Electric line remedial work such as through tubing perforation has been successfully carried out in most vertical/deviated wells. However, in high angle/horizontal wells it has become a major undertaking due to inability of the gravity-assisted, electric line to convey perforating guns to angles greater than 65°. With this electric line limitation, the options available for deploying the guns are limited to wireline tractor and e-coiled tubing since most through tubing perforation are done in real time. Apart from space constraint at the wellsite and cumbersome logistics, the main set back with the e-coil is its unavailability, while the tractor has high operational cost. This paper outlines the successful perforation of horizontal wells in the Niger Delta while addressing the operational issues encountered. The first case history is Addax ORW-11H, a horizontal well planned to have the lateral section slimmed down to 6 in. hole. After successfully drilling the hole to target depth (TD), a 6-in. hole-opener was deployed on 3½ in. drill pipe to condition the well before running the 4½ in. liner. In an attempt to re-run the hole-opener, the bottomhole assembly (BHA) got stuck 20 ft off target depth. After several unsuccessful attempts to recover the BHA, it was decided to perforate the 3½ in. drill pipe to provide a conduit for production. The challenge was deploying the gun at 90°deviation, correlating and perforating on depth without e-coil. This was overcome by using an intelligent memory correlating and perforating tool to perforate the drill pipe and communicate with the reservoir. On completion, the well delivered 1,400 bopd with 0% water cut. The second case history is Chevron Okan Well Y, which was drilled and completed as a horizontal gravity waterflood injection well. The initial 20,000-bwpd water injection began to drop and later quit due to sand accumulation and plugging. After an unsuccessful sand cleanout, the proposed remedial action was to add 40 ft of additional perforations shallower in the target reservoir to provide access for the desired injection rates for the well and help increase recovery. Initial attempt to run electric line to TD failed due to inclination of over 77°, but the well was later perforated successfully using the same novel technology with significant cost reduction.
The installation of dummy valves with the initial well completion for gas lifting wells has been a popular practise in the industry. These dummy valves provide a barrier between the annulus and the tubing during the well completion phase to the test the tubing and annulus independently after the well is flanged up. These dummy valves are later changed out for live valves in preparation for lift gas injection when the reservoir energy becomes too low for the wells to flow or when the desired production rate is greater than the reservoir energy can deliver due to water production. Whereas this completion method has endured, it has escalated the clean-up cost, and maintenance cost of these wells because the intervention operations for gas lift changeout are often time consuming and costly. To minimise the above costs due to the installation of these dummy valves during the initial completion phase, Addax Petroleum Development Company adopted the use of live valves during the initial completion. After completing the well with brine, it requires to be underbalanced to unload the brine and clean out before producing to the sales line. For under saturated reservoirs and depleted reservoirs, coil tubing with Nitrogen injection had been used to initiate the underbalance for the well clean up because of its low density and high-pressure characteristics. Today to further reduce the well clean-up cost, Addax Petroleum Development Company now pumps Nitrogen or lift gas through the casing-tubing annulus and the live gas lift valves to under balance and off load the well. Also, with the introduction of live gas lift valve installation, the cost of the dummy valve changeout, with consequent production deferment during the intervention process has been eliminated. This paper highlights the benefits Addax Petroleum Development Company has derived from the installation of live gas lift valves with the initial completion by reducing the completion and clean-up cost in each well completed, and the consequent elimination of well intervention cost for a gas lift changeout.
