Multistage Fracturing System: Improving Operational Efficiency and Production

Drilling technologies are constantly being developed as operators push the envelope limits to maximize reservoir contact and increase hydrocarbon recovery. These advancements in well construction challenge the well intervention community to seek innovative solutions to successfully intervene in these wells. This paper discusses the successful combination of a slim OD measurement-while-drilling (MWD) tool run on coiled tubing (CT) for real-time survey of the open hole lateral wellbore, followed by a stimulation treatment at appropriate depths for all laterals in a single CT run.Saudi Arabia has been in the forefront of maximum reservoir contact well construction with the drilling of multilateral open hole gas wells; thus, the need for CT operations to enhance current offerings and procedures. For this application, several tests were performed to determine the feasibility of the combination of necessary tools to be able to steer, identify, and pump the stimulation treatment in a single run. MWD tools were run on CT in this multilateral gas well, and the stimulation treatment was performed during the same CT run.The common practice in the study area was to run in hole down to total depth (TD) and determine, only by depth difference, in which lateral the CT was located. The uncertainty level increased exponentially when TDs of the laterals were within hundreds of feet because the treatment could potentially be performed in an alternate lateral, rather than the one intended (Ref 1-5). With the use of MWD tools that can relay inclination, azimuth, orientation (steering capacity), pressure and gamma ray, all this uncertainty is eliminated to help ensure a positive lateral identification for proper treatment placement in the well.The MWD tool run on coiled tubing (CT), implemented a procedure explained in this paper to eliminate the uncertainty associated with previous technologies used for in real-time CT positioning inside the wellbore. The CT position is now reliable verified by survey match with real time readings from CT tip, allowing the certification of job placement in the desired wellbore path, to complete the intervention associated to the CT intervention; i.e.,: "a stimulation treatment" to be done specifically and independently for all laterals in a single run on each. This project open the doors for many other MWD-guided CT interventions to be applied in such conditions.

Recent advances in drilling technology have resulted in longer horizontal wells being drilled to more efficiently exploit reservoirs. However, these long open hole horizontals are often problematic when using coiled tubing as the well intervention conveyance system during stimulation. Coiled tubing, a commonly used intervention tool for open hole horizontals, is considerably less stiff than jointed drill pipe and cannot reach TD on many wells due to friction. Assistance from friction reducers, well tractors or other devices have helped, but can be potentially damaging, expensive and/or high risk. This poster details the use of a simple agitation tool placed in the coiled tubing bottom hole assembly during the stimulation. This results in decreased friction which in turn increases reach for coiled tubing thereby allowing full horizontal open hole stimulation treatment. The case study that is presented on the performance of the agitation tool used in coiled tubing stimulations in long horizontal open hole sections of a hot, sour reservoir with a total measured depth up to 7 kilometers. Suncor Energy has utilized this process in the development of its Panther River reservoirs in the Western Canadian Sedimentary Basin with excellent results. Benefits discussed include reduced completion cost and reduced environmental impact.

A number of production logs in the Troll Oil production wells have been performed. Horizontal screen sections up to 2000 m required logging tool deployment by coiled tubing. All wells flowed monophase oil. Practical correction procedures for the logs are proposed. The corrections cover annular flow between screen and open hole, coiled tubing displacement flow, coiled tubing influence on drawdown and productivity due to reduced flow area. The correction procedures are essential for interpretation of individual layer productivities, which is demonstrated on field examples. Introduction The Troll Oil field is located in 300 m water depth offshore Norway. The field is characterized by a thin oil zone (13–26 m) sandwiched between a large gas cap and active aquifers. The reservoir contains several highly permeable unconsolidated sands separated by low permeability micaceous sands. Impermeable calcite layers occur within the high permeable sands. Several publications describing the Troll Oil horizontal well development are available. The production logs performed on the Troll oil wells had two main objectives:verify cleanup of the well after setting of kill pill,determine the productivity and permeability profiles along the well. In long horizontal wells with small drawdowns (a typical value during logging at 2000 Sm3/d of the Troll Oil wells is 0.2 Bar), the production log analysis is not straightforward, and a number of corrections to the measured data must be performed to obtain representative production inflow profile along the completion interval. The most important corrections identified for the Troll Oil wells are (1) coiled tubing displacement flow, (2) coiled tubing influence on drawdown and productivity due to reduced flow area, and (3) annular flow between screen and open hole. In addition water or kill fluid accumulation at low points in the well may corrupt the spinner flowmeter response. This paper discusses possible methods to correct for these effects. A possible disturbance of the velocity profile in the screen due to radial inflow has not been accounted for. Mathematical Modeling Fig. 1 and 2 show the flow in the screen section with and without coiled tubing present. To understand the influence of the coiled tubing mass and momentum balance of a horizontal well section with and without a coiled tubing is required. The analysis is similar to that performed by Dikken, with the addition of the acceleration pressure drop and the coiled tubing effects. Mass Analysis. From Fig. 3 the following mass balance equations are obtained for a control volume with coiled tubing partly inserted (1) or, equivalently, (2) For a control volume without coiled tubing we get (3) P. 699

