 on a gas well operated by Pan American Petroleum Corp. in the Hugoton field. Kelpper Well No. 1, located in Grant County, Kansas, was a low-productivity well, even though it had been acidized. The well was chosen for the first hydraulic fracture stimulation treatment so that hydraulic fracturing could be compared directly with acidizing. Since that first treatment in 1947, hydraulic fracturing has become a common treatment for stimulating the productivity of oil and gas wells. Hydraulic fracturing is the process of pumping fluid into a wellbore at an injection rate that is too high for the formation to accept without breaking.
The process of drilling and completing coalbed methane (CBM) wells is similar to wells in conventional reservoirs. Coring, however, can pose special challenges. The first step in creating a drilling program for a CBM well involves gathering information about existing wells in a given area. After these data are gathered and analyzed, a preliminary drilling and completion prognosis can be drafted with the input of field operations personnel. An important aspect in drilling frontier or appraisal wells is to keep the drilling procedures relatively simple.
Introduction The first hydraulic fracturing treatment was pumped in 1947 on a gas well operated by Pan American Petroleum Corp. in the Hugoton field. Kelpper Well No. 1, located in Grant County, Kansas, was a low-productivity well, even though it had been acidized. The well was chosen for the first hydraulic fracture stimulation treatment so that hydraulic fracturing could be compared directly with acidizing. Since that first treatment in 1947, hydraulic fracturing has become a common treatment for stimulating the productivity of oil and gas wells. Hydraulic fracturing is the process of pumping a fluid into a wellbore at an injection rate that is too great for the formation to accept in a radial flow pattern. As the resistance to flow in the formation increases, the pressure in the wellbore increases to a value that exceeds the breakdown pressure of the formation open to the wellbore. Once the formation "breaks down," a fracture is formed, and the injected fluid begins moving down the fracture. In most formations, a single, vertical fracture is created that propagates in two directions from the wellbore. These fracture "wings" are 180 apart and normally are assumed to be identical in shape and size at any point in time; however, in actual cases, the fracture wing dimensions may not be identical. In naturally fractured or cleated formations, it is possible that multiple fractures can be created and propagated during a hydraulic fracture treatment. Fluid that does not contain any propping agent (called the "pad") is injected to create a fracture that grows up, out, and down, and creates a fracture that is wide enough to accept a propping agent. The purpose of the propping agent is to prop open the fracture once the pumping operation ceases, the pressure in the fracture decreases, and the fracture closes.
Consider lining up the perforations. A handful of speakers at the recent SPE Hydraulic Fracturing Technology Conference talked about improved fracturing results with oriented perforating--shooting the holes at the same place in the casing, often the top. This breaks from designs that arranged the holes in a helical pattern with each charge angled 60 from the previous one. "We did see indications we are getting better production from oriented perforating," said Blake Horton, senior completions engineer for Ovintiv (SPE 204177). Production gains were also reported by ConocoPhillips which compared production from similar wells with and without oriented perforating.
Introduction Petroleum data analytics is a solid engineering application of data science in petroleum-engineering-related problems. The engineering application of data science is defined as the use of artificial intelligence and machine learning to model physical phenomena purely based on facts (e.g., field measurements and data). The main objective of this technology is the complete avoidance of assumptions, simplifications, preconceived notions, and biases. One of the major characteristics of petroleum data analytics is its incorporation of explainable artificial intelligence (XAI). While using actual field measurements as the main building blocks of modeling physical phenomena, petroleum data analytics incorporates several types of machine-learning algorithms, including artificial neural networks, fuzzy set theory, and evolutionary computing.
Introduction The three primary functions of a drilling fluid--the transport of cuttings out of the wellbore, prevention of fluid influx, and the maintenance of wellbore stability--depend on the flow of drilling fluids and the pressures associated with that flow. For example, if the wellbore pressure exceeds the fracture pressure, fluids will be lost to the formation. If the wellbore pressure falls below the pore pressure, fluids will flow into the wellbore, perhaps causing a blowout. It is clear that accurate wellbore pressure prediction is necessary. To properly engineer a drilling fluid system, it is necessary to be able to predict pressures and flows of fluids in the wellbore. The purpose of this chapter is to describe in detail the calculations necessary to predict the flow performance of various drilling fluids for the variety of operations used in drilling and completing a well. Overview Drilling fluids range from relatively incompressible fluids, such as water and brines, to ...
Abstract Objectives April 2010 in the Gulf of Mexico and January 2017 in Oklahoma brought into sharp focus what can happen if the oil and gas industry gets well control wrong: 16 fatalities, significant environmental damage, loss of assets and reputation. Each year we have multiple blowouts and several fatality events due to a loss of well control. The oil and gas industry can improve from a personnel safety, environmental and reputation perspective. The Automation of Well Control will bring a significant step change in the area of Process Safety forwells. It prevents blowouts, reduces all influx volumes, minimising kicktolerance volumes and reducingcasing and well costs. Method A system has been developedwhich enables Automated Well Control whilst in drilling mode. Pre-determined influx rates, agreed by the operator and drilling contractor, and input by the driller are established. Once the system detects the influx, it performs a series of operations by taking control of the drilling rig equipment. The drill string is spaced out, top drive and mud pumps are stopped, and the BOP is closed. All of this occurs without the driller doing anything; however, he can intervene at any moment. Thissystem is designed as an aid to the driller and does not remove his responsibility. Results The Automated Well Control system has been tested on drilling simulators with real drillers. Comparisons tests have shown that the technology enables shut-in times faster than conventional human interface methods, with influx volumes typically 10-20% of those experienced during manual shut-in. Additionally, a full Field Trial using a traditional rigdemonstrated the effectiveness of the system, proving up the functionality under different operational requirements. The system can now be applied to any type of rig worldwide. Over 50 potential modules have been identified. Planned developments forthe system include circulatingout the kick automatically, shut-in for tripping, circulating, cementing and in-flow testing. It provides assurance for afast, safe and effective shut-in.A full Technology Qualification process has been used for this technology. Innovative Technology Over the past 20 years, technology advancements associated with simulators and cyber-rigs have enabled new technologies to be developed. One of these technologies is Automated Well Control. It is believed that this innovative system will enable a step change in the performance ofprocess safety forwell control, dramaticallyreducing major accident hazards, thereby saving millions of dollars per well, reducing environmental impact and preventing loss of life.
US shale producers Cabot Oil & Gas and Cimarex Energy are the latest to declare a "merger of equals" in a deal valued at around $17 billion, based on recent equity prices. Announced today, the terms of the deal will result in Cimarex shareholders owning about 50.5% of the combined company and Cabot shareholders owning approximately 49.5%. The deal brings together Houston-based Cabot's gas-rich portfolio, comprising almost 173,000 acres in the Marcellus Shale, with Cimarex's oil-dominated 560,000 net acres in the Permian Basin and Anadarko Basin. On a pro forma basis, the merged company will produce around 600,000 BOE/D from the three basins. The companies expect $100 million in savings to materialize within 2 years of the deal closing and to generate around $4.7 billion in free cash flow from 2022 to 2024.