It is possible to conduct a drilling and completion operation, sustaining a high operational performance and ensuring low Non-Productive Time (NPT) throughout a well drilling and completion campaign. The results from a recent onshore drilling campaign proves that with the right people, planning and process, a hitch free drilling and completions campaign can be achieved. In this case a perfect campaign was defined as;Delivering the planned work-scope (5 wells) within the approved Authority for Expenditure (AFE) cost and duration. Drill to the specified Total depth, penetrating all the subsurface targets within the stated tolerances specified. Achieve less than 15% overall non-productive time.Deliver the planned work-scope without Fatalities (FAT), Loss Time Injuries (LTI), Restricted Workday Cases (RWC), or uncontrolled discharges to the environment.Deliver wells without well control issues, Stuck-pipe incidents or any train wrecks.Deliver wells with minimal formation damage.Maintain technical and operational integrity by complying with statutory regulations and company governance documents always. In order to avoid previous problems encountered while drilling the appraisal wells, critical sections of the Well delivery process were thoroughly reviewed and optimized as required. These include: The Well Design, Rig selection/certification and acceptance, Safety, and drilling operations and logistics. The optimization methods are extensively discussed in this paper. The improvement and close optimization of the mentioned facets of the project helped to save circa $14MM from the project. When compared with other land projects in the same terrain (Niger Delta), the campaign was observed to be a top performer in the P-10 region of the performance percentile.
The completion cost of development wells is usually 30-50% of the Authority for Expenditure (AFE). This depends on the number of zones to be completed, the completions strategy, cost of downhole jewelries and complexity. The quest to develop these complex un-stacked reservoirs has increased the tortuosity of the well plan and the complexity of the wells. This has in turn increased the completion complexity and has significantly increased the time taken to deploy the completion accessories, and the time taken to set the packer. The sand management strategy and lower completion philosophy for the case study field, is setting Stand Alone Screens (SAS) as the lower completion assembly. Over the years, Addax Petroleum has used the metallic ball to set the lower completion production packer in a slightly straight well. Due to the need to optimize the well architecture and the tortuous profile of the well, the average production packer is now set at circa 80-85 degree's inclination. This optimization plan, significantly increased the amount of time required to circulate the metallic ball to the lower completion ball seat (a device engineered to aid the setting and hanging of the lower completion assembly in the production casing). This increase in time has further increased the completion costs. To ensure that the development cost is reduced due to the current unstable and low oil price, a plastic setting ball (with lower specific gravity) was identified, risk assessed and used successfully to significantly eliminate the excess time for completion operations. This paper reviews the challenges experienced using the metallic packer setting balls in highly tortuous horizontal wells. It also shows and discusses the huge cost savings achieved in case study wells where the low gravity packer setting ball was used to set the lower completions production packer.
The job of pressure testing the tubing while running in a well was left up to running a standing valve to a nipple profile with a slick line unit. This involved multiple runs to set, test, and pull the standing valves, and with the advent of horizontal well's completion, the completion cost increases as more slick line trips are made. However, in high angle/horizontal wells, the slick-line associated hole problem has become a major challenge because of the inability of the gravity-assisted, slick line run to convey a standing valve to angles greater than 65°. This slick line limitation and associated challenges has resulted to major operators to find a more efficient method to pressure test the completion string. Various operators have done different things; including pressure testing the annulus of the string/casing to verify the tubing integrity to avoid slick line associated hole problems. In the quest to solve this problem and adding to body of knowledge, Addax petroleum team of engineers introduced a tubing tester valve as part of the completion string and used it to test the pressure integrity of the completion string connections while running in hole. In carrying out a tubing pressure test, the pumping sub with surface lines was rigged up directly on the tubing from the cement pumping unit, and pressure tested. The pressure testing exercise of this string took approximately 40 minutes. Also, to note that the tubing tester valve is a full-opening tester valve that allows completion string to self-fill while running in hole. The completion string could be pressure-tested as many times as required as it is run in the hole. The tester valve has reduced the rig non-productive time and risks associated with slick line deployments. The tester valve consists of a curved flapper valve and spring, a shear ring and locking dogs that allow the curved flapper to be fully closed during a pressure test; while the valve can be fully over ridden with a higher hydraulic pressure, which then opens a large-internal diameter through valve bore, permitting the internal diameter of the string to an unobstructed production rates and future well intervention access. The production string pressure test has been successfully carried out in sixty horizontal wells to date. The cost evaluation analysis performed between the slick line standing valve and the tubing tester valve tests for some of the wells shows cost savings as much as $240,000 per well on the jack up rig.
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