Eric R. Davis
Brian R. Buck
ConocoPhillips Alaska Inc.
Anchorage
Michael T. Triolo
BP Exploration (Alaska) Inc.
Anchorage
Rune Freyer
Consultant
Anchorage
Lee Smith
Alaskan Energy Resources Inc.
Anchorage
In multilateral wells where high costs, shallow depths, and long step-outs present completion difficulties, the use of swelling rubber packers (SRPs) enables operators to manage annular fluid flow, control solids-shale production, and achieve cost-effective zonal isolation.
SRPs are facilitating multilateral well completions in Alaska’s viscous oil reservoirs. The packers allow longer lateral lengths with less along-the-lateral commingling, lower well costs, and better future remediation options.
By isolating water-sensitive shales, the technology provides a cost effective way to efficiently develop a previously bypassed formation.
Slip-on SRPs also are used in viscous oil developments and have helped minimize solids and shale production so that a well maintains flow where previous nonisolated completions required multiple cleanouts to constantly reinitiate production or else were shut-in.
With no moving parts and no service tools or surface operations required for activation or installation, SRPs allow operators to reduce installation complexities and significantly cut costs for rig time and materials.
Installation of SRPs results in an overall superior development strategy that can significantly change the risk profile of operations. With simpler and more effective zonal isolation solutions, operators can have more confidence in programs that target more difficult and higher risk marginal reserves.
Alaska’s North Slope
The North Slope of Alaska contains an estimated 20-25 billion bbl of highly viscous oil at relatively shallow depths under 1,800 ft of frozen permafrost. Operators historically bypassed such resources for deeper, warmer, less viscous oil until the advent of horizontal multilateral wells and improved drilling fluids.
Currently, companies produce the viscous oil in the West Sak (WS) and Schrader Bluff (SB) sandstone formations through horizontal multilateral wells completed with big-slot slotted liners without downhole sand control. Instead of sand control, they employ a proactive drawdown strategy to minimize downhole sand production in conjunction with surface sand-management strategies.
Operators also have started to complete even heavier, more viscous oil in the shallower N-sand sequence. These completions have horizontal laterals that include downhole sand exclusion.
The recent application of SRPs has enabled operators to manage annular fluid flow, control solids and shale production, and achieve zonal isolation in multilateral wells where formation characteristics dictate complex wellbore geometries.
Dozens of North Slope multilateral wells now have SRPs that successfully isolate interbedded shale zones behind blank pipe, fault crossings along the lateral, and inadvertent zonal crossings during kick off from the parent bore.
Swelling-rubber packers
SPR technology is based on the swelling properties of rubber in crude or mineral oil-based mud (MOBM). These properties can be specifically designed to expand the packer over time to seal the annulus.
The SRP consists of a standard oil field-grade tubular with layered rubber bonded along its length. The rubber element swells through absorption of hydrocarbons, either from the reservoir, the drilling fluid, or a specially formulated spotted fluid.
The swelling, which is uniform along the element length, can cause a change of several hundred percent in the rubber volume when the packer is unconfined. The swelling process is time-dependent and controlled primarily by the viscosity and temperature of the hydrocarbon being absorbed.
The swelling pressure is different from the sealing pressure of the packer. The sealing pressure is the maximum estimated pressure differential across the element. The sealing ability depends on the absolute swelling (hole size vs. packer dimensions), not the swelling fluid.
The deployment fluid, however, is a consideration in SRP design because it is hydrocarbons that activate swelling. Deployment in an oil-based mud system typically requires a packer with a multilayered construction to delay the onset of swelling as the packer is being deployed into the well.
The multilayered packer design consists of a high-swelling inner core surrounded by a low-swelling outer layer and a diffusion barrier. The outer two layers typically delay the onset of swelling by 72 hr, but this property can be tailored to the application. With Alaska’s low-temperature viscous oil, 70-90° F., tests showed that even with use of oil-based mud, the diffusion layer was unnecessary; so it was eliminated.
Operators can employ different SRP configurations and sizes depending on the downhole conditions and the drilling fluid used.
The two standard configurations are: standalone subs and slip-on sleeves. Industry standard lengths for the standalone sub element length range from 10-20 ft, while the slip-on sleeve elements are typically 12-in. long. Both, however, can be manufactured to meet the needs of a specific application.
Because the packer has no moving parts and requires no surface or downhole activation, deployment is straightforward. The SRP is made up as part of the completion or casing string and deployed with the assembly in a single trip.
