In stimulation and injection treatments for removing or preventing formation damage, placement of the injected fluids is essential. Throughout the years, several diversion and placement techniques have been applied to obtain a desired fluid placement. A recent development is the application of distributed temperature sensing (DTS) to monitor the temperature profiles along the wellbore in real time during these treatments. Recent case histories showed that fluid placement can be quantified. Quantification of fluid distribution enables one to determine the flow distribution both before and after a diverter stage so that the diversion effect can be quantified. This paper discusses several case histories where DTS was applied to quantify the effectiveness of different diverters. The effects of chemical diverters, such as relative permeability modifiers (RPM) and in-situ crosslinked acids (ICAs), and more traditional diverters, such as rock salt, are discussed. Because of the advanced monitoring used with the temperature profiles, both the immediate and the sustained effect of the diverters can be measured. The changes in the flow distribution are not limited to diverters. Reactive fluid or changes in flow rate can change the flow distribution as well. These effects were measured during the stimulation treatments. The post-treatment analysis of the measured temperature profiles in combination with treatment pressures and flow rate information resulted in accurate knowledge of the effectiveness of the different diverters and stimulation effects over time. This knowledge will be used in future treatments to help optimize volumes, rates, fluid systems, and the selection of the appropriate diverter. Introduction Effective fluid placement and full zonal coverage has been a challenge to the industry. The applications where fluid placement and zonal coverage is important include but are not limited to:Matrix-acidizing treatmentsScale-inhibitor squeeze treatmentsWater-control treatmentsWater injection for enhanced recoveryHydraulic-fracturing treatmentsInjection of sand-consolidation materials This paper focuses on matrix-acidizing treatments, but several of the techniques discussed can also be applied to some of the other applications. During matrix-acidizing treatments, the goal is to remove or bypass damage in the near-wellbore area. Throughout the long history of acidizing, several fluid-diversion and placement techniques have been applied to ensure this goal is achieved over the entire zone of interest. Without effective fluid diversion, the injected fluids will follow the path of least resistance and will only stimulate the zones with the highest permeability, lowest reservoir pressure, or the least damage.
Distributed temperature sensing (DTS) is used on wells to determine the effectiveness of acid treatments. The technology uses a fiber-optic cable to read temperature in real-time, which allows for validation of fluid placement. In the case studies presented in this paper, effectiveness was determined during the pumping of the job. Using this process, the operator was able to decide if a change to the design needed to be made in real-time during pumping. The effectiveness of the acid job was dictated by how effective the fluid was placed into all zones. Concerns related to the acid treatments included where the acid was placed in the well, if the acid went where it was supposed to, and if the acid went into the first least-resistive zone and subsequent zones went untreated. If the latter took place, then investment capital for gallons of acid was not used wisely. The acid treatments included a wide variation of stimulation methods, such as stimulation of the formation using fracturing or matrix rates, varying the acid percentage, varying the type of acid, using linear, gelled, or crosslinked acid, varying the rate, and using diverters. Historically, on acid jobs, surface readings for pressure and rate were the only indicators to judge the effectiveness of the treatment. As the operator attempted the previously mentioned acid treatments and also monitored the treatment using DTS, it was observed that what is seen at the surface can be misleading. This is because surface pressure can be masked by friction and is therefore not a valid indictor for what occurred down hole, and because diversion can take place without surface indication. DTS allowed for practical adjustment to the diversion strategy for the well that was being treated. Candidate selection is highly recommended when using the DTS-number process. Placement of stimulation fluid was and is critical to well stimulation. DTS allowed real-time analysis to determine in real-time if stimulation was effective during the job.
ConocoPhillips drilled and completed three horizontal wells in the Bakken Shale, North Dakota in 2010; these wells contained between 33 and 40 stages. The lateral of each well consisted of a hybrid design using sliding sleeves in the toemost half of the well and plugs/perforations for the heel-most half. Multiple completion techniques were pumped in an alternating pattern throughout the plug and perforation section of each well, and production array logs were deployed on coiled tubing in an attempt to determine fracture design best practices.As one of the key parameters to horizontal well performance in the shale plays, fracture performance evaluation becomes the main objective. The flow contribution from each fracture stage was first determined from array production log interpretations in terms of the in-situ productivity index, which became the basis for fracture stage performance analysis. This paper also includes a discussion of the challenges associated with understanding the multiphase fluid flow behavior in horizontal wells.The subsequent analysis of fracture performance was performed to relate the in-situ productivity index with other well parameters, such as well trajectory, fracture method, fluid and reservoir information around the well and the mud log information during drilling. Oil, gas, and water rates were generated for each stage and correlated to completion technique.The final analysis was aimed to answer some of the questions about how certain fracture stages performed better in comparison to others. This analysis includes identifying parameters in favor of increasing fracture performance and defining the steps needed to deal with the challenges related to the geological nature of the field. The information from this integrated evaluation result was then used to define a better strategy to improve the well performance in the future drilling campaign and to optimize the commercial value of the field. IntroductionConocoPhillips has actively implemented new technology in the counties of McKenzie and Dunn, North Dakota, to improve the recovery of hydrocarbons from the Middle Bakken formation. A project consisting of three horizontal wells was completed in this formation utilizing a hydraulic fracturing application. The project included three wells, which will be referred to as the Bakken #1, the Bakken #2, and the Bakken #3, which are concentrated in the central part of the Bakken Field. All three wells were targeted toward the middle Bakken member.As part of an effort to maintain continuous improvement in well deliverability and hydrocarbon recovery, several fracturing methods were implemented in such a way that will enable us to study and define the most appropriate method for each one of them. Three methods were implemented over different fracture stages for each well. The first two methods were based on a combination of low or high proppant volumes over a single pumping schedule. The third method uses a two-stage pumping schedule with high proppant volume.The results from the various fracture m...