Successful reservoir surveillance and production monitoring is a key component for effectively managing any field production strategy. For production logging in openhole horizontal extended reach wells (ERWs), the challenges are formidable and extensive; logging these extreme lengths in a cased hole would be difficult enough, but are considerably exaggerated in the openhole condition. A coiled tubing (CT) logging run in open hole must also contend with increased frictional forces, high dogleg severity, a quicker onset of helical buckling and early lockup. The challenge to effectively log these ERWs is further complicated by constraints in the completion where electrical submersible pumps (ESPs) are installed including a 2.4" bypass section. Although hydraulically powered coiled tubing tractors already existed, a slim CT tractor with real-time logging capabilities was not available in the market. In partnership with a specialist CT tractor manufacturer, a slim logging CT tractor was designed and built to meet the exceptional demands to pull the CT to target depth. The tractor is 100% hydraulically powered, with no electrical power allowing for uninterrupted logging during tractoring. The tractor is powered by the differential pressure from the bore of the CT to the wellbore, and is operated by a pre-set pump rate from surface. Developed to improve the low coverage in open hole ERW logging jobs, the tractor underwent extensive factory testing before being deployed to the field. The tractor was rigged up on location with the production logging tool and ran in hole. Once the coil tubing locked up, the tractor was activated and pulled the coil to cover over 90% of the open hole section delivering a pulling force of up to 3,200 lb. Real-time production logging was conducted simultaneously with the tractor activated, flowing and shut-in passes were completed to successfully capture the zonal inflow profile. Real-time logging with the tractor is logistically efficient and allows instantaneous decision making to repeat passes for improved data quality. The new slim logging tractor is the world's slimmest most compact, and the first of its kind CT tractor that enables production logging operations in horizontal extended reach open hole wells. The ability to successfully log these extended reach wells cannot be understated, reservoir simulations and management decisions can only as good as the quality of data available. Some of the advantages of drilling extended reach wells such as increased reservoir contact, reduced footprint and less wells drilled will be lost if sufficient reservoir surveillance cannot be achieved. To maximize the benefits of ERWs, creative solutions and innovative designs must continually be developed to push the boundaries further.

At present, hundreds of horizontal wells have been drilled in Hassi Messaoud counting for about one fourth of the field's output. Among these, several wells are underperforming and could not yield the expected production. Vertical and areal permeability anisotropies, absence of natural fractures, severe heterogeneity, reservoir damage and wellbore instability are the main factors to blame for poor productivity. To address the problem of poor vertical communication and get past the near wellbore damage, hydraulic fracturing has been thought of as the best solution to improve productivity. This paper describes the candidate selection criteria, the design and execution of the first fracturing job to be carried in a horizontal well. A new openhole completion system is to be deployed in the horizontal section. The system uses a series of mechanical openhole packers that allow for stimulation in each desired interval. The use of mechanical packers provides positive mechanical diversion at high differential fracturing pressures. In this case the horizontal drain has been divided into six sections. Three of them have been hydraulically fractured while the remaining sections characterized by natural fractures are producing naturally by simply opening the frac port. The system has been designed, so the fracturing treatments along the horizontal wellbore can be pumped in one continuous operation, thus minimizing the associated risks and optimizing the efficiencies of both personnel and equipment needed to perform the work. In this case the pumping operation has been successfully performed in less than 48 hours with no operational issue. The first operation has proven the feasibility to set multiple hydraulic fractures in openhole horizontal wells in Hassi Messaoud field. The drastic production increase demonstrates how the multiple fractures allow improving the vertical and areal drainage of the reservoir for this type of wells. The article presents all the project phase from candidate selection, design to job execution. It also highlights the risks involved with regard to many aspects during the project. Finally, the paper summarizes some lessons learned and draws suggestions for prospective candidate wells. Introduction The Hassi Messaoud reservoir has been on stream since 1958. Currently, it produces about 65 Mm3/D of 45°API oil from a thick Cambro-Ordovician sandstone formation. The structure is a flattened anticline with a sequence of horts and grabbens contained by faults in a submeridian direction. The faults are generally oriented SSW to NNE and cross the entire reservoir. The depositional environment is fluvial at the bottom to marine at the top. The shaly sandstone contains silt interbeds which have a thickness between 0.2 and 0.4 m with a metric to kilometric lateral extension. The reservoir is naturally fractured in some parts because of tectonic activity. Fractures are either open or plugged with materials such as shale, silica, anhydrite, pyrite, and bitumen. The reservoir is subdivided into four distinct formations—Ri, Ra, R2, and R3—in addition to a zone of alternance with Ra-Ri and R2 being the main and secondary reservoirs respectively. The producing Ra-Ri is subdivided into six intervals: D5, D4, D3, D2, ID, and D1. The reservoir has a porosity ranging from 6 to 12 %. Overall, the permeability is low with a range from less than 1 to more than 100 md in open-fissures layers. The reservoir was initially undersaturated with an oil saturation of about 80%. The reservoir was subdivided into productive zones. Most zones are under miscible gas flooding. Five zones are under water injection. Up until 1995, the reservoir was developed using vertical wells. Along with matrix treatments, hydraulic fracturing is extensively used with more than 300 wells already treated to compensate for low permeability or to bypass nearby wellbore damage. Gaslift is used for production activation throughout the field.