Viscous oil production
The first hydrocarbon swelling rubber packer was installed in the Norsk Hydro AS’s Grane heavy-oil field in the Norwegian sector of the North Sea in 2001. Since then, the technology has had extensive development for a variety of conditions and applications, including the low temperature, heavy-oil reservoirs of Alaska.
North Slope viscous oil reservoirs are in the WS and SB sandstone formations in the West Sak, Orion, and Milne Point developments (Fig. 1). Both WS and SB formations share similar reservoir characteristics such as very fine to fine-grained, single and amalgamated sandstone-siltstone beds. Both reservoirs consist of vertically stacked sand intervals separated by siltstone intervals and are between 3,000-5,000 ft true vertical depth (TVD), with depths trending deeper towards the east.
In addition, both formations have oil viscosities at reservoir conditions that range from 10 to 3,000 cp, with oil API gravities between 16 and 24. This high-viscosity crude combined with unconsolidated reservoir rock tends to cause solids production, resulting in the desire to employ low cost solids control techniques in these wells.
In addition to the WS-SB sand sequence, the shallower N-sand has even heavier, more viscous oil. This sequence is slightly higher on structure and more unconsolidated than the WS-SB reservoir and consequently presents different challenges. In particular, proper well design for commingled production from both the N-sand and deeper sequences within a single well depends largely on the thickness of the sealing siltstone above the target sand-a characteristic that has resulted in some very complex, undulating, and inverted well designs.
West Sak
At West Sak, application of SRP technology has allowed for a cost effective way to efficiently develop a previously bypassed formation.
The West Sak reservoir has three primary sandstone targets, designated D, B, and A. Operators access the upper two zones (D and B) with long horizontal slotted liner completions. But the lower zone (A), separated by shale layers, was uneconomic to complete with a separate lateral.
One attempt to produce this zone used a horizontal undulating well completion, drilled in 2003, and completed with a preperforated liner without shale isolation. The well, however, could not maintain production because wellbore solids collapsed and blocked off flow in the liner on multiple occasions.
The next well completed with the lower zone included the first application of a slip-on SRP on the North Slope. The trilateral well completion, drilled in 2004, has 12 slip-on SRP devices installed on a blank liner across shale zones to isolate the water-sensitive shales from inside the slotted liner (Fig. 2). The liner with SRPs was run successfully in the hole without incident or lost time.
The zone drilled in this initial well and now being developed in subsequent wells contains about 20 ft of net pay separated by one or two shale layers. Depending on the well, the geologic structure is either two 10-ft sand packages separated by a 10-ft shale, or three thinner sand packages separated by two shale layers.
To date, all 11 subsequent wells with SRPs have experienced no noticeable torque and drag losses, even with up to 21 SRP slip-on sleeves on a long liner. More importantly, as shown through production logs and geochemical fingerprinting, all trilateral wells have maintained production from the lower zone without being blocked by solids.
In fact, throughout North Slope viscous oil developments, the use of slip-on SRPs has minimized solids or shale production. The wells have maintained flow even where previous nonisolated shale completions required multiple clean outs for restarting production, or where wells plugged of with shale and were shut in.
Orion
At Orion, the operator has a multiple strategy for SRPs, with both short and long-term objectives.
The stratigraphic sequence of the SB reservoir within the Orion development differs slightly from that in the WS reservoir. Orion’s SB reservoir is deeper than in either West Sak or Milne Point, and has better-developed, thicker sand intervals which lend themselves to economic development with single laterals.
The warmer SB reservoir at Orion, however, is both a blessing and a curse: Along with the reservoir heterogeneity, the temperature-induced variation in crude quality between different laterals tends to complicate lateral production expectations and reservoir management strategies.
Current development consists of horizontal multilateral producers with TAML (Technological Advancement of Multilaterals) Level-3 junction systems and42⁄3-in. slotted-liner completions (63⁄4-in. hole size). Each multilateral well has three to five horizontal laterals and exposes 15,000-27,000 ft of reservoir, with an average lateral length of 4,000-7,300 ft.
MOBM is the drilling fluid of choice, with displacements to solids-free MOBM prior to completing each lateral.
Liners are run after pulling the whipstock via a bent joint; consequently anything run in conjunction with the liners has to be configured accordingly so as not to hang up in the window while running.
Sand interval thicknesses range from 10-25-ft with permeability sweet spots ranging from 5-15 ft. The horizontal laterals fairly often cross unforeseen faults, either sub seismic or shadowed by other faults along the laterals. These faults can have throws of 5-3 ft and can cause inadvertent drilling out of zone into the overlying or underlying sand intervals, resulting in along-the-lateral commingling.
