Coiled Tubing Underbalanced Drilling May Increase Production at Lisburne Field, Alaska
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M ANAGED P RESSURE D RILLING Coiled tubing underbalanced drilling may increase production at Lisburne Field, Alaska By Patrick Brand, Blade Energy Partners; Mark Johnson, Greg Sarber and Sam French, BP; Pedro Rangel, Schlumberger; Udo Cassee, Nordic; and Jimmy Clark, ASRC IN 2005, BP Alaska began evaluat- ing the application of underbalance drill- ing technology as a method for drilling multilateral wells in the Lisburne Field. The evaluation process was enacted as a response to three key challenges at Lisburne: 1. Slow ROP through the Wahoo’s hard carbonate formation. 2. Frequent total losses of drilling fluid when drilling conventionally. To improve productivity in the Lisburne Field, a project was implemented using under- 3. Poor understanding of the orientation, balanced drilling for multilateral wells. To minimize the surface kit size in the harsh frequency and impact of fractures on environment, the project used locally available separator and heater packages (seen production. above). A skid was manufactured to control the gas lift gas injection rate (left). The main objective of implementing underbalance technology in the Lisburne thin interbedded mudstones layers. • Detailed well planning. Reservoir fluid is mainly oil with a gas Field was productivity improvement. • Hazard analysis. This was to be realized by improving cap covering a portion of the field. ROP, thereby allowing for long laterals to Previous drilling in the reservoir had CANDIDATE SELECTION be drilled, intersecting more fractures. been done overbalanced. Problems All wells went through a rigorous selec- Coiled tubing underbalanced drilling included low ROP (averaging about 105 tion criteria, which consisted of: (CT-UBD) would also allow for drilling ft/day) and instability of the mudstone multilaterals from a single parent well- layers in water-base muds. Production 1. Minimal remaining economic potential bore through the production tubing. In performance of the reservoir had been for the parent well. addition, it was felt that underbalanced disappointing, with an oil recovery to drilling would eliminate losses to the for- date of 8% due to low matrix permeabil- 2. BHP greater than 3,300 psi. mation, with a side benefit of potentially ity and excessive gas production. mitigating formation damage. 3. Undeveloped target present with sig- Overbalanced drilling and conven- nificant resource potential. A 2-well, 5 lateral pilot project was tional stimulation techniques have had 4. Top of structure much deeper than approved. A coiled tubing drilling rig was mixed results. This led BP to consider anticipated base of gas. adapted for use in an underbalanced underbalanced drilling. The idea was drilling mode. The pilot was completed to place multiple laterals from a single during summer 2006 with excellent parent wellbore within the carbonate DETAILED WELL PLANNING HSE performance. Although not without sections underbalanced, thus increas- To eliminate the concern over hole clean- operational problems, the project demon- ing exposure to fractures and avoiding ing, problems below the tubing packer strated that underbalanced drilling could the potentially unstable mudstones. (in the 7 in.), and to give a higher prob- be used to increase rate of penetration The main motivation for UBD was ROP ability of isolating the parent wellbore and bit life. The pilot also demonstrated improvement and elimination of drilling perforations, the decision was to work that underbalanced drilling could elimi- problems associated with overbalanced over the wells and create a 4 ½-in. mono- nate many of the hole problems associ- operations. Other potential benefits bore completion. ated with conventional drilling, making included improved productivity and res- the drilling of long reach multilaterals ervoir characterization. The wells were designed to use 2-in. coil feasible. and drill 3-in. bi-center hole. Diesel was ENGINEERING, DESIGN selected as the power fluid to minimize INTRODUCTION potential problems with the mud stones. The planning phase of the project Field natural gas injected through the gas The Lisburne carbonate reservoir has encompassed four primary segments: lift system was designed as the lift gas. approximately 2 billion bbl of OOIP. The Wahoo formation, at a depth of about • Feasibility study. The directional plans were developed 8,900 ft (TVDSS), is tight, fairly thick to miss troublesome mudstone sections. (400 ft) and highly consolidated, with • Candidate selection. 72 March/April 2007 DRILLIN G CONTRACTOR U NDERBALANCED O P ERATI O NS If it was not possible to miss the mud- 6. Peer review of operations was con- approximately 3,200 psi (about 300 psi stones, the well was design to cut the ducted with UBD and coil experts from underbalance to static reservoir pres- mudstones at inclinations less than 70° within BP and its partners. sure). Production rates between 0.3 and or greater than 107° (avoid being near 0.5 bpm were noted while drilling. horizontal in the mudstones). 