Historically, cemented plug and perf completions have been used for wells requiring multistage fracturing and stimulation in the North Sea. This is a well-known and trusted process, but also time consuming. Often the turnaround time per stage in the North Sea is 3-7 days. With high rig and frac vessel rates, this excessive operational time can negatively impact project economics and well payback times. Consequently there is a drive to develop new systems to gain efficiencies without compromising the quality of the planned stimulation treatments in these applications. This paper will review two newly developed novel completion systems that significantly reduce time spent performing multistage stimulation in environments where cost and consequence of failure are high. North America land frac operations rely heavily on ball drop actuated frac sleeve systems now commonly available in the market, however these typically require some over displacement of the previous frac stage and typically are only available for un-cemented liners. Hence, these are not always a good fit for North Sea frac applications. In order to prevent compromising the required stimulation treatment and allow flexibility to run cemented reservoir liners with frac valves, new technologies had to be developed. Both coiled tubing and wireline manipulated sliding sleeve/valve systems and ball-drop actuated systems have been developed and deployed depending on the various completion and stimulation challenges faced. Since the first installation in 2009 these systems have been proven and refined in multiple wells for two large operators. Various well installations will be discussed, illustrating that systems are being tailored for open hole and cemented environments both for proppant and acid frac stimulation treatments. The paper will give the audience insight into the depth of options available with these systems and explain how they are tailored for different types of stimulation and zonal isolation requirements. In addition operational considerations and experience will be shared. Testing and field data will be presented to verify the development, installation, operation and success of these systems. This data include pressure and temperature data, downhole monitoring during stimulation and sleeve manipulation. An overview of the results and efficiencies achieved in the installations will be presented and compared to conventional methodologies. These completion solutions have a broad application in areas where fracturing and stimulation is required and project cost and risks are significant, both in conventional and unconventional stimulation and fracturing operations. The installations discussed in the paper include first ever proppant frac done offshore through these systems, and introduction of specially developed intervention tools to aid the operation of the system. It also covers the first ever successful installation of cemented frac valve reservoir liner completions in an offshore environment as well as the use of dissolvable frac balls.