This form of commingling is undesirable from a reservoir-management perspective because of the variations in rock quality, oil quality, and expected water breakthrough potential. Thus, when commingling occurs in conjunction with significant variations in rock and oil quality, the wells include SRPs and blank liners for isolating the interval from the reminder of the lateral (Fig. 3).
The operator intentionally drilled one horizontal multilateral well at Orion downstructure toward the aquifer to optimize the development pattern within the polygon. The risk to water breakthrough at the toe of each lateral was considered very probable and, if it were to occur, would completely eliminate oil production. In this case, the well included two standalone SRPs per lateral, strategically placed half-way and two-thirds down the lateral, to allow future through-tubing lateral segregation (Fig. 4).
These SRPs went through unprotected windows and out to depths as far as 11,170 ft measured depth (MD) or 3,500 ft in the horizontal open hole. The operator intentionally placed them within planned shale exit points along the lateral further to increase the likelihood of slowing the imminent migration of water along the lateral throughout the life of the well.
The completion included four joints of blank pipe on either side of each packer to isolate the shale and provide adequate space to position inflatable packers on coil tubing. Drag data, acquired for all liners run, showed negligible effects on friction factors or slack-off weight. The SRP standalone subs did not affect significantly the liner installation in these shallow extended-reach wells.
In these wells, SRPs initially help to minimize silt production across intervals where deviations occur from the sand, and ultimately the packers help reduce along-the-lateral commingling that could complicate the understanding of individual lateral production, providing both short and long-term benefits.
Milne Point
At Milne Point, SRPs facilitate well-design changes that allow a previously bypassed sand sequence to be incorporated into an already successful multilateral development.
Several well designs have achieved the necessary downhole sand control to enable the addition of an N-sand lateral within an existing O-sand multilateral well. (Fig. 5) The major factor that determines well design in this application is the thickness of the sealing siltstone above the target sand.
The N-sand sequence is similar to the underlying O-sands in that siltstones separate each interval. In addition, sand sequences above the N-sand siltstone are often wet, so that isolating the lateral is essential for preventing potential water production.
A well in which the siltstone interval is too thin to set a junction and stand-alone SRP with sufficient separation from the overlying and underlying sands requires an inverted well design. Such a design makes it difficult to plan landing points, is difficult to drill, and does not accommodate efficient reserves access. As a result, the N-sand lateral, being in most cases bound on all sides by faulting or nearby wells, is often shorter than desired, with a landing point as much as 1,000 ft from the mainbore.
If the overlying siltstone is thick enough, a junction and SRP sub can achieve the necessary isolation from the sands to prevent water or sand production from behind the SRP sub (Fig. 6). To date, Milne Point has three wells completed with this design. All produce as forecast with sand production falling within planned quantities and grain-size distribution.
The SRPs have achieved sufficient sand production isolation to allow incorporating an N-sand lateral economically into an O-sand multilateral well. When reservoir conditions allow, this design results in longer N-sand lateral lengths, less tortuous trajectories, cheaper well costs, better future remediation options, and an overall superior N-sand development strategy.✦
Based on a presentation to the SPE/PS-CIM/CHOA International Thermal Operations and Heavy Oil Symposium, Nov. 1-3, 2005, Calgary.
The authors
Eric R. Davis (eric.r.davis@ conocophillips.com) is the Northeast West Sak project coordinator with ConocoPhillips Alaska Inc. Previously, he has worked of projects in upstream technology and with ConocoPhillips US and international operations. Davis has a BS in petroleum and geosystems engineering and a masters of engineering from the University of Texas at Austin. He is registered professional engineer in Alaska and Texas.
Brian R. Buck is a completions engineer for the North Slope and Cook Inlet operations for ConocoPhillips Alaska Inc. Buck has a BS in chemical engineering from the Colorado School of Mines.
Michael T. Triolo is the Western Regional Development projects drilling lead for BP in Alaska. Previously he worked as an operations drilling and completion engineer in numerous Alaskan North Slope drilling programs. Triolo holds a BS in petroleum engineering from the University of Alaska, Fairbanks. He is a member of SPE and AADE.
Rune Freyer is an adviser for Easywell in Alaska. He was formerly the Easywell general manager responsible for developing the swell technology before Halliburton’s acquisition of Easywell. Before developing Easywell, Freyer worked for Schlumberger Ltd. Freyer has a BSc in mechanical engineering, and a BSc in petroleum engineering.
Lee Smith is president of Alaskan Energy Resources Inc., Anchorage. He has held various operations and marketing positions in the US and international oil and gas industry. Smith holds a BS in geology from University of Utah and a MBA from Oklahoma City University.
