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.
Well intervention in horizontal extended reach wells (ERWs) comes with a myriad of challenges and in the case of coiled tubing the overarching impediment is in reaching the target depth (TD). Frictional forces act against the coiled tubing (CT) while being pushed from surface, this eventually leads to helical buckling of the tubing and early lockup where no further progress is made. Advances have been made over the last decade with the development of high-tech downhole CT tractors that deliver a strong pulling force to overcome these frictional forces. Restrictions in the well completion require these tractors to collapse to 2-1/8″, and then to expand to the cased or open hole size of up to 6-1/8″. With many wells having a larger bore size of 8-1/2″, a CT tractor did not exist to improve the coverage in those type of wells. At first glance, modifying the existing tractor for 6-1/8″ sized holes to function in 8-1/2″ sized holes could be accomplished by simply extending the lengths of the arms. However, the reality is a little more nuanced with several innovations required to deliver the same pulling force as the 6-1/8″ tractor version. This new generation of downhole compact high expansion tractors have improved push-links and newly designed grippers to enable rig-less acid stimulation and production logging in ERWs. The high expansion tractor is an important facilitator in CT well interventions to tackle challenging ERWs by increasing the coverage in 8-1/2″ hole sizes. The CT tractor design, development, testing and first deployment was conducted in 2021. The major advantages gained from increasing the reach can be summarized as follows: The CT high expansion tractor enables successful reservoir surveillance and production monitoring, including improved reservoir understanding providing data to update and calibrate reservoir models.Acid stimulation in 8-1/2″ open hole wells on CT targeted fluid placement to improve well productivity to increase revenue per well.Detecting and then shutting off water inflow zones with CT techniques, avoiding the need for drilling a side track. This new generation of slim tractors is the first in the industry to operate in wells with a diameter of 8-1/2″ and an operating range from 8″ to 10″. The key metric to successful acid stimulation or logging applications in ERWs is the ability to achieve maximum coverage of the openhole section. These engineered solutions demonstrate how creative innovations in technology design are improving accessibility in ERWs, resulting in superior reservoir management outcomes.
Increased concerns from well testing activities about the environmental impact have left several oil industry challenges. Some of these challenges include handling well effluents from flow back operations with sour crude; the challenges can be more severe to contend with H 2 S safety, pollution and spill risk. Limited deck space in offshore environments often restricts the footprint of flow back equipment. An optimized solution to cater specifically for offshore operations requires careful design to ensure a safe yet functional flow back system. The pollution risk from fall out could have serious consequences to the marine life and habitat. Given that offshore operations typically cost an order of magnitude in excess of land based operations, weather uncertainties could typically result in cost overruns, increasing total job costs.The scope of the paper is to examine the evolution of well deliverability testing -from conventional flaring practices to contemporary smokeless and zero flaring operations in a giant carbonate oil field in Saudi Arabia, surrounded by a world class environmentally protected marine and coastal ecosystem. The examination of 100 well testing candidates, with 39 of those using the zero flaring approach, allows a demonstration of the clear cost, technical and economic benefits over traditional flaring techniques.Before the production facilities and flow lines were operational, the previous clean up method required flaring of oil and gas. Although best practices were applied, an environmental and technical cost accompanied the approach. With the completion of the flow lines and production facilities, the application of the zero flaring option became possible. The possibility to conduct zero flaring provides several attractive benefits, with at least the equivalent of 4,000 barrels of oil not flared, pollution avoidance, 50% time saving and over 50% reduction in total job costs for the field development.
Workover operations with conventional workover rigs have an enormous impact on the site, adding strain to operational and production targets. Alternative approaches to optimize Electrical Submersible Pump (ESP) replacements were evaluated and a Hydraulic Workover Unit (HWU) was selected as delivering the most advantageous outcome for the field to expedite the workovers efficiently and cost effectively. The HWU is more than capable to overcome any challenges and perform the replacement of failed ESP's, yet at the same time is a more compact & mobile unit than a traditional workover rig resulting in a much reduced impact on the wellsite. Several major benefits are gained including; avoidance of disruption to nearby wells, faster well turn-around, reduced cost, and ultimately an increased production avails. The size and scale of conventional workover rig and well spacing require the candidate well and other nearby wells to remove flowlines and instrumentation to create enough space for the rig and ancillary equipment. One of the primary design features of a standard HWU is the high level of accessibility in tight spaces allowing the unit to be assembled in small multiple individual components. This can be very time consuming so the challenge was to benefit from the superior accessibility but also to minimize the rig time for a more efficient process. To achieve this, a specialized fit for purpose HWU with the modular construction packaged into minimal components allowing for a swift rig up and efficient deployment of the unit. This HWU remains highly accessible and can replace the failed ESP without disturbing the installed production flowline infrastructure and instrumentation. The HWU has been a key technology enabler transforming the status quo to improve the optimization of resources and reduce operational costs. During the project of 8 pilot wells, the average workover cost reduction was calculated at 61% per well. The improvement in operational efficiency benefited from an overall 69% faster site and well preparation duration with a 13% reduction in rig time. The magnitude of these improvements in efficiency, cost avoidance and the unlocking of earlier production availability is a game changer for ESP replacement operations. The HWU equipped with comprehensive capabilities has proven itself as a viable alternative to conventional workover rigs to replace failed ESP's. The design enhancements of the pre-assembled modular construction for the HWU minimizes the hazardous and labor-intensive assembly onsite, increasing the safety environment for the operational personnel.
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