Several extended reach-restricted completion-smart wells required matrix acid stimulation using Coiled Tubing (CT). These wells are equipped with Mechanical Formation Isolation Valve (MFIV) in the tubing end which needs to be reopened by using CT to access mother-bore for performing acid job. CT simulation results for these wells showed coil can reach only 60-70% of open hole interval. Calibrated friction coefficients were used in CT simulation based on the data base developed from other wells in the same area. Only CT-Tractor simulation showed 100% reach with maximum tractor over pull of 3200 lbs from the lock-up depth. World’s slimmest CT tractor was developed in collaboration specifically to address the challenges of extending CT reach past lock-up depth during acidizing and other intervention jobs in minimum restriction extended reach well. The world’s slimmest tractor (2 1/8" outside diameter; OD) was able to provide a pulling force of 3200 lbs and was powered by intervention fluid pumped through coiled tubing. The tractor has many failsafe features and self-cleaning mechanism of gripper arms to overcome the challenges encountered while tractoring in open hole. Four smart wells (with minimum restriction 2.81") were successfully matrix acid stimulated while the CT-Tractor combination were able to extend the reach of CT beyond lock-up depth. CT-Tractor was run-in-hole (RIH) to lock-up depth and then tractor was activated from that depth to extend the reach of CT. At total depth (TD), the tractor was isolated and de-activated by dropping steel ball. The wells were acid stimulated while pulling-out-of-hole (POH). Pre-flush was pumped while RIH at low pumping rate to avoid activating tractor before lock-up depth and after lock-up, pre-flush was pumped through tractor to activate the tractor. This paper outlines the tractor characteristics, matrix acid stimulation jobs design parameters, detailed operational data captured and the learning curve achieved during job execution.

The paper discusses the pilot project in ADNOC Offshore to assess the Autonomous Inflow Control Device (AICD) technology as an effective solution for increasing oil production over the life of the field. High rate of water and gas production in horizontal wells is one of the key problems from the commencement of operation due to the high cost of produced water and gas treatment including several other factors. Early Gas breakthrough in wells can result in shut-in to conserve reservoir energy and to meet the set GOR guidelines. The pilot well was shut-in due to high GOR resulted from the gas breakthrough. A pilot project was implemented to evaluate the ability of autonomous inflow control technology to manage gas break through early in the life of the well spanned across horizontal wellbore. And also to balance the production influx profile across the entire lateral length and to compensate for the permeability variation and therefore the productivity of each zone. Each compartment in the pilot well was equipped with AICD Screens and Swell-able Packers across horizontal open hole wellbore to evaluate oil production and defer gas breakthrough. Some AICDs were equipped with treatment valve for the compartments that needed acid simulation to enhance the effectiveness of the zone. The selection factors for installing number of production valves in the pilot well per each AICD was based on reservoir and field data. Pre-modeling of the horizontal wellbore section with AICD was performed using commercial simulation software (NETool). After the first pilot was completed, a detailed technical analysis was conducted and based on the early production results from the pilot well showed that AICD completions effectively managed gas production by delaying the gas break through and restricting gas inflow from the reservoir with significant GOR reduction ±40% compared to baseline production performance data from the open hole without AICD thus increasing oil production. The pilot well performed positively to the AICD completion allowing to produce healthy oil and meeting the guidelines. The early production results are in line with NETool simulation modelling, thereby increasing assurance in the methods employed in designing the AICD completion for the well and candidate selection. This paper discusses the successful AICD completion installation and production operation in pilot well in ADNOC Offshore to manage GOR and produced the well with healthy oil under the set guidelines. This will enable to re-activate wells shut-in due to GOR constraint to help meeting the sustainable field production target.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189910, “Operational Improvements Using a Coiled-Tubing-Telemetry System for a Complex Milling Operation in Shut-In Conditions,” by P. Correa, D. Parra, S. Craig, SPE, S. Livescu, SPE, A. Yeginbayev, and Z. Nadirov, Baker Hughes, a GE Company, prepared for the 2018 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 27–28 March. The paper has not been peer reviewed. When a new horizontal well in Asia was incapable of unassisted flow, coiled tubing (CT) was selected for the perforation and stimulation intervention. Mechanical isolation was required to ensure that the stimulation fluids entered only the new zones. Accurate depth control was required for three runs: setting two composite bridge plugs (CBPs), deploying CT-conveyed perforating guns for opening two intervals, and milling out the two CBPs without taking returns to surface. For the first time, a tension, compression, and torque (TCT) subassembly was used to improve the milling operation. Introduction CT telemetry (CTT) systems have proved to be effective in enhancing operations by providing real-time monitoring of downhole data including depth, pressure, temperature, force, and torque. For data transmission from downhole sensors to surface, these telemetry systems can use either insulated wire or optical fiber. With insulated wire, power can be transferred from surface to the downhole sensors. With optical fiber, downhole batteries are required in the bottomhole assemblies (BHAs) to power the downhole sensors. When compared with braided systems using the 0.125-in. insulated electrical cable (Fig. 1), the main advantages of the CTT system are its low weight and the fact that balls can be pumped through the CT. A small wire has a minimal effect on the CT cross-sectional area. Balls up to 7/8 in. in diameter do not become stuck, and there is a minimal effect on the CT fluid pressure drop. Description of the Wire CTT System The 0.125-in.-wire CTT system has several components, such as surface hardware and software; the ⅛-in. insulated electrical conductor inside the CT string; and a BHA with different sizes, including 2.125, 2.875, and 3.5 in. The 2.875-in. BHA with three subassemblies is shown in Fig. 2. The 2.875-in. sensor assembly has the following components: Tubing end connector Head that secures the wire downhole, seals the exterior of the wire, and provides downhole electrical connection 0.875-in. ball-operated wire-release mechanism Double-flapper check-valve housing Electronic module with a casing collar locator (CCL) and pressure/temperature sensors (internal/external) Motorhead section, where a ¾-in. ball-release mechanism is located followed by a circulating port activated with 0.625-in. balls Burst-disk section enabling 0.5-in. balls to pass through to activate downhole tools