7. A Drilling Well on Paper (DWOP) was conducted in June. The lateral reached a planned total depth of 12,800 ft. The well was tested EQUIPMENT SELECTION 8. Multiple on-site audits were con- prior to setting the whipstock for drilling To minimize surface kit size in the harsh ducted. the next leg. Following the flow test, sig- cold weather environment of the North 9. Authorization to Proceed (ATP) was nificant paraffin was noted on the pipe. Slope, a locally available portable test conducted and given on 21 June 2006. Several runs were required to clear the separator was used for the Lisburne wellbore of paraffin prior to proceeding. CT-UBD project. Additional equipment TRAINING included diesel storage tanks and a FIRST WELL - LATERAL #2 heater to mitigate hydrate and emulsion There were three levels of training given potential problems. for the Lisburne project: The second lateral was drilled from 10,707 ft to a total depth of 12,532 ft. The diesel was stored in four 400-bbl 1. Scenario training for all critical deci- Initial conditions were 1.7 bpm diesel upright tanks. The tank farm came com- sion-makers. with 3 MMSCF/d of lift gas for a BHP of plete with transfer pumps and chemical 2,900 psi. Lift gas was turned off on this injection pumps. 2. Project orientation training for all field lateral when production was sufficient personnel. to achieve underbalanced conditions GAS CONTROL SKID 3. Live gas training for the rig crews. without the aid of lift gas. The well was tested at TD. Paraffin problems occurred To control the gas lift gas injection rate, again following the flow test causing a gas control skid was manufactured. IMPLEMENTATION additional lost time. This skid utilized a PLC system to allow The implementation phase of the proj- the desired rate to be remotely con- ect was broken down into the workover SECOND WEll – LATERAL #1 trolled. phase and the drilling phase. The rig was moved over the second well. EQUIPMENT LAYOUT The whipstock was set and the window WORKOVER PHASE milled. The lateral was drilled from The equipment layout was controlled by The two wells were worked over in batch 9,907 ft to a planned depth of 10,875 ft. the hazardous areas constraints adopted mode. The production tubing was pulled, Injection rates were between 1.5 bpm for the project. A zone 2 area, defined as and the original perforations were and 1.7 bpm with gas rates between 3.5 a 60-ft radius around each of the wells, cemented. The new monobore comple- MMSCF/d and 4.5 MMSCF/d for a BHP had restricted access. A further 150-ft tion consisted of a 4 ½-in. scab liner and between 2,800 psi and 3,300 psi. The zone was defined around the well that 4 ½-in. production tubing. The produc- lateral was flow tested, and the well was was being drilled. This area was to be tion tubing included a TRSCSSV at 2,000 prepared for the next lateral. clear of any potential ignition sources. ft and gas-lift mandrels. The view of the layout on the first well SECOND WEll – LATERAL #2 can be seen in Figure 6. DRILLING PHASE — Due to problems not associated with this FIRST WELL - LATERAL #1 project, the source of diesel was lost. HAZARD ANALYSIS Final live gas rig training was done for The decision was made to continue with The process of hazard identification all crews prior to milling the casing for the project using a 2% KCL brine as the and hazard mitigation was broken into the first lateral. Once competency of the drilling fluid. The second lateral was several steps for the Lisburne CT-UBD crews was assured, the first window was drilled from 8,960 ft to 9,748 ft. Injection project: milled at 10,732-ft MD, and underbal- rates ranged from 1.6 bpm liquid to 1.7 anced drilling commenced. As planned, bpm with gas injection rates from 4.0 1. Preliminary Hazard Identification drilling started with a 2% KCL fluid to MMSCF/d to 4.5 MMSCF/d for a BHP study (HAZid) was designed to identify mitigate risk until the crews gained between 2,850 psi and 3,350 psi. the initial level project hazards. comfort in the operations. Similarly, Following a trip for a BHA change, it the well was killed for the first trip (all 2. A two-day detailed HAZid was con- was not possible to pass a mudstone at subsequent trips were done live using ducted at the well site to further identify 9,408 ft. Multiple attempts to pass the pressure deployment/un-deployment project hazards and categorize each one mudstone failed. The decision was made techniques). by probability of failure and risk. to abandon this lateral and sidetrack to avoid the problem zone. 3. A two-day detailed Hazard and After the crews gained confidence, the Operability Analysis (HAZop) was con- fluid system was switched to diesel.