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Conformance is a measure of the uniformity of the flood front of the injected drive fluid during an oil recovery flooding operation and the uniformity vertically and areally of the flood front as it is being propagated through an oil reservoir. This page provides an overview of selected chemical systems and technologies that promote improved conformance during oil recovery operations. See Conformance problems for a discussion of the underlying problems creating the need for conformance improvement. Conformance improvement systems and technologies include fluid systems for use during oil recovery flooding operations in which the fluids promote sweep improvement and mobility control (e.g., polymer waterflooding) and oilfield conformance improvement treatment systems (e.g., "small-volume" gel treatments). A conformance improvement fluid system for promoting flood sweep improvement and mobility control involves injecting a volume of an oil recovery fluid that constitutes a significant fraction of the reservoir pore volume.
Muskat defines primary recovery as the production period "beginning with the initial field discovery and continuing until the original energy sources for oil expulsion are no longer alone able to sustain profitable producing rates." This article provides an overview of types of reservoir energy and producing mechanisms (drive mechanisms). Primary recovery should be distinguished clearly from secondary recovery. Muskat defines secondary recovery as "the injection of (fluids) after the reservoir has reached a state of substantially complete depletion of its initial content of energy available for (fluid) expulsion or where the production rates have approached the limits of profitable operation." Because primary recovery invariably results in pressure depletion, secondary recovery requires "repressuring" or increasing the reservoir pressure.
Remedial cementing is undertaken to correct issues with the primary cement job of a well. Remedial cementing requires as much technical, engineering, and operational experience, as primary cementing but is often done when wellbore conditions are unknown or out of control, and when wasted rig time and escalating costs have the potential to force poor decisions and high risk. Good planning and risk assessment is the key to successful remedial cementing. Squeeze cementing is a "correction" process that is usually only necessary to correct a problem in the wellbore. Most squeeze applications are unnecessary because they result from poor primary-cement-job evaluations or job diagnostics.
This topic page provides an extensive set of tables intended to aid in the practical application of production-logging technology. For a given problem, the reader is guided first in the selection of the set of logging tools most appropriate. Next, suggestions are given on the proper procedure for each tool's use. This is an important part of the guidance, because the way logging records are obtained is often the most important part of the operation. Finally, the user is provided with comments regarding what the records should show relative to the problem.
Most primary cement jobs are performed by pumping the slurry down the casing and up the annulus; however, modified techniques can be used for special situations. Conductor, surface, protection, and production strings are usually cemented by the single-stage method, which is performed by pumping cement slurry through the casing shoe and using top and bottom plugs. There are various types of heads for continuous cementing, as well as special adaptors for rotating or reciprocating casing. Stage-cementing tools, or differential valve (DV) tools, are used to cement multiple sections behind the same casing string, or to cement a critical long section in multistages. Stage cementing may reduce mud contamination and lessens the possibility of high filtrate loss or formation breakdown caused by high hydrostatic pressures, which is often a cause for lost circulation.
Progressive cavity pumps (PCPs) have become one of the most common types of lift methods for dewatering coalbed-methane wells. Water rates are typically high during initial production and may exceed 400 m3/d [2,500 B/D] in some cases but normally decline to 25% of their original level after a few months. The produced water often contains high concentrations of suspended sand from hydraulic fracturing, coal particles, and dissolved solids. To facilitate maximum gas production, the wells are usually maintained in close to a pumped-off condition. This tends to exacerbate the problems associated with the handling of produced gas.
Offshore production operations can be either very similar to or radically different from land-based installations. Except for a few innovative installations, wellheads and Christmas trees on platforms are basically the same as for land wells (see Fig 1). Control valves, safety valves, and piping outlets are configured the same and use the same or similar components. Some of the valves probably will have pneumatic or hydraulic actuators to facilitate remote and rapid closure in an emergency. Also, some Christmas trees may have composite block valves instead of individual valves flanged together.
Production operations in the offshore artic regions are within the reach of existing technology. Procedures used onshore and offshore in less hostile regions, however, must be modified to meet the challenges of the harsh climatic conditions in the remote locations. In the last decade, the major area of industry interest has been the offshore region of Alaska and Canada. The environmental conditions vary significantly in each of these regions. The specific production system that is selected must be tailored to each unique combination of these factors to ensure safe oilfield development.
The following topic describes the intermittent-flow gas lifts and the factors which affect its design and performance. Intermittent-flow gas lift is applicable to low-productivity wells and to low- and high-productivity wells with low reservoir pressure. As the name implies, the reservoir fluid is produced intermittently by displacing liquid slugs with high-pressure injection gas, as illustrated in Figure 1. Either an electronic or clock-driven time-cycle controller, or an adjustable or fixed choke, controls the flow of injection gas. Not all gas lift valves operate on choke control. The number of intermittent-flow gas lift installations on time-cycle control far exceeds the number of choke-controlled installations. Intermittent-flow gas lift should be used only for tubing flow.
An important consideration related to intermittent gas lift operations is the injection-gas breakthrough and resulting loss of the liquid production per cycle from the injection gas penetrating the liquid slug during the time required to displace this slug to the surface. The produced-liquid slug can be a small fraction of the starting slug size because of injection-gas breakthrough. The losses are greater when the injection-gas pressure is low and the required depth of lift is near total depth in a deep well. For example, a 12,000-ft well with a bottomhole flowing pressure of 300 psig and an available injection-gas pressure of only 450 psig can be gas lifted intermittently with the proper plunger. The well could not be gas lifted successfully from this depth without a plunger.