Gary Collins
Marathon Oil Co.
Houston
Rod Bennett
Baker Oil Tools
Houston
A downhole multiwell drilling template, called a downhole splitter, allows two wells to be drilled cased, and completed from one well bore.
After completion, each well can be produced, serviced, and worked over independently of the other. The downhole splitter was successfully field tested in Wyoming.
The downhole splitter is suitable for use on offshore platforms, subsea completions, offshore exploitation and delineation wells, inland waters, and onshore in environmentally sensitive areas. It is also ideal for planned multilateral or multivertical completions.
The splitter can reduce the size of a platform planned (reducing cost) or increase the number of wells that can be drilled from an existing platform. The splitter also reduces drilling time and cost because one common surface hole is shared.
DOWNHOLE SPLITTER
A splitter well shares conductor and surface casing and allows two well bores to be drilled from one at surface. The sequence of drawings in Fig. 1 shows the basic steps in drilling the two well bores with the splitter.
The splitter is placed on the bottom of the surface casing which is run in the hole and hung off conventionally in the wellhead (Step 1).
Once the splitter and surface casing are in place, a riser, which consists of an anchor latch seal assembly, is run and landed in the first side of the splitter (Step 2). This side of the splitter contains conventional cement float equipment, and the surface casing is cemented through the riser. The float equipment and cement are then drilled out, and the casing shoe is tested. The first well is directionally drilled to total depth (TD) and logged. A conventional liner, with a no-go hanger and liner top packer, is run to depth and hung off in the splitter.
The liner is cemented and the liner top packer is set (Step 3). The riser is released from the first side and automatically oriented 180 from the first well to the second side. The riser is stung into the second side of the splitter, and the second well is directionally drilled to TD and logged.
A second liner is run and cemented as previously outlined (Step 4).
The riser is pulled, and the wells are tied back into the existing liner tops and hung off in a special dual-bore wellhead at the surface (Step 5). The wells are now ready for completion as two individual wells.
PROTOTYPE DEVELOPMENT
The downhole splitter system was conceived in April 1992 in response to the increasing need to develop expensive reserves more economically. The tools and process are being patented by Marathon Oil Co. Baker Oil Tools and National-Oil-well participated in prototype development.
In July 1992, funds were requested to build splitter prototype tools, and all of Marathon's domestic regions were asked to investigate and identify potential drilling prospects for pilot testing the tools. Selection criteria for the pilot test involved limitations regarding cost, maximum displacement of two targets, maximum hole angles, timely approval by working interest owners, and engineering confidence in the economic viability of the wells.
Despite the limitations, several prospective options were submitted. The top proposals for testing this type of technology were all in the Garland field in Wyoming. The Garland field had the most appeal because of the 5-acre close proximity of the wells, the proven success of the 5-acre development program being conducted in the area, the sole working-interest, and the relatively low drilling cost. The two wells were Utah-Wyoming Nos. 10 and 11.
Prototype development began in October 1992, and laboratory testing of the tools was completed in February 1993. A primary consideration was to make operation of the splitter system simple and straightforward.
Some of the key issues that needed to be addressed included the following:
- The orientation of the riser into the two sides of the splitter is accomplished by moving the riser and orienting cam up and down a J-slot cut into the cam, which is engaged with an orienting lug attached to the splitter (Fig. 2). A spline joint provides ease in spacing out the riser.
- The riser is released from the orienting cam by right-hand rotation. Slacking off on the riser engages the splitter.
- The riser is released from either side of the splitter also by right-hand rotation. Straight pick up of the riser re-engages the orienting cam so the riser can be easily oriented into the desired position.
- The liner hanger system incorporates a no-go ring in the splitter and a no-go liner hanger with a packer. The no-go liner hanger sets on the no-go ring, and the packer provides a secondary seal to the cement.
- Liner tiebacks are used to tie back the two wells to surface.
- The wellhead system is designed to accommodate a mandrel hanger for the drilling riser that connects the splitter to the wellhead (Fig. 3).
- The wellhead system is also designed to accommodate a dual-bore hanger to separate the two wells at surface and provide individual access (Fig. 4).
WELL PLANS
Utah-Wyoming Nos. 10 and 11 are two wells designed to share a common surface location and surface casing. Individual production casings were cemented in place to ensure mechanical isolation. The riser to connect the 20-in. splitter to the wellhead equipment was 9 5/8-in. STC casing.