In stimulation and injection treatments for removing or preventing formation damage, placement of the injected fluids is essential. Throughout the years, several diversion and placement techniques have been applied to obtain a desired fluid placement. A recent development is the application of distributed temperature sensing (DTS) to monitor the temperature profiles along the wellbore in real time during these treatments. Recent case histories showed that fluid placement can be quantified. Quantification of fluid distribution enables one to determine the flow distribution both before and after a diverter stage so that the diversion effect can be quantified.This paper discusses several case histories where DTS was applied to quantify the effectiveness of different diverters. The effects of chemical diverters, such as relative permeability modifiers (RPMs) and in-situ-crosslinked acids (ICAs), and moretraditional diverters, such as rock salt, are discussed. Because of the advanced monitoring used with the temperature profiles, both the immediate and the sustained effect of the diverters can be measured. The changes in the flow distribution are not limited to diverters. Reactive fluid or changes in flow rate can change the flow distribution as well. These effects were measured during the stimulation treatments.The post-treatment analysis of the measured temperature profiles in combination with treatment pressures and flow-rate information resulted in accurate knowledge of the effectiveness of the different diverters and stimulation effects over time. This knowledge will be used in future treatments to help optimize volumes, rates, fluid systems, and the selection of the appropriate diverter.
Producing hydrocarbons from the lower Delaware formation in SE New Mexico and West Texas is often associated with high water production. In the Matthews Field in West Texas (Reeves County), an operator was encountering water production of over 600 BWPD (bbl of water per day) from wells that had been treated. The stimulation techniques and processes were modified in an attempt to improve the production results. Multiple stage treatments using coiled tubing (CT) with selective placement controls and reduced rates were performed to lower the fracture height growth. This method included using conventional fracturing fluids, specialized coiled tubing perforating and controlled fracturing placement, and a relative permeability modifier (RPM) capable of reducing the potential for water production by coating the formation rock. This paper will detail how these operations were performed. Introduction The operator has produced a steady production of oil from the Delaware pays in the Matthews Field (Fig. 1) for several years. The production decline in the field was rather flat, with an estimated reserve life of 25 to 30 years. Following the last completions, the average well produces approximately 300 BWPD along with hydrocarbons. Upon acquisition of this field some time ago, a disposal well readily available in the field was used. The produced water was injected into a nonproductive zone in this disposal well. Because the field is remote from the nearest disposal facility, transporting the water to an offsite facility would be expensive. Therefore, use of the disposal well was beneficial. Over time, the high production of water also added significant costs for lifting, additional facilities, etc. The operator obviously needed a method to reduce the water-oil ratio (WOR). The geological makeup of the Matthews Field and the methodology used to derive the applied treatment are covered in this paper. Included as well are (1) a general discussion of how RPMs work, and (2) details regarding the application in this particular case. The stimulation design and treatment is surveyed, including subsequent production results. In addition, an economic analysis of a drilled and completed well in this field is also provided. This paper illustrates how the RPM and other new technology can help decrease the WOR and increase the gas-oil ratio (GOR), thereby adding value for the operator. Geology The pay intervals of interest in this field are the Lower Delaware sands of Brushy Canyon and Cherry Canyon. Cherry Canyon is the more productive and is also noted for its high clay content and high water production. Its primary makeup is fine-grained sandstone with carbonate consolidation.[1] A variety of stimulation techniques has been used in this area, including fracturing with water and foamed fluids energized with either carbon dioxide or nitrogen. In this project, a conventional crosslinked fluid system was used. Stimulation treatments in the Brushy and Cherry sands are usually straightforward, but it is common for significant amounts of sand and water to flow back after treatments. A possible solution to this flowback problem entails pumping resin-coated sand, which has significant bonding capability. Use of this type of treatment in the subject well however was eliminated because of its high cost. Instead, a conductivity-enhancing additive was used to coat the proppant to help prevent sand flowback and fines migration. An RPM was also added to the treatment as a preflush to help combat water production.
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