Prolonged chemical inhibition is the desired outcome from placing a solid inhibitor in a formation during the fracturing process. Traditionally liquid inhibitors applied through a squeeze have provided inhibition for up to one year and sometimes longer. Deepwater operators, especially, desire longer inhibition periods. This paper reports on new fracture compatible chemistry that has been applied on over five hundred wells for the inhibition of mineral scale. It also reports on similar products for the inhibition of paraffin and asphaltene. These applications have been in deepwater, tight gas and coal bed methane formations. The longest documented treatment has been in the ground for over three and a half years. The highest cumulative water production with acceptable scale inhibitor residuals has been over 1,000,000 bbls of water. Placing a solid chemical inhibitor into the formation via the fracturing process requires a product that is compatible with the fracturing fluid, does not adversely affect conductivity and provides long term inhibition through the controlled release of the inhibitor into the produced fluid. The solid inhibitor is added to the fracturing proppant. Primarily this is a mass-balance process by which a finite amount of inhibitor desorbs over time. The goal is to maximize the inhibitor loading and minimize the chemical release rate without negatively impacting the stimulation. In the treated wells, inorganic and organic deposition has been arrested for extended periods when compared to alternative liquid addition applications. This is a direct result of the placement of the inhibitor in the formation during the fracturing process. All wells have shown inhibition, as measured by produced fluid sample analyses. All operators with deposition potential must undertake significant remedial intervention measures. This new chemical technology extends the life of a chemical inhibitor placement beyond traditional expectations. The advancement of this technology has reduced deposition-related failures and reduced well intervention costs. Introduction This paper presents a production chemical technology that is added as a solid particle to the proppant in a hydraulic fracture. The purpose of the addition is to provide long term inhibition of scale, paraffin or asphaltene. Current research is underway to develop salt and corrosion inhibitors adsorbed onto a solid particle. By adding the product during the fracture, the chemicals are present at the initial point of pressure drop in the formation that occurs at the fracture/formation interface. By inhibiting at the initial point of potential mineral or organic deposition, the fluid is protected throughout the time spent in the formation, at the near well bore, in the production tubulars and through the surface facilities. The mitigation or elimination of down hole deposition reduces LOE (lease operating expense) and reduces NPT (non-productive time), thus improving lease economics. A fracture fluid has several functions, all of which need to be accomplished within a relatively short time. The fluid must offer viscosity and then break the viscosity. It must control fluid leak off. It must maintain a prescribed pH range in order to achieve the viscosity. Any additional component added to a fracture fluid must be examined for any potential distortion of the primary functionality of the fluid. For that reason all solid production chemicals added to the fracture must be examined for fluid compatibility.
Within the past decade, hydraulic fracturing has been proven to improve the efficiency and economics of recovering oil and natural gas from shale formations. In a previous paper (SPE 134414), a summary of treatment results of placing a solid scale inhibitor into formations via the fracturing process for over five years and in over 1500 wells was fully discussed. The practice of hydraulic fracturing has come under scrutiny due to concerns about the environmental impact, health and safety. Therefore, a novel biodegradable solid scale inhibitor with an excellent ecotoxicity profile for fresh water incorporated into a solid matrix was recently developed and deployed in North Dakota. For one operator in this area with 150 Bakken-producing wells, 22 of the wells have experienced at least one event of severe mineral scaling in the pump and production tubing, leading to well failure, whereas the results from over 140 Bakken wells now fractured with the new solid inhibitor additives indicate no reported scale failures to date. This paper provides a detailed description of the first deployment of this environmentally preferred proppant-sized solid scale inhibitor additive under severe scaling conditions in the field. In addition, an analytical method developed to track the residual of this additive in the produced fluid containing polysaccharide contaminants is also discussed.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractProlonged scale inhibition in excess of one year is a desirable benefit of oil and gas well formation squeeze treatments. Traditionally liquid inhibitors have given the requisite inhibitor residual for up to one year. Operators desire longer inhibition periods. This paper describes a new scale inhibitor technology that extends scale inhibition beyond one year.All of the components of a hydraulic fracturing package must be compatible to insure that the rheology of the fluid is not affected. The placement of a scale inhibitor onto a formation requires a suitable inhibitor that will adsorb to the mineral surfaces and return slowly with the produced water. Adding a solid scale inhibitor to a frac package required limited compatibility testing and reformulation in order to meet the fluid integrity and product effectiveness criteria. The scale inhibitor dosage was designed for a three-year life.The accepted method of monitoring the effectiveness of a scale inhibitor squeeze is through measuring the scale inhibitor residual in the produced water. Traditional liquid scale inhibitors give a high initial residual (>1000-ppm) and deplete to a minimal level (1-10 ppm) within a year. The solid inhibitor placed on the formation during the frac released a residual below 50 ppm at the first reading and has maintained an acceptable level for the life of the placement (as of this writing the residuals are still above the minimum level).Operators of offshore and remote area wells that are prone to scale deposition must undertake significant intervention measures to remediate scale deposition. 1 This new chemical technology extends the life of a scale inhibitor placement beyond the current expectations. The advancement of this technology will save operators money and encourage the development of properties that might be viewed unprofitable due to the high frequency and cost of intervention.