CASING PROGRAM
Fig. 5 shows the actual casing programs for Utah-Wyoming Nos. 10 and 11. The planned casing programs were as follows:
- 26-in. conductor casing cemented in a 36-in. hole at 60 ft MD
- 20-in. splitter run on the bottom of 20-in. surface casing cemented in a 24-in. hole at 650 ft MD
- 7-in. production casing in an 8 3/8-in. hole at 4,694 ft MD in Utah-Wyoming No. 10
- 7-in. production casing in an 8 3/8-in. hole at 4,694 ft MD in Utah-Wyoming No. 11.
- Both wells tied back to surface with individual strings of 7-in. casing.
DIRECTIONAL PROCEDURE
- Drill Utah-Wyoming No. 11 out of the first side of the splitter, and establish a walking tendency. Make a motor run to correct for direction, and angle to hit target.
The bottom hole target is a 50-ft radius cylinder from the top of the target at 3,894 ft true vertical depth to TD. The total displacement is 285 ft at a direction of N 71.6 E. Natural drift is N 34 E (Fig. 6).
- Drill Utah-Wyoming No. 10 out of the second side of the splitter with a mud motor. Using the walking tendency established in the first well, lead the second well, and allow it to walk into the target.
The bottom hole target is a 50-ft radius cylinder from the top of the target at 3,894 ft to TD. The total displacement is 425 ft at a direction of N 1 W (Fig. 7).
FIELD TEST
Utah-Wyoming Nos. 10 and 11 were successfully drilled in March and April 1993 using the splitter. The successful completions proved that two wells can be drilled and completed individually from one well bore.
This significant milestone was not achieved without problems, however. Fig. 8 shows the planned and actual days vs. depth curves. These two wells had 10 days of problem time resulting in a cost over-run of approximately $100,000. Except for these problems, all went as planned. The problems were as follows:
- The drilling riser failed.
- The collet on the riser seal assembly did not release.
- The orienting cam did not come out of the hole with the riser following a mechanical cut on the collet.
- Bit cones were lost in the hole during drilling out the aluminum plug on the second well.
The first three problems resulted from damage that likely occurred during the initial drill out of the float equipment on Utah-Wyoming No. 11. The damage is believed to have been caused by compression of the drilling riser. The 9 5/8-in. drilling riser system connecting the splitter to the wellhead was spaced out using a 10-ft spline joint placed at the top of the riser, which in turn caused the riser to be in compression. Rotation through the riser (which was in compression) with drill pipe caused the riser to fatigue and break at two couplings. The last break occurred two joints above the orienting cam.
Attempts to release the collet latch on the riser seal assembly from the splitter after the riser failed were unsuccessful. The riser failure caused the problem with the collet latch not releasing. It is believed that the threads on the collet latch and the splitter galled together because of the riser rotating after it failed. The riser was tied back to the surface via a casing patch and placed in tension with casing slips in a conventional wellhead. Utah-Wyoming No. 11 was successfully drilled, and the liner was cemented without additional problems.
The collet on the riser was then cut at the splitter with a conventional hydraulic cutter. The riser was removed; however, the orienting cam did not come out of the hole with the riser. The orienting cam was successfully speared and retrieved on the first attempt. Examination of the orienting cam showed that the riser failure caused the problem with the orienting cam. The threads on the running nut attaching the riser-seal-assembly collet latch to the orienting cam were found rounded and fatigued.
The orienting cam was repaired, a new riser seal assembly was built, and the riser was engaged in tension to the second side of the splitter to drill Utah-Wyoming No. 10. While the aluminum plug was drilled out on the second side of the splitter, three cones on the bit were lost in the hole. The cones were successfully retrieved, and Utah-Wyoming No. 10 was drilled and cased without additional problems.
The riser was released according to design and removed from the well. The two wells were then successfully tied back to surface. The wells were completed and are currently producing.
It is important to note that once the riser was placed in tension, no additional problems with the riser occurred on either well. The fishing operations on the drilling riser, collet latch, and orienting cam proved that conventional fishing tools can be successfully used to retrieve the riser assembly from the splitter.
SYSTEM COMPONENTS
All problems that occurred with the splitter system on the test wells can be overcome with additional engineering and modifications to the tools. These problems have been reviewed by Baker, National, and Marathon personnel involved with the design and running of the tools. Joint observations, modifications, and recommendations to the splitter system are as follows:
RISER
Premium connections on the riser should be used instead of the eight-round connections used on the prototype. There are three reasons for this recommendation: Premium connections would enhance the ability to rerun the riser and minimize damage to the threads. Premium connections are shouldered connections that are able to withstand higher torque, and they do not have the tendency to continue to make up and gall as does an eight-round connection. Right-hand rotation of drill pipe through unsupported eight-round casing could cause the connection to back out, which is less likely if a premium connection is used.
