The coiled tubing (CT) industry continues to operate in deeper and higher pressure wells and in more challenging environments, thereby extending the operating envelope for the service worldwide. CT operations for cement milling provides a safer, faster, and more economical solution, but achieving the desired results in a high pressure, high temperature (HPHT) offshore environment using corrosive brine as the milling fluid is challenging. This paper describes various challenges and customized remedies for a cement milling operation in an HPHT well with high-density brine, which made milling challenging because of limitations on pumping rates, low viscosity, and fluid corrosiveness. This offshore gas well had a bottomhole static temperature (BHST) of 400 °F and reservoir pressure of 12,000 psi, with a completion of 9-5/8 in. casing from the surface and a 3-1/2-in. liner hanging from 4,606 meter measured depth (mMD). A 1.75-in. outer diameter (OD) CT string was used to accommodate the internal diameter (ID) restriction of the liner. The allowable pumping rate in the 1.75-in. CT was restricted as a result of pipe friction and low viscosity of milling fluid; however, higher annular velocities were needed to lift the cuttings from the wellbore. To overcome this, additional pumping was performed from the annulus of the 9-5/8-in. section. A positive-displacement, metal-on-metal motor was selected over various types of motors. This paper provides details about best practices, including the selection of brine-compatible elastomeric seals, severe corrosion observed on the motorhead assembly (MHA), and redressing of MHA after each run. It also includes details about laboratory tests performed to identify a suitable viscosifier and corrosion inhibitor, as well as the optimum rate of penetration (ROP) and weight on bit (WOB) to avoid large cuttings, surface-fluid handling, and filtering arrangements. Based on precise tool selection, including power section, bearing section, and corrosive-brine-compatible motor seals, as well as design parameters, such as ROP, annular fluid velocity, particle size, and equivalent circulating density (ECD) under the operating envelope, cement milling of 217 m of cement was completed successfully in an overbalanced condition with no health, safety, and environment (HSE) related issues. Selecting the correct milling motor and mill plays a crucial role in any milling job. Several operational challenges, such as excessive corrosion at a minimum MHA ID, pitting on bottomhole assembly (BHA) components and erosion on ball seats, erosion, and degradation of elastomeric seals at a BHST of 400 °F, were observed. These adverse effects were avoided with engineering controls. The methods used, tool selection, and customized design helped the operator to find a solution for milling a cement plug in an HPHT well with zinc bromide (ZnBr2) brine, which resulted in reduced rig time and avoided the side tracking of the well. The lessons learned, methods, and best practices described in this paper can be used in a similar application worldwide, which can help to minimize issues related to service quality and HSE.

Acid systems are widely recognized by the oil and gas industry as an attractive class of fluids for the efficient stimulation of carbonate reservoirs. One of the major challenges in carbonate acidizing treatments is adjusting the convective transport of acid deep into the reservoir while achieving a minimum rock face dissolution. Conventional emulsified acids are hindered by several limitations; low stability at high temperatures, a high viscosity that limits pumping rate due to frictional losses, the potential of formation damage, and the difficulty to achieve homogenous field-scale mixing. This paper highlights the successful application of an engineered low-viscosity retarded acid system without the need for gelation by a polymer or surfactant or emulsification by diesel. An acid stimulation job using a new innovative retarded acid system has been performed in a West Kuwait field well. The proposed acid system combines the use of a strong mineral acid (i.e. hydrochloric acid "HCl") with a non-damaging retarding agent that allows deeper penetration of the live HCl acid into the formation, resulting in a more effective stimulation treatment. The retardation behavior testing includes dissolution experiments, compatibility testing, coreflood study, and corrosion rate testing (conducted at 200°F). The on-job implementation included the use of a packer to pinpoint fluid pumping (pre-flush) at the point of interest, followed by the customized novel retarded acid system for improving conductivity at perforations and effective reservoir stimulation. This acid system is characterized by having a low-viscosity and high thermal stability system that can be mixed on the fly. This approach addresses the main challenges of emulsified acid systems and offers a cost-effective solution to cover a wide range of applications in matrix acid stimulation and high-temperature conditions that require a chemically retarded acid system. The application of this novel acid retarded system is a fit-for-purpose solution to optimize the return on investment by maximizing the well production and extending the lifetime of the treatment effect. This new system also offers excellent scale inhibition and iron control properties which eliminates the need for any acid remedial work, making it an economical approach over other conventional acid systems. The paper presents results obtained after stimulating the carbonate reservoir and describes the lessons learned from the job planning and execution phases, which can be considered as a best practice for application in similar challenges in other fields. Proper candidate selection, best available placement technique, and lab-tested formulation of novel retarded acid system resulted in achieving 1700 BOPD of oil production (27% higher than expected).