Solid chemical inhibitors placed in the formation during hydraulic fracturing have provided inhibition protection for up to five years. Deepwater operators, especially, desire longer inhibition periods. This paper provides a summary on treatment results over five years and over 1500 wells. It covers inhibition for scale, paraffin and asphaltene either as a single application or as a multiple product application. These applications have been in various formations including deepwater, tight gas and coal bed methane formations. The longest documented treatment has been in the ground for over five years.Placing a solid chemical inhibitor into the formation via the fracturing process requires a product that is compatible with the fracturing fluid, does not adversely affect conductivity and provides long term inhibition through the controlled release of the inhibitor into the produced fluid. The solid inhibitor is added to the fracturing proppant. Primarily this is a mass-balance process by which a finite amount of inhibitor desorbs over time. The goal is to maximize the inhibitor loading, minimize the chemical release rate without negatively impacting the stimulation.In the treated wells inorganic and organic deposition has been arrested for extended periods when compared to alternative liquid addition applications. Solid scale inhibitors have been the most common treatment and are monitored through residual analysis. The paraffin and asphaltene inhibitors are monitored through comparative testing. The paper details both the time and the cumulative production that has flowed through the respective proppant packs.Wells that are scheduled for hydraulic fracturing and that display tendencies for organic and/or inorganic deposition are candidates for solid chemical placement during the fracture. The results from over 1500 wells indicate that this method for deposition inhibition reduces intervention costs and lowers lifting costs.
Multi-year scale inhibition is the desired outcome from placing a scale inhibitor composite in a formation during the fracturing process. Traditionally liquid inhibitors applied through a squeeze have provided inhibition for up to one year. Deepwater operators, especially, desire longer inhibition periods. This paper reports on the twenty-four wells that have been treated for at least sixteen months. It also details the inhibition for two deep water wells that have been on line for about one year. At the time of the publication of the paper over five hundred wells have been treated with the solid inhibitor. The longest documented treatment has been in the ground for over three years. Placing a scale inhibitor composite into the formation via the fracturing process requires a product that is compatible with the fracturing fluid, does not adversely affect the conductivity of the proppant pack and provides multi-year inhibition through the controlled release of the inhibitor into the produced water. The solid inhibitor is added to the fracturing proppant. Primarily this is a mass-balance process by which a finite amount of inhibitor desorbs over time. The goal is to maximize the inhibitor loading without negatively impacting the stimulation effectiveness. Mineral scale deposition in the treated wells has not occurred in the time since the initial stimulation and inhibitor placement. In all wells, but especially for deep water wells where subsequent intervention represents a significant cost, this technology has financial benefit compared to traditional treatments. All treated wells continue to show scale mitigation, as measured by inhibitor residual in the produced water. Mineral scale deposition in wells means costly well remediation. This means decreased production and workover costs. It has an adverse impact on lifting costs. This chemical technology advancement extends the period between remedial workovers well beyond traditional expectations. It will save operators money and may encourage the development of fields that might otherwise be viewed unprofitable or marginal. Introduction Below is a brief discussion on scale inhibitor work reported upon in previous SPE papers. These all involve the addition of a scale inhibitor as a bulk fluid or solid. Only papers that reported on post-treatment measurement of scale inhibitor residual as a function of time or cumulative water production are shown. These papers report on the addition of scale inhibitor asa liquid squeeze separate from a hydraulic fracturea liquid inhibitor in a hydraulic fracture fluida solid inhibitor in a hydraulic fracture fluid These are presented as a representation of the evolution in the industry towards gaining prolonged inhibition through a single application. These bulk placements are done for two reasons. First, it is not always possible to treat for scale with a continuous treatment fed into the well bore. Second, it is preferable to place the inhibitor in the formation in order to prevent scale precipitation in the formation and to have the inhibitor in the produced water before that water reaches the pressure drop zone (zone of scale precipitation) at the near well bore. Martins (1992) reports on the addition of a liquid scale inhibitor in a hydraulic fracture fluids in Alaskan wells Alaska at Prudhoe Bay. They report on the treatment of 75 wells all of which reported acceptable inhibitor residuals up to and beyond one year. The paper shows data on acceptable inhibitor residuals after 200,000 bbls of cumulative water production on a typical well. Norris (2001) reports on the addition of a SIIP (scale inhibitor impregnated proppant) to a well in the British sector and a well in the Norwegian sector of the North Sea. For the first they report 55 days of acceptable inhibitor residuals. For the second they report 33,000 bbls of cumulative water production with acceptable residuals.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.