In parts of South Texas, the cementing of long drilling and production liners has long been one of the most challenging aspects of well completion. High formation pressures require mud and cement weights that approach the equivalent fracture gradient of the exposed open hole interval. Very low pump rates and excessively long job times have been common due to the constraints imposed by tight annular clearances and the use of heavy, viscous cement slurries. Another problem associated with these wells is the temperature gradient in this area. Geothermal gradients of 2 deg.F / 100 ft. create large temperature differentials from liner top to bottom, even with liners of only moderate length. Consequently, developing TOL compressive strength and adequate seal at the liner lap has been difficult with the cement retarder concentrations necessary for bottom hole conditions. Positive and/or negative differential pressure tests are normally used to evaluate these jobs and, in many cases, results have been poor. Since these wells are subjected to hydraulic fracturing upon completion, the integrity of the cement sheath is essential and squeeze work must often be performed to achieve good zonal isolation. A new design approach has significantly reduced the problems associated with cementing these wells. This approach centres on the careful selection of spacers and the use of highperformance cement slurries. Desirable properties of the latter include very low fluid-loss and exceptional fluidity (low rheology) without development of free water or sedimentation. Early compressive strengths of these systems are also superior to those of the systems used historically in this area. Case histories from several wells are used to demonstrate the success of this approach.

Unconventional reservoirs require innovative completion techniques and technology to become more economical. Formations vary drastically in lithology, lateral lengths, completion methods, and financial drivers. Since reservoir conditions typically mandate the use of hydraulic fracturing for economical production results, a significant amount of resources are focused on making the fracturing process more efficient and lowering its environmental impact. This case history includes an operational review focused on a novel technique to rapidly perform targeted annular hydraulic fractures by deploying an activation tool on coiled tubing (CT) to open frac sleeves in a horizontal well. The paper covers results and information gathered from the first operation of its kind in Montana's Bakken Formation – where a total of 19 stages were fractured in the shaley dolomite. The new technology does not involve dropping balls or setting composite plugs to isolate stages. Rather, the technique utilizes frac sleeves that are activated using a CT bottomhole assembly to save time between stages. The sleeves can be cemented in place if desired and have a full-bore internal diameter that does not require post-treatment composite plug millouts, further reducing overall completion time and time to production. Additional capabilities of the system enable the use of memory gauges to monitor downhole pressure and temperature characteristics. The operator preferred this method due to its targeted nature, efficiency, and fluid savings. As opposed to multicluster fracturing methods (such as ‘plug-n-perf"), a single entry point during the frac job promotes increased fluid velocity, enabling a more aggressive sand ramp and reduction in required hydraulic horsepower. Similarly, the single entry point ensures that a fracture is generated at each port, as opposed to the possibility that some clusters are not treated. In addition, no composite plugs or diverting devices are required to be pumped down the wellbore, so water usage is reduced considerably. The system, already used in thousands of fracturing stages in Canada, speeds up the completion process, uses less fluid, minimizes risks, and reduces overall downtime.

Well completions in the United States are predominantly completed using the plug and perforate process. Following the fracture stimulation treatment, coiled tubing (CT) is utilized to convey a downhole milling assembly to remove these plugs and clean out the wellbore. As wells continue to extend in lateral length, an extended reach tool (ERT) is commonly used to aid in achieving these depths. In order to truly understand the milling process using an ERT, a downhole memory tool was developed. The memory tool is run in-line with the milling assembly and obtains weight on bit (WOB), torque, pressure, temperature, and vibration at one second sampling rates. The tool has been run on multiple bottom hole assemblies (BHA) on both 2 3/8-in and 2 5/8-in CT on over 35 jobs accounting for 1,500 composite frac plugs. The data collected is compared to surface data providing a detailed view of the overall plug milling operation. The ERTs used provide WOB while milling at a level that is unpredictable by commercial CT modeling software. Comparison of the surface weight gauge with the downhole WOB enables a clearer understanding of the forces delivered by the ERT. This data provides an avenue for better job planning and informed decisions on ERT selection.