In the current cost-constrained oil field environment, operators must complete their wells while minimizing capital expenditure. Operators respond to these challenges by utilizing customized diagnostic services and specialized tools in a single run to save on rig costs. Coiled Tubing (CT) deployed fiber- optics assist in taking Distributed Temperature Sensing (DTS) during acid stimulations to estimate fluid volume distribution in the horizontal openhole with a specialized jetting tool to create wormholes and complex microfractures. This paper discusses an acid stimulation process using dynamic fluid energy to divert flow into a specific sweet spot in the well to initiate and accurately pinpoint acid stimulation. The treatment efficiency was monitored and visualized in Real Time (RT) with CT-conveyed fiber-optic DTS. This acid stimulation process, named Integrated Dynamic Diversion (IDD), often uses two independent fluid streams: the acid phase down the treating string and other liquids or foamed fluid down the annulus. Two different fluids mix downhole with high energy to form a homogenous mixture. Pre-job DTS injection profile diagnostics identified a non-permeable zone, and the stimulation pumping schedule was adjusted accordingly. Using the IDD process, this was done in RT by changing the depths and increasing the number of stages across the non-permeable zone. Post-job injection profile DTS diagnostics confirmed an increase in injectivity across the non-permeable zone with a uniform injection across the entire openhole. This proved the value of combining RT CT with IDD using a dual pumping process and the specialized jetting tool. Post-job production results also indicate a sustainable production with an oil gain of +500 BOPD. Applying the IDD methodology with DTS services is the most appropriate solution to address the unique challenges of openhole operations, formation technical difficulties, high-stakes economics, and untapped high potential from intermittent reservoirs. This paper presents post-job results obtained from stimulating multiple zones along the lateral and describes the lessons learned in implementing this methodology, which can now be considered best practice for applications with similar challenges in other fields.

Increasing water cut in oil-producing zones is a common issue, particularly in mature fields. Currently, most decisions are governed by economics, and incurring additional expenses, such as handling produced water, is undesirable. Depending upon the source of the water production, chemical isolation provides one effective solution to this issue. This paper describes a cost-effective coiled tubing (CT) intervention to implement permanent zonal isolation for water shutoff using an organically crosslinked polymer (OCP) sealant system and a modified organically crosslinked polymer (m-OCP) sealant system to provide a controlled, shallow penetration solution to the problem in a high-permeability, low-pressure reservoir. The traditional water shutoff method uses rig intervention for cement squeezes, which targeting shallow penetration can be time consuming and expensive in a high-permeability, low-pressure reservoir. The OCP sealant system is an organically crosslinked polymer that is thermally activated to effectively seal the targeted interval. The m-OCP sealant system combines particulates with the OCP sealant system to provide leakoff control to help promote shallow matrix penetration. The production logging tool (PLT) data for the candidate well indicated that the maximum water cut originated from the lower perforations and a single zone. CT intervention was selected to accurately place the OCP and m-OCP sealant systems and to permanently block water production by creating polymer barriers inside the reservoir and to remove any remaining OCP/m-OCP from the wellbore. OCP and m-OCP are resistant to acid and H2S and provide the required radial penetration. This system provides a predictable and controlled set time (as shown by laboratory testing). Because this system does not develop compressive strength, a simplified cleanout with a jetting nozzle is required to wash it from the well. After completing the zonal isolation with the OCP sealant system, the pressure test for the zone indicated a good seal. An electric submersible pump (ESP) was run on the completion string, and initial test results showed that the water cut was reduced from 97 to 75%, and oil production increased from 175 to 300 bpd. Increased production will recover all intervention and chemical costs within 20 days. The polymer sealant system with the customized intervention solution successfully reduced the water cut for this west Kuwait field. The same approach can be applied to other similar fields worldwide.

Coiled tubing (CT) is widely used during sand cleanout applications for its multiple benefits, such as speed, cost effectiveness, minimum reaction time, efficient operations, the ability to perform live intervention cleanouts, etc. However, these benefits are difficult to achieve in complex, offshore, high-pressure/high-temperature (HP/HT), or big bore wells because of various operational constraints, such as weight, dimensions, wellbore trajectory, and completion design, resulting in increased expenditures and operation time for workover activities. This paper describes how these constraints were eliminated using a synergy of an innovative fluid system and engineering to perform a challenging, balanced sand cleanout treatment using 1.75-in. 5800 m long CT in ~500 m of a 7-in. 35-lbf casing section executed in a 5300-m deep HP/HT well. The deep HP/HT well had a minimum restriction of 2.56-in. in the upper completion limits, requiring large-diameter CT strings and a bottomhole assembly (BHA). Feasibility studies for use of a 1.75-in. CT vs. 2-in. CT string were performed, resulting in the selection of the 1.75-in. string. Another challenge was executing sand cleanout in a balanced condition, resulting in the selection of a saturated 13.1-lbm/gal potassium-formate (K-formate) brine. The combination of all three major constraints, a) 500-m long 7-in. section, b) use of 1.75-in. CT string, and c) use of saturated brine, made the cleanout design challenging, as sand cleanout with CT requires circulation rates, net particle rise velocity, friction pressures, viscosity, and fluid properties within the design envelope. However, the inversely proportional nature of such treatments means tuning of one property would decrease the operational feasibility of other properties. Based on results of several tests, a customized fluid recipe was designed containing a gelling agent that can become hydrated in saturated brine and remain stable at high temperatures. A compatible friction reducing agent was used to help reduce pumping friction to attain the desired annular fluid rate and velocity. A field test was performed with the designed fluid at surface with a CT string that was to be used for operations, confirming the effectiveness of the fluid recipe. Using downhole turbulence created by the tool, along with the custom-designed recipe in combination with wiper trips, the necessary design parameters were achieved for the cleanout operation, resulting in a) effective sand cleanout with ~98% efficiency, b) reduced operating hours, c) cost savings on workover operations, d) safer operation by keeping the well in a balanced condition, and e) a contingency action in place for screenout during fracturing treatments. The procedure described in this paper, along with lesson learned, can be applied in similar applications to help optimize results and overcome related challenges.