TX 75083-3836, U.S.A., fax 1.972.952.9435. AbstractTailoring drilling fluid hydraulics is one important key to the success of a drilling operation. Failure to do so can result in costly problems, negatively impact equipment longevity and performance, and ultimately jeopardize overall well objectives. In recent years the industry methods have deviated from API RP13D Standard Practice. This departure has been driven primarily by the increasingly onerous demands of critical wells, coupled with readily accessible computer power.In 2003 a Task Group was formed to modernize the existing API Recommended Practice Bulletin on Rheology and Hydraulics. It comprised a cross-functional team of operators, suppliers and academics which set an aggressive target to modernize the existing standard within two years. The focus was to develop simple, yet accurate methods, which could be readily implemented with basic spread-sheeting skills.This paper describes improvements made to the existing procedures and provides an illustration of how these methods can be applied to complex well designs. The paper also serves to introduce the industry to a modernized API Standard which offers an ideal foundation to inform new engineers of the fundamental concepts of hydraulic design and optimization. Project PlanningThe selection of resources was key to delivering this cross-industry project in a timely manner. The resource pool was drawn from operators, service suppliers and academia. The people were deliberately chosen to bring the appropriate balance of theoretical rigor and practical application. The final core team comprised 10 people from 5 different countries. The geographically dispersed nature of the team necessitated that most of the communication was via email and virtual meetings. However communication was augmented by face-to-face meetings at key stages of the project.
Chevron has been successfully drilling and gravel packing open hole horizontal wells on the Alba Field (central North Sea) since 1998 and 13 open-hole gravel packed (OHGP) wells drilled with water based mud(WBM) are currently in production with no history of sand production. Although these wells have been hugely successful with significant net present value (NPV) returns it was recognised that the future, mature redrill and infill targets cannot sustain the current costs associated with traditional OHGP completions. The challenge was to develop alternative techniques to maintain the benefits of OHGP wells but to achieve a low cost well and completion concept to assist in realising new drilling opportunities. To drill the shale above the top of the reservoir and the productive interval in a single hole section would remove the conventional requirements to set an additional casing string and change over to a water based system prior to drilling into the reservoir. This would save costs but raise a question over the gravel packing operation. Hitherto, attempts to gravel pack involving á/â placement techniques using an aqueous carrier fluid following drilling with oil based systems have had only limited success. The prospective problems were examined by extensive laboratory tests carried out by Baroid and Chevron in co-operation. A new synthetic oil based mud (SBM) formulation was developed and compatible displacement fluids and procedures were devised. Based on this work, 1500 ft of shale and reservoir were drilled; a liner was installed – predrilled over the reservoir section – and screen was run inside the liner. Gravel was pumped using brine as carrier fluid and complete gravel placement was achieved. The well has achieved productivity levels at least as good as existing WBM wells. A second well completed in the same manner has given similar performance. This combination of a liner system and SBM fluids offers several advantages. There is the prospect of considerable savings with respect to operating time, cementing and drilling fluids. Also the liner gives protection to the screen. This new approach which represents potential large savings in costs and excellent productivity is considered to be very applicable for expandable sand screens (ESS), multi-lateral completions and additional redrill targets both on Alba and worldwide.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractDrilling in the Qiongdongnan Basin, offshore China's Hainan Island Province, has often resulted in failure to reach desired objectives.Bottomhole temperatures up to 475°F, and pressures requiring mud weights up to 19.5 lbm/gal equivalent, place severe limitations on the performance of drilling fluids and often contribute in failure to reach the desired drilling objectives.Well Yacheng 21-1-4 was drilled in this basin with the COSDC semi-submersible rig Nanhai V and was spudded on 27 th November 1998. TD of 5,250 meters was attained on 20 th May 1999 where the bottomhole static temperature was 414°F and the pore pressure was 18.5 lbm/gal equivalent. Logs were run to bottom without incident with no significant drilling fluid related problems and the primary drilling objectives achieved. The success is attributed to innovative, fit-for-purpose drilling fluids and rigorous pre-well planning over a 2-year period prior to the well commencing.The paper describes the holistic approach to drilling fluid engineering for extreme well conditions. The development of innovative drilling fluids specific to these well conditions, and the rigorous laboratory testing necessary to generate detailed engineering guidelines, are described. Large-scale abrasion and pressure tests were also conducted. Modifications made to the rig design facilitated the management of drilling fluid properties at high density with high flow line temperatures. A portable drilling fluids laboratory, staffed with trained technicians, was installed on the rig to continually pilot test drilling fluid samples and treatments under simulated downhole conditions. The importance of good communications and global technical support networks proved invaluable during the pre-well planning and for the execution phase of extreme high temperature and high pressure wells drilling.
The Alba field in the central North Sea is an unconsolidated sandstone reservoir with an average permeability of around three darcies. Maximising productivity and extending completion life has been an evolving process throughout the life of this field. Recent practice is to drill the horizontal reservoir section using a water-based drill-in fluid (DIF) and complete with a circulating open-hole gravel pack (OHGP). One current option employs an oil-based DIF prior to gravel packing in brine. Both of these procedures have allowed higher off-take rates from these wells than previous completion practices. New advances in the nature of delayed stimulation chemicals and the introduction of more effective additives (generating acid in situ downhole) made it of considerable interest to determine whether productivity could be further enhanced. One major obstacle to overcome was the uncertainty associated with the placement and uniform distribution of the stimulation treatment in a horizontal well, allowing the entire filter cake to be contacted and broken down successfully. This paper describes how the deployment problems were successfully circumvented. A dual density treatment was employed in which both the upper and lower zones of the horizontal well-bore were targeted so that the filter cake on both the upper and lower surface in the hole would be contacted and attacked. Evidence will be provided indicating the placement resulted in an enhanced productivity index compared to conventional, non-stimulated completions. The new stimulation treatment was effective in wells drilled with either a water-based DIF or an oil-based DIF. Introduction The history of the development of the Alba field over theperiod from its inception until 2002 has been reported in previous publications.1,2 This paper reports recent developments. The Alba oil field located in block 16/26 of the UK sector of the North Sea comprises an Eocene sandstone formation that is thin, highly porous, highly permeable, very unconsolidated and overlain by a bed of impermeable, highly reactive shale. The nature of the reservoir dictated that development would be best achieved by open hole completions and highly deviated or horizontal reservoir sections with the productive interval being sited near the top of the sand body. The earliest approach was to run screen only completions, initially using synthetic oil-based mud (OBM) as the drill in fluid (DIF), evolving through the same screen arrangements but using a saturated brine/sized sodium chloride based DIF. Both approaches provided excellent drilling properties but there were severe limitations in respect of productivity in the case of those wells drilled with synthetic-based mud (SBM) and screen longevity was a problem for the wells using the sized salt approach.1 Both issues were addressed by adopting a sized carbonate DIF and performing open hole gravel packs (OHGP) on the productive sections. Since these observations on the evolution of the drill-in fluids and completion strategies on the Alba were reported, several other important developments have been made. In apparent contrast to the message provided in the earlier report2 about the robustness of the gravel pack completion philosophy relative to stand alone completions, the appearance of extremely early well failures on a few gravel packed wells have given cause for additional concern. As previously reported, the well failure data indicated that the standalone screen completions had failure rates in the order of 70–90%, with failures typically occurring after one to three years of production. Open hole gravel packed wells, in contrast, at least initially, exhibited prolonged well life. Thirteen open hole gravel packs were successfully completed and on line before any incidence of failure.2 Subsequently, the field has experienced four well failures in a relatively short period of time. One of the wells in question produced for four years before failing but the other three failed after only a few weeks of production.
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