Wells in the South Ratqa field often fill with sand. Ultra low bottom-hole pressure did not allow efficient sand cleanouts in several wells. Despite using massive amounts of nitrogen during clean out, and largest available CT size (2.375") to ensure enough annular velocity; severe fluid losses occurred into the formation, which resulted in decreased well production post clean outs, moreover handling energized returns has always been a logistic and safety hazard Recently, concentric coiled tubing (CCT) technology was employed for the first time in Kuwait and five wells were identified as viable fill cleanout candidates for which traditional cleanout methods had proved inefficient at best and many times unsuccessful. The system uses concentric coiled tubing and a special vacuum tool designed to apply a localized drawdown, which would deliver the sand particles through the Coiled Tubing / Coiled tubing annulus to surface. Returns were handled using H2S resistant lines into a desander. A carefully engineered cleanout program enabled removal of more than 12 MT of sand from four vertical wells, and also identified the formation damage in a horizontal wellbore. The identification of wellbore damage revealed the best intervention to cure the damage and eliminated speculative remedies that sometimes increased the damage done to reservoir. Additionally, the layout of well plots was designed in a very congested way to maximize output but made it impractical to have return pits, requiring mobile tanks to handle returns, while the energized nature of returns in conventional nitrogen jobs are dangerous to handle in a closed tank environment. CCT eliminated that hazard as the returns are not energized. The campaign has pushed the boundaries of the coiled tubing interventions in Kuwait and has unlocked several wellbore cleanout opportunities using the CCT technology

One main challenge facing the Shell Pinedale Anticline completions is effectively drilling 21 plugs per well throughout a 6500′ hydraulically fractured completion interval (7,500′ – 14,000′ TMD) in a safe, timely, and cost effective manner. Ths process of drilling plugs has improved considerably with respect to time, cost, and environmental impact since drilling and completions operations ramped up in 2002. Early bottom hole assembly (BHA) designs used for the drilling of plugs with coiled tubing (CT) were limited to drilling approximately 4-6 plugs before tripping out of hole for a new mill or motor. In addition to the long cycle times, this BHA design also resulted in high frequency of sticking, disconnects, and costly fishing jobs. Since no advanced flowback equipment or layouts were used on early drill outs, all gas was flared. Improvements to all aspects of the drilling process, such as BHA design and flowback layout, have led to routinely drilling up as many as 21 composite bridge plugs, with one coiled tubing trip, limited flaring of gas, and reduced cycle time of less than 24 hours from rig up to rig down. This paper will focus on four main areas of improvement: 1) Bottom Hole Assembly (BHA) improvements; mill design, motor performance 2) Surface equipment improvements resulting in limited flaring, 3) Composite plug selection, 4) CT selection – taper, grade, size.

The paper combines a brief case history of applications with supporting laboratory data, for using a new relative permeability modifier (RPM) in conjunction with a conventional acid stimulation treatment. This design was targeted at mature oil wells with high water cuts in Ecuador. The recommendation was proposed after mineralogical characterization of core samples, using scanning electron microscopy (SEM) followed by laboratory core flooding with treatment fluids. The methodology described in the paper comprises stimulation of certain areas of the sandstone formation with an acid followed by a RPM treatment to prevent the water from the stimulated water-bearing zones from entering the wellbore. Coiled tubing is used for effective placement of the treatment. Conventional stimulation treatments in the Hollin sandstone formation in Ecuador result in high water cuts because of encroaching water from an active aquifer. The acidizing technique with RPM improved the economic life of many mature wells in the field. Both laboratory and field data indicate excellent results from the treatments. The overall water cut in the treated wells decreased (by 8 to 15%), while oil production increased (~200%). Coiled tubing enables accurate placement of the acid and RPM into the desired zones, with the benefits from this targeted treatment far outweighing the cost of using coiled tubing units. Successful implementation of the laboratory core flood results in the field resulted in field-wide protocols aimed at oil wells producing water at unacceptable rates. The optimized stimulation treatment increases oil production and selective placement of RPM using coiled tubing decreased water cut, thereby prolonging the economic viability of mature wells.