The economic performance of a waterflood or a water disposal project can be significantly affected by suspended solids in the injection water. Here are methods and a theory that can be used to interpret water quality data obtained with membrane filters or cores and to predict well impairment caused by suspended solids. predict well impairment caused by suspended solids. Introduction In a waterflood or a water disposal project the possibility exists that suspended solids will cause the possibility exists that suspended solids will cause the injection wells to become impaired. Filtration can usually reduce the concentration of suspended solids; however, the cost of water treating should be balanced against the cost of other alternatives, such as periodic stimulation or replacement of injection wells. In some cases extensive water treating can be justified, but under other circumstances it will be more profitable to inject untreated water. Water quality is affected by several types of contaminants, including suspended silts, clays, scale, oil and bacteria. Any of these may be the predominant source of improvement in a particular injection water and environment. Formation cores, artificial cores. and membrane filters have been used in the industry to monitor suspended solids and to evaluate water quality. Some studies have defined water quality in terms of filtration rates or other experimental data. The disadvantage of these empirical definitions is that they cannot be directly related to well impairment. This paper proposes a measure of water quality that is defined as the ratio of the concentration of suspended solids to the permeability of the filter cake formed by those solids. The water quality ratio can be obtained directly from membrane or core filtration data and can be used to calculate the rate of formation impairment. Formation Impairment from Suspended Solids In considering the effects of suspended solids, some measure of the rate of impairment is needed. A convenient way to estimate how long an injector can be used before stimulation is required is to calculate its half-life. The half-life is defined as the time required for the injection rate to decrease to 50 percent of its initial value. The time required to reach some other fractional reduction in rate can also be calculated. Impairment from suspended solids is thought to occur by one of the following mechanisms (see Fig. 1):The solids form a filter cake on the face of the wellbore (wellbore narrowing);The solids invade the formation, bridge, and form an internal filter cake (invasion);The solids become lodged in the perforations (perforation plugging); andThe solids settle to the bottom of the well by gravity and decrease the net zone height (wellbore fillup). Each of the four basic impairment mechanisms is modeled in Appendix A for a constant-pressure-drop process, Equations are derived that express the time process, Equations are derived that express the time required for the injection rate to decline to some fraction a of its initial value. For each mechanism, this time can be expressed as the product of the two function, F and G. P. 865
A new approach to stabilizing clays has been developed that uses anoil-soluble surfactant to coat the clays with a tenacious film of oil.Two alternative formulations of the oil-coating treatment an emulsion of diesel oil and an aqueous system consisting of a dispersion of the surfactant in brine have been developed. Introduction In some waterflood operations it is necessary to injectfresh water when a suitable brine is not available or is toocostly. If the reservoir rock contains interstitial clay thatswells and disperses in fresh water, permeability may beimpaired and injection rates may be lowered. Many methods of stabilizing clays are based on ioniccomposition of the water or the use of hydrolyzed metalliccations. This paper describes a new approach to stabilizingclays that uses an oil-soluble surfactant to cause the clays to be coated with a tenacious film of oil.Following laboratory development, the oil-coatingtechnique was field tested. It is an effective andinexpensive method giving protection from fresh-waterimpairment. Two alternative formulations of the oil-coatingtreatment have been developed:an emulsion of diesel oil, containing the oil-wetting surfactant, in brine(referred to as the OC emulsion), andan aqueous systemconsisting of a dispersion of the surfactant in brine(referred to as the OC dispersion). The second method, which uses the residual oil in the formation to coat theclays, is less expensive and is generally preferable.However, it is not effective with certain heavy crudes, forwhich the first method must be used. Both methods areapplied as a batch treatment that affects only a small radiusaround the wellbore. Since the pressure drop decreasesunder conditions of radial flow with the log of the distancefrom the wellbore, a treated zone of about 10 ft isgenerally adequate. Usually, the treatment is preceded by an acid job so that the formation may be cleaned and broughtto maximum permeability before being stabilized. It is recommended that laboratory tests of the treatmentbe made before applying it in a new waterflood. This isbest done by measuring the relative permeability to freshwater of preserved cores from the reservoir at residual oilbefore and after treating with the oil-coating process. Theeffect and comparability of acid and acid additives alsoshould be checked. In principle, the optimum volume oftreatment may be determined by assuming various radii oftreated zones, substituting into the radial flow equationtreated and untreated permeabilities as determined from the cores, and comparing the resultant injection ratesand costs. Laboratory Evaluation of the Oil-CoatingSystems Oil-Coating Emulsion Testing The OC emulsion was formulated with two considerationsin mind:that it should be effective in stabilizingthe clays, andthat it should be fine enough to beinjected easily into the formation. The composition ofthe emulsion is given in Table 1 and the function of eachingredient is as follows. The agent that causes the sandgrains to become oil wet is Redicote 75 TXO, a cationicsurfactant. Another cationic agent, E(11), is added tostabilize the emulsion. A nonionic agent, E(12L), controlsthe fineness of the emulsion. The diesel oil or tolueneprovides a low-viscosity oil to coat the sand grains. JPT P. 1053^
