In volatile times, when oil prices are in a decline, efficiencies and asset utilization are critical elements to ensure sustainability in the market for both operators and service companies. However, maximizing utilization and pushing equipment to the maximum could potentially have negative repercussions and ultimately result in failures causing loss of time and other potential damages. Thus is it critical to closely monitor and evaluate the assets conditions to ensure both safe and efficient operations are performed. In the case of coiled tubing (CT) strings, monitoring and proper evaluation can be performed by utilizing an infield nondestructive evaluation (NDE) device that employs magnetic flux leakage (MFL) to detect flaws and monitor, wall thickness, outer diameter, and various other properties. The real-time device requires no direct contact with pipe, and its compact design allows it to be run continuously throughout the life of the CT. Damage can then be detected and managed before a failure occurs. The ultimate goal is to reduce CT failures while increasing CT longevity throughout the operations. This paper covers three specific examples of NDE inspection conducted on site that increased the utilization of the CT string without compromising the service quality delivery. It also reviews the various parameters that were monitored and evaluated on location and the decision-making process used to keep the strings in service longer than previous methods would have allowed thus safely increasing the utilization and improving the efficiency. The first two cases are out of Texas, USA. The objective of the NDE was monitoring the pipe for corrosion or physical plastic deformation. This region regularly performs high-pressure cycling operations and in the past relied mostly on calculated fatigue models with significant derated values and safety factors to retire strings from use. Utilizing the scanning devices from after manufacturing through the strings' life allowed both the operator and the service company get more useable footage and still retire the strings after getting indications of irreversible geometric changes. They were able to plan and control the CT retirement around operational well plans to ensure no delays were seen in the field. The third example is out of Alberta, Canada. A CT string being used on a long-term project was damaged. The NDE inspection allowed for continued use of a pipe that had visible surface damage. In the past, this string would have been immediately retired and removed from service after a mechanical defect of the same nature was observed; however, the NDE device aided in adressing the severity of the damage, by MFL, and monitored its progress while continuing to use the string. The 2.375-in. string was able to be run an additional 53,203-m [174,550-ft] in a safe and controlled manner before reaching retirement.

Matrix stimulation treatments are applied to improve well productivity and enhance the hydrocarbon recovery from the formation. However, in some wells optimum results cannot be achieved using conventional stimulation techniques since it is difficult to ensure efficient placement of the stimulation fluid across the entire stimulation interval. This is a prerequisite for a successful result. The situation becomes even more challenging in heterogeneous reservoirs with large permeability variations or possible presence of natural fractures in a complex geological environment. Other complications may occur when conventional stimulation treatments keeps creating undesired wormholes throughout the same spot within existing (horizontal) bore hole. These complications may result in making future diversion jobs even more challenging and sometimes enlarges the hole to the limit of affecting accessibility in future interventions. The paper describes a unique approach that has been successfully executed in one of the super giant onshore fields in Abu Dhabi through an extensive study over different types of heterogeneous reservoirs. The objective was to develop an economically justified stimulation strategy utilizing different treatment fluids and a unique placement approach which led to proper reservoir drainage. In this field the production comes from various carbonate reservoirs, where the different layers are subject to different methodologies to support the reservoir pressure. The approach consists of chemical diversion, dual injection for acid placement, and optimized jetting tool. The paper also describes the results of re-stimulation of a group of wells as part of field pilot. Actual data from several treated horizontal wells are presented. The methodology of candidate selection, treatment design and execution is described along with pre and post stimulation production logging. The paper highlights the impact of production improvements of the treated wells. Chemical diversion, as proved in the pilot wells, enhanced the acid stimulation. It was shown that previously untreated subunits, were now contributing to flow. The pilot wells have validated the engineered methodology adopted for the work-scope.

