Open-hole gravel packing in vertical/conventional wells is an accepted sand exclusion method that has not gained wide and rapid application in horizontal wells. The reason is largely due to sand placement challenges in the horizontal drain that could lead to premature sand screen-out. Consequently, many operators are skeptical gravel packing horizontal wells since failure could probably result in enormous capital risk. In the Niger Delta, about 70 % of the hydrocarbon-bearing reserves lie in shallow unconsolidated reservoirs where the sonic transit time vary between 110 to 140 us/ft. Production from these intervals has proven record of sand threats to operating cost, well integrity, surface facilities and production sustenance. The challenge is to complete wells in these reservoirs with sand exclusion materials that would guarantee full life-cycle production performance. Early horizontal wells in the region were completed with stand-alone screens, but recently, the expandable sand screen (ESS) took a leading edge. Though the ESS has a higher inflow area compared to other screens, its high cost, lack of full-bore expansion and the required lead-time continue to raise concerns especially when considered for applications in brown field development where well potential and reserve rewards are low. In response to these concerns, in 2002, openhole gravel packing (OHGP) in a horizontal well was investigated and considered as an alternative sand exclusion option in Shell Petroleum Development Company (SPDC). The trial candidate, the Obigbo-North QWSB-3 was selected and successfully completed as the first horizontal OHGP in SPDC using the alpha-beta wave concept. Based on simulation results, about 9237 lbm of sand was planned for placement in 1000-ft of 6.0-in hole size, however, the actual sand pumped was about 10830 lbm. This represents an estimate of 6.25-in drain hole size. The application saved over $0.3 million when compared to the cost of using ESS. For the Eastern asset team that drills an average of 12 wells annually, an annual projected completion cost-saving of some $3.6 million is achievable. Based on the initial production testing, Obigbo-North Well QWSB-3 tested 3250 BOPD with a productivity index (PI) of 130 bbl/(psi-D). Baseline Memory Production Logging Tool (MPLT) logging showed that the entire drain section completed on the clean sand member had effective inflow into the linerbore. In addition to establishing confidence in the application and performance efficacy of OHGP, this trial and the significant cost-savings will engender a paradigm shift to horizontal well sand control. In this presentation, we will share some data and results based on field experiences, challenges and new understanding. Introduction This paper discusses the first application of horizontal open hole gravel packing as a sand control method in SPDC. The paper further demonstrates the evaluation of the inflow profile (based on memory production log) as a yardstick for determining the completion efficiency, and reveals the economic argument against using ESS as seen in Well QWSB-3 (figure-1) located in the Obigbo-North field of Niger Delta, Nigeria (figure-2). Production "hot-spot-effects" a phenomenon characterized by massive inflow into the liner-bore at a particular point (figures-3–5) is a common phenomenon in horizontal wells completed with stand-alone screens and ESS (that are not fully expanded to the sand-face). The problem is attributed to differential plugging of the completion screen by the migrating formation fines and/or improper horizontal drain section clean out2,3,4. When a stand-alone screen is partially plugged, the resultant annular flow converges to a point where intense inflow into the liner-bore is observed. This problem leads to higher drawdown, liner erosion, sand failure and ultimately production decline1,10. These problems commonly associated with wells completed with stand-alone screens, led to the many recent applications of ESS by the SPDC Land Asset Team. However, high material installation cost and complete expansion remain key challenges in ESS applications. SPDC decided to try horizontal OHGP as an alternative sand exclusion option that will be cost-effective and capable of sustaining production. Consequently, a trial application was executed at the end of the second quarter of 2002 in Obigbo-North Well QWSB-3. The well was planned to develop some 8.5 Million STB from the D3.200A reservoir at an initial offtake rate of 3000 BOPD (tables-1,2).

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA 360-degree rotating jetting tool has been successfully deployed to cleanup about 1000 ft of 6.25" horizontal openhole gravel packed (OHGP) well. The exercise was carried out using Nitrified 10% HCl placed from the toe to the heel at Coil Tubing average rate of 20 ft/min. Three passes were made at total fluids rate of 1.0 bpm. During the fluid placement, no losses were encountered. After the treatment and initial production testing, a baseline memory production log (MPLT) was acquired across the horizontal drain section to evaluate the completion/cleanup efficiency. The MPLT results indicated a better drain hole cleanup as seen in the inflow profile of the completed drain section. Higher contribution was also noticeable in the cleaner sand members. From the result obtained, the 360-degree rotating jetting tool can be efficiently applied to cleanup drain holes especially in horizontal wells equipped with gravel packs.

This case study describes the planning and execution of a surface gas fire blowout control operation that resulted in re-entering, killing and abandoning a wellbore that was blowing out at the surface via the annuli "A and B" at an SPDC well blowout. As part of the kill plan, simulations by use of the dynamic two-phase pipe flow simulator OLGA were performed. This paper presents the principles of the kill simulator and how the results were used in the design of the kill operation. A comparison with observed data and actual result are presented. The challenges faced include, accessing the wellhead due to the raging gas fire, obsolete wellhead, vandalised wellhead entry points, and absence of top packer in the original completion are highlighted in this paper. The techniques and equipment employed, plus good teamwork, provided the necessary ingredients to divert the gas fire and gain access to the wellhead thus enabling killing, securing and partial abandonment of the well. Introduction After a blowout, everyone wants to find the cause, prevent recurrence and understand how it was controlled. In-house papers/documentations may be written, measures are introduced to prevent another occurrence and be better prepared next time. In time, experience is lost as individuals leave and conditions become ripe for another blowout. Therefore, it is important to record, publicize, discuss and review case histories and past actions to learn about and prevent future disasters. Failure to use available information, not a lack of knowledge, usually causes and can certainly worsen disasters. This article is meant to disseminate information on an SPDC well blowout, analysis of causes, control methodology, etc., which will prove useful in educating and helping to avoid the disasters of blowout control in another well or region. Surface control operations are normally more difficult to develop due to the many possible blowout scenarios; potential escalation and unknown well response associated with intermediate control steps. For example:removing debris from Wellhead area;extinguishing fire;capping and diverting wellhead;shut-in and bullhead well dead ordynamically kill well. At these points additional information is gained that guides the team to the course of action required to meet the next milestone (1).