Tests showed that the guar gum and unfiltered bay water contained in some completion fluids were the probable cause of irreversible formation damage. Accordingly, several new fluids were tested. Those systems that have proved successful and are now in routine field use are calcium carbonate-brine and calcium carbonate-hydroxyethylcellulose-brine. Introduction The necessity for higher production rates to supply the increased demand for oil and gas in the U. S. implies a need for unimpaired wells. Most research and development have been directed at simply reducing drilling and workover costs. The energy need is changing this situation by removing prorationing and increasing the value of the oil. Thus we are now more concerned about the effects of drilling and completion practices on well productivity. Although this concern practices on well productivity. Although this concern is not new, until recently its economic significance was insufficient to justify an extensive effort to solve the problem. problem. During 1967, Shell became aware that sand control failures in the Gulf Coast area might be related to well impairment caused by the completion fluids in use at that time. As a result, research and field testing were initiated in order to define the problem and to obtain solutions. We shall describe here some of the results of that research, including the development and testing of several acid-degradable and nondamaging completion fluids. Evaluation of Previous Completion Fluids The completion fluids commonly used by Shell in the Gulf Coast area when the tests were begun werebay water containing 5 percent sodium chloride,filtered bay water containing 5 percent sodium chloride, andbay water containing guar gum and 5 percent sodium chloride. These fluids were used because they were inexpensive, the ingredients were easily obtainable, and they appeared to work satisfactorily. The term "bay water" as used here refers to any untreated surface water available at the well location. It varies from fresh to saline and from clear to brown and turbid in appearance. Salt was added to prevent possible damage to fresh-water-sensitive formations. possible damage to fresh-water-sensitive formations. Guar gum was added for viscosity control to remove sand and drill cuttings from the hole and to reduce fluid loss to the formation. Impairment by Bay Water Solids Laboratory and field tests were conducted on both filtered and unfiltered bay water. It was found that the bay water, which contained clays and other fine solids, severely reduced the permeability of the test core as a result of filter cake formation on the inflow face and deep particle invasion. In general, only 10 to 30 percent of the initial permeability could be regained by simply backflowing with clean brine. Not more than 50 percent of the original permeability could be restored by large-volume treatments of mud acid (over 100 PV).Filtration tests were conducted in the field using 50-, 25-, 10-, 5-, and 2-micron cotton cartridge filters. The tests showed that the 2-micron filters resulted in the lowest rate of impairment, except for water that was filtered with a sand pack. JPT P. 1221
Discussion of this paper is invited. Three copies of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P.O. box 228, The Hague, the Netherlands. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Seawater injection will probably be required to maintain reservoir pressure in most North Sea oilfields. Since there is little published data on North Sea water quality was carried out in the vicinity of the Auk and Brent fields. From these measurements conclusions have been drawn about the filtration and chemical treatment requirements for the seawater that will be injected into the reservoirs of these two fields. Introduction Water injection will be needed to maintain initial reservoir pressure in the Auk and Brent fields and will probably be required in most North Sea oil fields. The Auk project will require about 70,000 b/d injection water and each Brent production platform will require about 250,000 b/d. Because of its greater size, the emphasis of the work was directed towards the Brent field. The most convenient source for injection water is North Sea water taken from below the production platforms and in order to design facilities for filtering and treating this water a knowledge of its quality and its effect on the reservoir is needed. At presented there is no published data on the quality of North Sea water with respect to suspended solids, micro-organisms or scaling tendencies. This paper describes the results of a programme of on-site measurements of North Sea water quality which were made in the vicinity of block 211/29, 90 miles northeast of the Shetland Islands. The objectives of the programme were:To determine the type of chemical treatment needed to prevent corrosion, scaling and bacteriological problems.To find the pump intake depth that yields the best quality water.To determine whether the suspended solids level can be substantially reduced by filtration.To estimate the rate of impairment due to suspended solids that would result in the Brent formation from the injection of either filtered or unfiltered seawater.
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