The UAE field has many thin multilayered carbonate reservoirs. Production from thse thin reservoirs are primarily supported by water injection. Reservoir properties, such as permeability, pore pressure, and water saturation, vary significantly both across the field geographically and within the different layers. Recently a study has been done to drill and maximize reservoir contact via ERD wells. To reduce costs and improve recovery, further development of the plan is to use wells drilled with throws greater than 15,000 ft and measured depths greater than 20,000 ft with some wells exceeding 35,000 ft. Long horizontals provide many benefits including enhanced access to offshore reserves, optimized productivity, reduced capital expenditure, and a minimized environmental impact With these benefits come challenges, accessibility for intervention operations being the most prevalent. Many factors affect the accessibility and intervention capabilities in ERD wells. Completion ID restrictions play a critical role in the equipment availability and selection. Once equipment is selected the leading principles used for improved access in ERD applications are: Increasing pipe bending stiffness to postpone helical buckling Reducing Normal Force between the CT wellbore Reducing Friction Coefficient Adding Axial Forces ERD applications and accessibility for interventions have been an ongoing challenge on how to properly model and predict the reach of CT in varying environments. The two pilot wells covered in this paper allowed for an array of information to be collected as the trajectories were very similar but the wells themselves were very unique. One well was a producer while the other was an injector. One well was completed with 13% Chromium and the other with conventional tubing. In this paper we will cover the above topics in more detail to clearly outline the challenges of ERD operations and the methods to overcome them. It will be clearly outline how these methods were used on two ERD pilot wells in UAE with the supporting actual operational data. These wells and lessons learned will pave the way for future ERD operations planned in both offshore and island based offshore UAE pilot projects.

Flow assurance in subsea production flow lines is becoming more prevalent as deepwater well developments continue to grow. Coiled tubing (CT), though traditionally used in wellbore environments, can be utilized to address flow assurance. Complications are possible when applying CT technology in a nonconventional environment. Connection tie-ins and available deck area are typically incompatible with intervention-type activities, and challenging issues such as weight limitations, nature of blockage, and weather sensitive environments lead to the need for elaborate planning with multiple contingencies to address the uncertainties. Our study investigated the operational planning and logistical requirements associated with the radiation of the flow assurance for the Serrano flowline. The Serrano flowline is located in the Gulf of Mexico (GOM), in 3,500 ft of water and is tied back 6 miles to the Auger TLP. Three subsea wells have produced through the electrically heated Serrano flowline since 2001. In November 2006, there was an unplanned shutdown of the flowline and despite numerous attempts to restart, the wells had failed to flow. In December 2007, after 6 months of intensive and complex planning, a standalone CT operation was successfully performed while drilling operations continued on the main rig. The operations consisted of utilizing a unique small footprint compensation frame to allow access to the flowline from a confined area. Then a 1–1/2-in CT string was deployed into the flowline to retrieve a sample of the blockage for diagnostic purposes. The analysis of the sample dictated the optimal cleanout strategy which was to combine a specialized rotary nozzle with pumping diesel and solvents to successfully clean out the flowline. The blockage was breached at a depth of 3,700 ft after cleaning almost 1,000 ft in less than 24 hours. The flowline was reinstated and gas production restored to >2,000 bbl/d and 8 MMcf, thus preventing the client from losing the lease. Introduction The Serrano flowline is tied back six miles to the Auger TLP platform and consists of 3 wells. The flowline is a single 6 in by 10 in pipe-in-pipe insulated flowline. The flowline and its counter part the Oregano are not only the first pipe-in-pipe single flowline systems but also the first use of an electrical heating flowline system. This heated system was used to aid in the reduction/elimination of potential hydrate formation due to subsea temperatures. In August 2005, the hurricane Katrina evacuation caused a shut-in of the flowlines for 17 days. The flowlines were brought back online without incident. Shortly after the August shut-in, hurricane Rita, November 2005, caused another shut-in for a total of 78 days. The comparison of the well tests completed before each shut-in showed that production values were comparable and little to no loss was seen. The third shut-in was done in July 2006 for 2 days after which a small but noticeable reduction in productivity was seen. The flowline was shut in for 1 week in November 2006. Generator power to the EH (electrical heating) system was lost. Once the flowline was opened back up for restart, it would not flow. It was suspected that a hydrate formed in the flowline during the shut-in period, but other possibilities were sand and paraffin buildup. Pressure (2,800 psi) was applied from the riser side of the blockage; however, it failed to dislodge the plug. Methanol was then pumped down the riser to further prevent hydrate formation since it was possible that the EH system was not functioning properly. The top of the plug has been estimated to begin at approximately 2,200 ft to 3,500 ft, based on the fluid volumes pumped into the flowline from the TLP. There were some variations during the November 2006 shutdown compared to the previous shutdown operations, which include a blowdown of the flowline, a Chilly Choke back pressurization upon restart, and the injection of approximately 24 bbl of MeOH injected into the riser section.

No abstract