No abstract

Several improvements were necessary in the Manifa giant oil field development to secure a superior or favorable business position through the deployment of value-adding technological solutions in rigless interventions. Developing a field is often like solving a typical problem of constrained optimization, in this case, to maximize field development outcomes from well intervention (leading to improved production) subject to certain constraints. The constraints in the giant Manifa field maturation project case include the state of technical knowledge to access its extended reach wells, allocated budget for intervention, or to protect the environment. Thus, the optimization problem is to determine the bundle of technologies which maximizes the field's well intervention strategy subject to technology, budget, or environmental constraints. The improvements are necessary to intervention outcomes dividends and to overcome several technical difficulties in the field. The scope of the paper is to examine technology improvements in coiled tubing (CT) reach and stimulation treatments specifically. CT reach technologies have improved to include elaborate physics or design aided simulations, which includes a consideration of friction coefficients, prediction or estimation of the lock-up points, selection of the amount, concentration, and volumes of friction reducers. The simulation offers guides to engineers with available methods for additional CT reach including the use of flowing fluid, downhole tractors and agitators, straightening, pipe size, and optimal taper of CT, drag/friction reducers, and buoyancy reduction. The advent of robust tractors that provide external pulling force on CT has increased CT reach especially on power water injectors. However, uncertainties remain in determining tractor performance, quantifying the tractor actual pulling force, fine-tuning friction coefficients, early detection of CT tags, and differentiating between CT tag and excessive drag. Stimulation treatments have improved from bull heading stimulation fluids into the wells with limited zone control. The use of CT for matrix stimulation treatments to optimize acid placements seemed to have helped to enhance diversion and acid placements through a combination of distributed temperature sensing, pressure, temperature, and casing collar locator real time measurements. Self-diverting viscoelastic diverting acid (VDA), designed to viscosify in situ as the fluid spends on the reacted formation for chemical diversion in carbonates have been optimized from 20 % HCl to 15 % HCl. Technologies which allow the measurement of bottom-hole parameters in real time enabled the conduct of deeper reach CT for enhanced stimulation practices. The improvements are significant because real-time capabilities can significantly improve the quality of well interventions and decision making in the field.

Corrosion in offshore well completions can lead to serious well integrity problems and costly workover operations. Although carbon steel is an ideal material for most completions, under certain conditions corrosion can attack and severely damage carbon steel equipment. Corrosion resistant alloys (CRA) are a good option but come with the considerable downside of very high cost. A relatively simple and cost effective approach to protect completion equipment against these corrosive elements is to line carbon steel completion tubulars with a non-metallic Glass Reinforced Epoxy (GRE). The GRE material properties provide excellent protection against a range of conditions including; highly corrosive fluids, erosive granular materials, Carbon dioxide (CO2), Hydrogen Sulfide (H2S) and acid treatments. The GRE lined Carbon steel is capable of combatting a range of corrosive environments in oil producers, water injectors / supply wells, including water with high concentration of total dissolved solids (TDS), chloride and sulfates and oil with high levels of H2S and CO2. The steel tubing is protected from these unforgiving ecosystems by lining the inside of the tubing with one continuous GRE tube. To secure the GRE lining and to increase the strength, a cement is pumped down the narrow annulus between the GRE lining and tubing internal wall. This procedure is relatively simple with the resultant GRE lined tubing having exactly the same tubing strength properties as the bare tubing. The primary method for detecting any well integrity problems with water injector wells are from determining high pressures in the tubing casing annulus (TCA). To date, all of the water injector wells installed with 7" GRE lined tubing have remained integral with no indication of any corrosion. Several of the oil producer and water supply wells that were lined with GRE have subsequently been worked over to replace faulty equipment; primarily electrical submersible pumps (ESP's). Encouragingly, the condition of the recovered GRE tubing had suffered no corrosion, scaling or other degradation benefiting from the GRE protection. The non-metallic GRE material is exceptionally robust with notable longevity and very resistant to any scale build-ups, leading to improved flow assurance. At the same time being tough enough to withstand any routine well intervention for logging, acid stimulation and other applications. The durable qualities and chemical characteristics of these non-metallic materials in downhole completions is likely to expand in the coming years, with increasing applications being found.

Summary 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 is 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 of effectively logging these ERWs is further complicated by constraints in the completion where electrical submersible pumps (ESPs) are installed, including a 2.4-in. bypass section. Although hydraulically powered CT 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 of pulling the CT to target depth (TD). 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 preset pump rate from surface. Developed to improve the low coverage in openhole 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 run in hole (RIH). Once the CT locked up, the tractor was activated and pulled the coil to cover more than 90% of the openhole section, delivering a pulling force of up to 3,200 lbf. Real-time production logging was conducted simultaneously with the tractor activation; 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 (SLT) is the world’s slimmest and most compact and is the first CT tractor of its kind to enable production logging operations in openhole horizontal ERWs. The importance of the ability to successfully log these ERWs cannot be overstated; reservoir simulations and management decisions are only as good as the quality of data available. Some of the advantages of drilling ERWs, such as increased reservoir contact, reduced footprint, and fewer wells drilled, will be lost if sufficient reservoir surveillance cannot be achieved. To maximize the benefits of ERWs, creative solutions and innovative designs must be developed continually to push the boundaries further.

Matrix acid stimulation in carbonate formations can often be vital to remove formation damage post drilling and achieve a more uniform production profile. Reaching well total depth (TD) is critical for an effective treatment in extended reach wells (ERWs) completed with an electrical submersible pump (ESP). The ESP completion with minimum restriction of 2.44-in. limits the coil tubing (CT) and downhole tools size. Hydraulically powered CT tractors are an ideal solution to pull the CT to TD (Saiood et al. 2018). The completion minimum restriction only allows for 2-in. CT with 2-1/8-in. OD hydraulically powered CT tractors and a maximum pulling force of 3,200 lbs. Pre-job CT design-aided simulations predicted the 2-in. CT size and a 2-1/8-in. CT tractor would not reach well TD due to unfavorable trajectory and therefore potentially jeopardizing a successful stimulation treatment. An alternative method is to utilize 2-7/8-in. CT combined with a 3.5-in. hydraulically powered tractor to conduct matrix acid stimulation prior to installing the upper ESP completion with restricted ID. This alternative arrangement allows for a maximum pulling force of 9,200 lbs, ensuring a greater reach in ERWs and effective treatment. It also tolerates higher pumping rates with 2.875in. CT (up to 5 bbl/min as compared with 2 bbl/min for 2-in. CT), reducing the exposure time of acid on surface, reaching optimum rates faster creating favorable wormholes in the carbonate formation and reducing the pumping operation time by up to 50%. Matrix acid stimulation is then completed with the drilling rig still in position post drilling operations. Thereafter, the upper ESP completion with restricted ID is installed. This engineered solution provides an alternative for CT interventions in extended-reach horizontal wells featuring completion restrictions, where the main challenge is to maximize the reach for optimum stimulation. The approach of combining the 3.5-in. hydraulically powered tractor with 2.875-in. CT pipe successfully enabled effective stimulation of the openhole section to a 27,000-ft. TD in a challenging downhole environment.