Temporary Chemical Block Brings Efficiency and Economy to Eastern U.S. Workover Operations

Abstract

Summary Gel plugs (GP's) have been used in the eastern U.S. for many years. They area versatile and simple method of temporarily plugging a well. Gel plugs areoften used to control a well while remedial workovers are performed. This paperdescribes the various types of gel plugs and their applications. Case historiesare given for gel plug applications. Introduction Operators performing workovers on gas-storage wells in the eastern regionsof the U.S. have improved operations and reduced expenses by using GP's tocontrol wells while work is in progress. A large number of the gas-storagewells were drilled in the 1950's and 1960's and have nonstandard equipment thatlimits the use of other wellcontrol methods during the initial stages ofworkover. The GP is a highly viscous fluid that can be crosslinked to form aviscous plug. GP's can be tailored to break back to a less viscous fluid forremoval, or they can be broken by acid. Using this type plug can eliminate theneed for various packers, bridge plugs, and plug can eliminate the need forvarious packers, bridge plugs, and associated surface equipment usually neededto control or "kill" a well while remedial workovers are performed. This paper describes chemistry, operating ranges (temperature), and applicationprocedures pertinent to GP's. Also presented are field case histories where GP's were successfully used to plug a well for running casing inspection logs, to plug a well to permit replacement of tubing and wellhead equipment, and tokill a well temporarily to replace an old wellhead and then place a mechanicalplug for a cement squeeze job or additional workover operations. plug for acement squeeze job or additional workover operations. Background Some eastern U.S. oil and gas wells completed in the 1950's and early 1960'sbecame unable to produce economically when their reservoir pressures anddeliverabilities diminished. In some instances, these depleted zones are beingconverted to storage wells for natural gas. However, many of the casings, tubings, and wellheads designed for the original well conditions are notsatisfactory for the application of gas storage. 1. Many of these wells wereoriginally completed with 5 1/2- or 7-in. casings for the production casing. Toprovide annular integrity in these wells today, it is usually necessary tostore and produce gas through 3 1/2-in. tubing and a packer. 2. Most of thesewells were originally penhole completions. 3. As a result of fluid depletion, many of these wells will not hold the column of fluid necessary to kill thewell during routine workovers, e.g., pulling the tubing and setting amechanical plug. When replacing the tubing, packer, and wellhead assemblybecame necessary, several alternatives were investigated. The options usuallyavailable included kill fluids (e.g., weighted brines) and temporary packerbridge plugs, but because no known packers or bridge plugs could be run inside3 1/2-in. tubing and packers or bridge plugs could be run inside 3 1/2-in. tubing and set in 5 1/2 or 7-in. casings, mechanical methods of pressureisolation were not available. Gas-storage wells have highly predictablepressure patterns; it is easy to determine the pressures necessary to kill thewells. These wells, however, can also lose large volumes of kill fluids whenthe delicate balance of reservoir pressures and hydrostatic pressure isdisrupted. Large volumes of kill fluids lost to the formation can create manyproblems in gas-storage wells, including long cleanup times, increased fluidproduction, and possible fluid introduction into an otherwise dry collectionsystem. Snubbing the tubing and packer is possible, but it is a costly and notreadily attainable packer is possible, but it is a costly and not readilyattainable service. Replacing tubing and wellhead assemblies safely andeconomically while minimizing damage to the production capabilities andgathering systems of the well requires a fluid with special properties. 1. Thefluid must be easy to apply. 2. It should not require special equipment ormaterials for mixing. 3. It should resist forces from both formation andhydrostatic pressures. pressures. 4. The fluid should work over the lowtemperature range (60 to 100 degrees F) for these particular applications. 5. It must mix in a wide variety of waters. 6. It must have predictable anddependable fluid properties. 7. The fluid should break back to a fluid verynear to the viscosity of the base mixing fluid. 8. It must leave little residueupon break to minimize formation damage. These properties were incorporatedinto a fluid that can easily be pumped as a thin fluid to the zone of interestbefore becoming thickly gelled. Once gelled, this GP protects the producingzone by minimizing fluid loss to the formation; this allows the killing ofwells for tubing or wellhead replacement and well logging, while keepingformation damage to a minimum. Several cases exist in which a zone requiredisolation and temporary GP's were applied as an efficient and economicalsolution to the problem. The chemical nature, placement technique, andapplication of the technique are described. Geology The case histories discussed in this paper are from jobs located in West Virginia, Ohio, and Indiana. The West Virginia jobs (case history Wells 1 and2) were performed in the Big Injun and Oriskany formations, which represent the Mississippian and Lower Devonian, sands of the Appalachian sedimentary basin, respectively. The Appalachian sedimentary basin covers about 175,000 sq miles, and consists of the Pennsylvanian, Mississippian, Upper and Lower Devonian, Silurian, Ordovician, and Cambrian ages. The sediments contained represent theentire Paleozoic section from Permian through Cambrian, with a thickness of30,000 ft. Permian through Cambrian, with a thickness of 30,000 ft. Sedimentaryvolume is estimated to be 500,000 cu miles. The upper portion of the Mississippian in West Virginia and eastern Kentucky is composed of fluvialsandstones that produce gas from stratigraphic traps. Underlying these classicsis the Greenbrier limestone, commonly identified by drillers as the "BigLime" in West Virginia. Stratigraphic reservoirs composed of oolitic zonesin southern West Virginia and eastern Kentucky produce gas; in central West Virginia, however, the porosity zones are composed of dolomite, sandy dolomite, and sandstone, which are called "Big Injun" or just "Injun."The Lower Devonian includes Oriskany sandstone, which produces gas with onlysmall amounts of oil and condensate. Structural traps are productive in the Overthrust Belt of eastern West Virginia and adjacent Pennsylvania. While someof these structural entrapments are partly stratigraphic, the Oriskanyproduction in the large Elk-Poca field in west-central West Virginia isentirely stratigraphic as a result of westward pinchout of the sandstone. SPEPE P. 70

New Stimulation Technologies in a Major Gas Field in the Middle East

“…The chemical plug is used to provide temporary isolation while the CT places the stimulation treatment into the target zone. This application enables a more flexible movement for CT and easier removal of the plug once it is not needed, using common breakers like acids and oxidizers [6][7][8] . …”

Experimental study of polyacrylamide gel in close‐in well operation

“…In the process of polymer gel degelling, the structure of gel network bonds between polymer and crosslinker is broken by the degelling agent . Some successful close‐in operations by using the polymer gel were reported in the United States and Russia …”

“…10 Some successful close-in operations by using the polymer gel were reported in the United States and Russia. 11,12 Considering the importance of close-in well operations and the harsh condition of Iranian well, in this study, design and preparation of a polymer gel system were investigated. Efforts have been done to produce a polymer gel which in case of placing under the column of fluid on it, diesel fuel, or formation water, it could plug the well (for approximately a week) without any permission to any fluid to be able to pass through it ( Figure 1).…”