Drilling, completing, and fracturing of unconventional-formation wells in North America have become commonplace for producing natural gas. It is less common to drill, complete, and fracture treat multiple lateral branches from a single main wellbore. Augmenting a multilateral well with selective fracturing of each leg is as straightforward as fracturing a single-horizontal well. In this project, a plug-and-perforate system was used to address ten or more intervals in each leg, with average stimulation pressures of up to 9,000 psi.
Introduction
Multilateral solutions enable working within a limited surface area, generating a reduced footprint while draining a much larger volume of reservoir from a single surface location. A few multilateral wells can minimize the effect, visibility, and liability of drilling operations to drain the entire reservoir, especially in environmentally sensitive or protected areas. Potential advantages of a multilateral system can be broken into two broad categories. First, reserves can be increased or production can be increased or accelerated over the life of the well. Second, the tangible and intangible costs of the project can be reduced.
Stimulating a Multilateral Well
Earlier techniques in vertical wells used conventional perforating, typically followed by ball diversion for isolation. Horizontal wellbores were treated with a few widely spaced intervals (four to eight zones), then longer horizontal sections were treated (with up to 90 zones) by use of newly developed techniques and systems.
Originally, ball-actuated fracturing-sleeve completions were limited to 15 to 20 intervals because ball-size increments were limited by the internal diameter (ID) of the fracturing string. New systems are available in which additional subintervals are created within the original primary intervals. With this system, five metering valves, plus one baffled valve, can be placed within the previously defined single interval. Thereby, it is possible to have six valves within each of the (up to) 15 primary intervals, for a maximum of 90 valves or 90 points to initiate fractures within a horizontal wellbore, compared with the previous limit of approximately 15 intervals.
The fracturing sleeves use a metering system that enables a single ball to open five metered valves within an interval before landing on a baffle sleeve; all of the valves are within a single interval that is isolated by an openhole packer, such as a swellable packer. After the ball lands on the baffle sleeve, the casing-ID pressure is increased to open the baffle sleeve, during which time, the metered sleeves move to the open position for access to as many as six fracture-initiation points within the interval. Each sleeve has ports that could be plugged to allow every sleeve within a subinterval to be designed to specific flow requirements to maximize the stimulation treatment.
Unconventional Formations. Shale-gas reservoirs have low porosity and low matrix permeability, lack an obvious seal or trap, have a large regional extent, and in most areas are believed to be highly heterogeneous. Therefore, it is common to confirm reservoir thickness, evaluate rock properties, and determine horizontal shale-gas targets by use of vertical or pilot offset wells. Then, horizontal wells are drilled and stimulated to maximize reservoir exposure and enhance production.
Some multilateral completions, such as those used for unconventional formations, require only temporary junction isolation (JI), such as during high-pressure fracture-stimulation operations. All high-pressure treatments of multilateral wells require some form of junction as a means of selectively isolating each lateral for independent, controlled stimulation. In shale and tight gas plays, it is possible to fracture each leg of a multilateral well without compromising the integrity of the junction. To isolate the junction from the stimulation fluids, a temporary Technology Advancement of Multilaterals forum (TAML) Level-5 completion can be used. Level 5 is a multilateral junction that provides both mechanical and hydraulic integrity, achieved by the completion system, to provide pressure integrity at the junction.
Background
Fig. 1 shows the Granite Wash play in the northern Texas panhandle and in western Oklahoma. The tight-sand gas reservoir occurs in thick, stacked sand/shale sequences. The Granite Wash is present in several zones at depths from 9,000 to 12,500 ft. The Pennsylvanian Granite Wash is an alluvial wash consisting of 2,000 ft of stacked sandstones. Granite Wash is found in Beckham, Roger Mills, Custer, Washita, and Greer counties in Oklahoma and in Gray, Wheeler, Roberts, and Hemphill counties in Texas. Despite its low permeability and porosity as a tight-sand play, reservoir quality and porosity can be superior to those in most plays, and reserves can be large. High condensate yields from the preferred multistage, slickwater fracture treatments used in unconventional completions also contribute favorably to producer economics.
System Design
Selecting the casing-exit method was important because window geometry, specifically the geometrical precision with which a window is created, becomes increasingly important and critical with regard to the ability to deploy and recover tools and systems through the opening later. Poorly defined geometry, as shown in Fig. 2, creates a greater risk of damaging seals or packer elements when they are dragged through the window.
Premilled and precision-milled casing-exit systems were evaluated because they offer advantages over conventional casing exits. For this project, the precision-milled casing-exit system was selected. A precision-milled casing-exit system uses a track-guided milling tool to cut the casing in a manner that is as controlled and as accurate as possible, to replicate the geometry of a premilled casing window. It also has a junk basket to recover milling debris, and magnets can be run below it.
Because most horizontal wells in the Stiles Ranch field in the Texas panhandle targeted separate members of the Granite Wash reservoir, the operator chose to use a multilateral well to reach the A and B members of the Granite Wash from a single surface location. A multilateral well could double the reservoir exposure vs. a single-horizontal well, while allowing selective fracturing of the main bore and the lateral, with pressures up to 10,000 psi, resulting in commingled gas/condensate production from both legs of the completion. Typical single-horizontal wells in the area are 5,000 ft long and require stimulation with 10 to 15 fracturing stages.
