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Environmental hazards can be reduced or prevented by the proper choice of chemical additives at optimum concentrations. Pressure tests are performed with water or brine to ensure the absence of leaks in pressure piping, tubing, and packer. Leaks on the surface can endanger service personnel, and subsurface leaks can cause subsequent corrosion of tubing and casing in the annulus. Anyone around acid tanks or pressure connections should wear safety goggles for eye protection. Those handling chemicals and valves should wear protective gauntlet-type, acid-resistant gloves.
Since the most common use of matrix acidizing is the removal of formation damage, it is important to understand the nature of the damage that exists so that an appropriate treatment can be designed. Well testing and well test analysis generate a skin factor and well completion efficiency. This is insufficient alone for formation damage diagnosis. Well performance analysis has provided a beneficial tool to identify the location and thickness of damage at flow points in the near wellbore area. Models of flow into perforations and gravel-packed tunnels provide a way to relate the location and severity of damage to the completion procedure that preceded it.
If the problem is formation damage, then matrix acidizing may be an appropriate treatment to restore production. This page discusses ways to evaluate whether a well is a good candidate for acidizing. This plugging can be either mechanical or chemical. Mechanical plugging is caused by either introduction of suspended solids in a completion or workover fluid, or dispersion of in-situ fines by incompatible fluids and/or high interstitial velocities. Chemical plugging is caused by mixing incompatible fluids that precipitate solids.
Introduction This chapter is organized to help perform acidizing on a well candidate in a logical step-by-step process and then select and execute an appropriate chemical treatment for the oil/gas well. The guidelines are practical in intent and avoid the more complicated acid reaction chemistries, although such investigations and the use of geochemical models are recommended for more complicated formations or reservoir conditions. Effective acidizing is guided by practical limits in volumes and types of acid and procedures so as to achieve an optimum removal of the formation damage around the wellbore. Most of this chapter is an outgrowth of field case studies and of concepts derived from experimental testing and research. Justification for the practices and recommendations proposed herein are contained in the referenced documents. The reader is referred to the author's previous papers on matrix acidizing for references published before 1990. Concepts and techniques presented have ...
Corrosion of metal in the presence of water is a common problem across many industries. The fact that most oil and gas production includes co-produced water makes corrosion a pervasive issue across the industry. Age and presence of corrosive materials such as carbon dioxide (CO2) and hydrogen sulfide (H2S) exacerbate the problem. Corrosion control in oil and gas production is reviewed in depth in Treseder and Tuttle, Brondel, et al., and NACE, from which some of the following material is abstracted. Iron is inherently (thermodynamically) sufficiently active to react spontaneously with water (corrosion), generating soluble iron ions and hydrogen gas. The utility of iron alloys depends on minimizing the corrosion rate. Corrosion of steel is an "electrochemical process," involving the transfer of electrons from iron atoms in the metal to hydrogen ions or oxygen in water. This separation of the overall corrosion process into two reactions is not an electrochemical nuance; these processes generally do take place at separate locations on the same piece of metal. This separation requires the presence of a medium to complete the electrical circuit between anode (site of iron dissolution) and cathode (site for corrodant reduction). Electrons travel in the metal phase, but the ions involved in the corrosion process cannot. Ions require the presence of water; hence, corrosion requires the presence of water.
The temperature-logging tool includes a cage, which is open to the wellbore fluid, at the tool's bottom end. Inside the cage is a thermistor that senses the surrounding fluid temperature. The preferred sensor is a platinum element because the electrical resistance of the sensor varies linearly with temperature over a wide range and is stable over time. The circuitry of the tool is designed so that the voltage across the sensor is proportional to the sensor's electrical resistance. In analog recording, the transmitted spikes per minute are converted to a voltage by a counting circuit.
The Prudhoe Bay field, located on the North Slope of Alaska, is the largest oil and gas field in North America. The main Permo-Triassic reservoir is a thick deltaic high-quality sandstone deposit about 500 ft thick with porosities of 15 to 30% BV and permeabilities ranging from 50 to 3,000 md. The field contains 20 109 bbl of oil overlain by a 35 Tcf gas cap. The oil averages 27.6 API gravity and has an original solution gas-oil ratio (GOR) of about 735 scf/STB. Under much of the oil column area, there is a 20- to 60-ft-thick tar mat located above the oil-water contact (OWC).
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.
There is no generic difference between a "continuous" spinner and a "fullbore" spinner. In the case of the fullbore, the spinner element folds into a diameter no greater than that of the tool when in the tubing, but expands into a larger diameter for surveying in the casing. The continuous spinner does not have this capability. The difference between the two is too small to justify a separate discussion of each. The continuous meter derives its name from the need to move the tool fast enough to overcome frictional torque and start the spinner element rotating. It also derives its name from the in-situ calibration procedure that uses logging runs at several different cable speeds with the well shut-in at the surface. Neither continuous nor fullbore, however, can provide a log that is quantitative whenever the fluid velocity is sporadic, that is, changing in the logged interval. The spinner element can rotate either clockwise or counterclockwise (as viewed down the tool barrel). The direction of rotation depends upon the movement of the fluid relative to the barrel of the tool, that is, upon the direction of fluid movement as seen by "rider" on the tool.
The coiled tubing (CT) injector is the equipment component used to grip the continuous-length tubing and provide the forces needed for deployment and retrieval of the tube into and out of the wellbore. Figure 1 illustrates a typical rig-up of a CT injector and well-control stack on a wellhead. There are several types of counter-rotating, chaindrive injectors working within the industry, and the manner in which the gripper blocks are loaded onto the tubing varies depending on design. These types of injectors manipulate the continuous tubing string using two opposed sprocketdrive traction chains, which are powered by counter-rotating hydraulic motors. Figure 1--CT injector and typical well-control stack rig-up (courtesy of SAS Industries Inc.).