A spline joint is not an acceptable tool to space out the riser. The use of a spline joint forces the riser to be placed in compression. Rotation through the riser in compression caused the fatigue damage to the riser.
A wellhead system that allows the use of a mandrel hanger to place the riser in tension is preferred to a wellhead system that uses slips to place the riser in tension.
A mandrel hanger used in the future should have an antirotation device incorporated in its design to prevent damage to the hanger caused by drill pipe torque.
The tensile strength of the riser collet latch should be increased from 125,000 lb to a minimum of 400,000 lb. The higher tensile strength will withstand the added tension that is seen by the collet from possible high lateral loads between the riser and the drillstring in deep, deviated offshore wells.
The design should consider incorporating a shear-out safety release to the riser collet latch. This may not be possible, however, because of high lateral loads between the riser and drillstring which add tension to the riser's collet latch.
The design should also consider installation of a mule shoe stab-in guide to the bottom of the drilling riser. The mule shoe would allow the riser to engage either side of the splitter without the use of the orienting cam.
ORIENTING CAM
The orienting cam body should have circulation points to help prevent settling of well bore cuttings and debris inside the surface casing. Debris could cause a sticking problem while the cam is operated.
The orienting cam should have a shouldered connection for the lock ring that engages the riser seal assembly. The shouldered connection will improve torque requirements and prevent the connection from vibrating loose while drilling through the riser.
The close-tolerance fit on the orienting cam body should be loosened to prevent the cam from binding up while rotating through the riser.
SPLITTER
The aluminum guide shoe and plug should be replaced with a composite guide shoe and plug to prevent losing roller cones in the hole during the drill out.
Kick-off pads could be installed on the splitter frame to minimize possible directional interference.
LINER TIEBACK SEAL
ASSEMBLIES
A full mule-shoe guide nose should be used instead of a half mule-shoe guide nose.
DESIGN FOR FUTURE TEST
Additional engineering has been completed on the critical issues required to have a problem-free second test. Additional engineering for a second splitter test may be required once offshore candidate wells are identified.
The main issue of evaluating the effects of lateral loads between the drill pipe and the riser that will occur in a directional well on the riser assembly has been addressed.
Several worst-case scenarios were modeled to determine the maximum tensile load on the riser collet latch in a directional well. The riser collet latch as presently designed is capable of only 125,000 lb of tensile load before the set shoulder begins to deform. Modeling worst-case scenarios shows that tensile loads between the riser and the drill pipe will seldom exceed 330,000 lb.
A quick evaluation and modification of the design indicates that tensile loads of 400,000 lb on the collet are attainable by adding additional set shoulders to the collet.
The additional set shoulders would absorb a portion of the tensile load before the collet engages the primary set shoulder. A change in the metallurgy of the set shoulders of the riser collet could possibly raise the tensile loads to greater than 400,000 lb.
A mandrel hanger and wellhead system to place the riser in tension saves significant rig time compared to conventional slips. A hanger system that can be modified and engineered to accommodate the riser has been identified. This system has the necessary features required to manipulate, orient, and then lock the riser in tension. The system incorporates an antirotation lock mechanism to keep the riser from rotating during drilling.
The use of a spline joint will not allow the riser to be placed in tension. Therefore, the spline joint cannot be used as a space-out tool to engage the splitter. The new wellhead hanger system being considered is adjustable up to 4 ft and would provide the space out needed. Once the desired space out is obtained, the tool is secured in the desired position by locking pins. The riser tension and orientation can be adjusted by re-engaging the hanger and backing out the locking pins.
A kick-off pad should be added to the frame of the second side of the splitter on future wells. The pad will guide the bit directly into the formation and minimize possible interference at the closest point between the two splitter wells.
The next splitter application should have a cement or composite guide shoe and plug instead of an aluminum guide shoe and plug.
RESULTS
- Utah-Wyoming Nos. 10 and 11 proved that two wells can be individually drilled and completed from one well bore.
- Problems with the riser proved that conventional fishing techniques can be successfully used to recover the riser, collet latch, and orienting cam.
- All problems with the splitter system on the test wells can be overcome with slight modifications to the tools and procedures.
- The use of the splitter system offers economic and environmental advantages for some locations with surface restrictions.
ACKNOWLEDGMENT
The authors would like to thank Baker Hughes and Marathon Oil Co. for permission to publish this article. The authors extend special thanks to Doug Hall of National Oilwell, Lindley Baugh and George Melenyzer of Baker Oil Tools, and Marathon Oil Co.'s Rocky Mountain region drilling staff, particularly Richard B. Gideon and Mac R. Hansen.