Multilateral-Well Design. The selected design for this application consisted of a stacked TAML Level-4 dual-lateral well (Fig. 3), which has two parallel trajectories at different vertical depths and is used to drain different reservoirs or the same reservoir with enough thickness or permeability barriers to justify the additional leg. The lower, main-bore, leg would drain the Granite Wash Member B, and the upper leg would drain Granite Wash Member A. The well has a cemented expandable liner hanger and liner in the lower main-bore lateral and a cemented dropoff liner in the upper lateral. The well was planned to be selectively stimulated (plug-and-perforate method) by use of the JI system with 11 stages in the lower lateral and 10 stages in the upper lateral, then to commingle production of these legs.
Completion
Because hydraulic and pressure integrity (up to 10,000 psi) at the junction is important during stimulation, a JI system was used, which allowed each lateral to be stimulated at high pressure without concern of setting/retrieving packers in the lateral. The lower JI or upper JI system is associated with the lower lateral (main-bore) or the upper lateral, respectfully.
Lower JI System. The lower JI system and a hydraulic packer were run with 4-in. drillpipe (before releasing the drilling rig) with the seal assembly stung into the liner-hanger sealbore by use of 4½‑in., 13.5-lbm/ft P-110 tail pipe across the casing window. This configuration isolated the upper lateral from the lower-lateral fracturing pressures. The hydraulic packer was set 40 ft above the casing junction. A workover unit was used to run a 4½-in., 13.5-lbm/ft P-110 fracturing string with a ratch-latch seal assembly to land on top of the hydraulic packer.
Fracturing the Lower Lateral. Eleven stages were planned and pumped into the lower (main-bore) lateral. Total volumes included 2.2 million lbm of proppant and 155,000 bbl of fluid, for an average of 200,000 lbm/stage of proppant and 14,000 bbl/stage of fluid pumped. A waterfrac plug-and-perforate completion method was performed down the 4½‑in. fracturing string. The average treatment rate was 72 bbl/min at 7,200 psi, with maximum observed rate and pressure of 76 bbl/min and 9,200 psi, respectively. Proppant concentrations began at 0.25 lbm/gal and increased to a maximum of 1.5 lbm/gal, with multiple sweeps run throughout for an average pump time of 3.75 hr/stage. All eleven stages were placed without the use of gel and were completed over the course of 5 days. The plugs were drilled out, and the well was flowed for 3 months.
Upper JI System. The upper JI system had to be modified because of a poor cementing job on the 4½-in. lateral liner and because of dropping the transition-joint and polished-bore-receptacle assembly 14 ft into the openhole section. It was decided to bond swellable material onto the seal assembly and run slip-on swell packers on the 4½-in. tail pipe across the casing window to support the exposed open hole out of the window. As a result, new equipment was ordered and manufactured to meet the new requirements.
Fracturing the Upper Lateral. Ten stages were planned for the upper lateral, of which nine were completed successfully. Total volumes for the job were 2.15 million lbm of proppant and 132,000 bbl of fluid for an average of 215,000 lbm/stage of proppant and 13,000 bbl/stage of fluid. The completion method was a waterfrac design with plug-and-perforate isolation down a 4½-in. fracturing string. The job treated at an average rate of 71.5 bbl/min and an average surface pressure of 8,500 psi. The maximum observed rate and pressure for the upper lateral were 86 bbl/min and 9,500 psi, respectively. Unlike the lower lateral, the upper lateral required linear gel to place the proppant. The proppant concentration began at 0.25 lbm/gal and was increased to a maximum concentration of 1.5 lbm/gal, with several cleaning sweeps in between for an average pump time of 3.85 hr/stage. One of the stages was aborted after several attempts were made to break it down with no success, which caused the completion to take longer than planned—a total of 7 days to complete. The plugs were drilled out, and the well was flowed for 3 months.
Results
A 7×4½-in. multilateral junction was constructed at 12,241-ft true vertical depth, and two 5,000-ft lateral horizontals were drilled. The main and lateral wellbores, including the junction, were cased and cemented. A JI system was installed to create a temporary TAML Level-5 junction to provide selectively controlled stimulation of the main-bore and lateral horizontals. Both laterals were stimulated; the main-bore horizontal was fracture treated first with 11 stages and a maximum pressure of 7,800 psi, then the lateral horizontal was fracture treated with 10 stages and 8,900‑psi maximum pressure.
The operator realized USD 2 million in cost savings in this first application, compared to drilling two single-horizontal wells, while doubling reservoir exposure and increasing production with an initial rate of 6 MMcf/D per lateral. The well is producing commingled gas and condensate from both laterals through a single tubing string into the field gathering system.
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163959, “Unconventional-Shale-Play Selective Fracturing Using Multilateral Technology,” by Doug G. Durst, SPE, and Mario Vento, SPE, Halliburton, prepared for the 2013 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 28–30 January. The paper has not been peer reviewed.