Removal and Inhibition of Calcium Sulfate Scale in Waterflood Projects
- C.F. Smith (Dowell Div. Of Dow Chemical Co.) | T.J. Nolan III (Dowell Div. Of Dow Chemical Co.) | P.L. Crenshaw (Dowell Div. Of Dow Chemical Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- November 1968
- Document Type
- Journal Paper
- 1,249 - 1,256
- 1968. Society of Petroleum Engineers
- 5.4.1 Waterflooding, 2.2.2 Perforating, 3.2.4 Acidising, 4.3.4 Scale, 5.2 Reservoir Fluid Dynamics, 2.4.3 Sand/Solids Control, 4.2.3 Materials and Corrosion, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 3.4.1 Inhibition and Remediation of Hydrates, Scale, Paraffin / Wax and Asphaltene, 6.5.2 Water use, produced water discharge and disposal, 5.6.4 Drillstem/Well Testing, 4.1.2 Separation and Treating, 1.8 Formation Damage, 2.2.3 Fluid Loss Control, 2.7.1 Completion Fluids, 2.5.2 Fracturing Materials (Fluids, Proppant)
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The problem of preventing calcium sulfate scale deposition has become increasingly important in the last few years due to the increasing use of waterflood as a means of secondary recovery. Many methods have been proposed for removing or preventing scale deposition. A few chemicals and treatment methods have been effective, but there are many ineffective scale-removal agents and inhibitors still an the market today. This paper describes the results of a laboratory testing program that evaluated 98 potential-scale inhibitors and 20 scale-removal agents. The paper also describes a field testing program in which various removal methods and inhibitor placement techniques were evaluated in 19 wells, and it compares field and laboratory results.
Deposition of inorganic scale in producing wells has been a costly problem in the petroleum industry. Scale not only restricts production, but causes inefficiency and failure of production equipment. Scale problems have an even greater impact on the economics of waterflood operations where injection wells are subject to deposition of inorganic sulfate and carbonate deposits.
Scale control usually involves complementing treatments that first remove the deposited scale, then chemically prevent its recurrence. There is no effective all-in-one treatment that will both remove and inhibit scale deposits. In many cases, scale control must begin with a program of inhibition since some inorganic scales are difficult - even impossible - to remove by chemical treatment once they form. These scales, usually containing barium or strontium can be prevented from forming by proper use of inhibitors. Fortunately, most scales occurring in producing formation are calcium sulfate or calcium carbonate. These deposits normally can be removed chemically before further treatment to prevent recurring scale deposits is begun. Scale composition frequently changes during the production history of the well, causing many scales that are initially subject to removal treatments to become unresponsive to subsequent treatment. This makes it imperative to obtain the best scale-removal treatment possible before the scale inhibition program is started. Samples of the deposit need to be collected and analyzed to determine the proper treatment.
Two techniques have been used to place inhibitor in the formation. One technique involves placing slowly-water-soluble polyphosphate crystals in the formation by hydraulic fracturing. The polyphosphate limits the choice of fracturing fluid since it is sensitive to acid or heavy brine and reverts to inactive calcium orthophosphate. Liquid phosphonate inhibitors also have been placed during fracturing operations with the expectation that they will leak off and adsorb to the rock matrix. Using liquid inhibitors in fracturing treatments will prevent scale deposition, but this is a comparatively expensive method of replacing inhibitor unless a fracture job is already planned for remedial stimulation. The second placement method is a matrix squeeze technique in which liquid inhibitors are injected into the formation at subfracturing pressures. This method is becoming increasingly popular because it is frequently undesirable to fracture the formation in a waterflooding operation. In addition, this technique is cheaper than fracturing.
There are many chemicals that will prevent scale deposition. However, most will not remain in the formation long enough to make them economically feasible as inhibitors. To improve the economics of inhibitor squeeze treatments, a thorough laboratory investigation was undertaken to select the best scale inhibitors and determine what changes would be necessary to improve their formation longevity. This investigation was followed by a field development program in which removal chemicals, scale inhibitors, and treating techniques were evaluated on a cost-to-performance basis.
The laboratory phase of the program necessarily began with a study of scale compositions and the downhole physics-chemical relations that cause deposition.
The major components of most oilfield scale deposits are calcium carbonate, calcium sulfate, and/or barium sulfate. Other components that occasionally are found include strontium sulfate, strontium carbonate, barium carbonate and magnesium carbonate. Corrosion products are found such as iron oxide, iron sulfide, and, occasionally, pyrite; however, these deposits do not occur so much from equilibrium changes in the system as from corrosive environments. Bacterial residues also are found frequently in conjunction with inorganic scale in water injection wells.
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