A new design enables West Texas operators to use a more cost-effective approach in deep Devonian completions.

Many reservoirs that could benefit from the implementation of multilateral technology are limited because each lateral wellbore must be selectively stimulated to facilitate production. Few multilateral systems are available to provide this functionality. A new technique has been developed, which was successfully implemented to complete a multilateral well in West Texas.

Permian Basin operators were struggling to develop a deep Devonian limestone reservoir for the growing domestic natural gas market. These operators were spending millions of dollars just drilling down to the productive horizon, at almost 12,000 ft (3660 m), and all of them were looking for a way to maximize the productivity of that investment.

To the asset managers in West Texas, the potential for cost savings by using multilateral technology was as plain as day: Instead of drilling two wells to drain their acreage, they could simply drill one multilateral well.

But there was a problem. The highly diagenetic carbonate formation is ruthlessly tight, offering less than 0.01 millidarcies of natural permeability. For this reason, the long horizontal wellbores that drain the reservoir must undergo a very expensive acid-frac stimulation treatment to become economically productive. The challenge was put forward to the service companies: Find a solution that will allow a multilateral well to be drilled and completed in the Devonian formation.

Multilateral well design

Drilling the multilateral well in this field was relatively straightforward. The well design was not allowed to become substantially more complicated until the completion and stimulation phase. Sperry-Sun has drilled and completed more than 410 multilateral junctions to date, and this well required nothing more complicated than the standard 7-inch. casing re-entry drilling system (MillRite) to construct a basic level 2 junction.

It was decided very early in the planning of this well that the junction would need only to subscribe to the TAML level 2 definition because it was to be constructed in a very hard, consolidated chert formation. (Chert is diagenetic quartz, a siliclastic rock that has a very high hardness and compressive strength.) Cement at the junction was not a requirement because there was no need for zonal isolation in the lateral wellbore. The strength of the chert formation eliminated the need for a connected junction and allowed the 41/2-in. pre-perforated lateral liner to be simply "dropped off" several feet outside of the main bore casing.

Controlling the geometry of the casing exit window is critical to multilateral operations. Poor window geometry can introduce positioning and lateral liner re-entry risks to a multilateral well. Oftentimes, conventional milling systems do not cut a straight casing window - the mills are often poorly controlled as they cut through the casing, and poor control creates a window that veers to one side or terminates prematurely. To alleviate these issues, the system was used to mill the casing exit window because of its ability to create a long, straight window.

A latch coupling, which serves as an anchoring point for the whipstock, was installed as a part of the main bore 7-in., 26-1b, P-110 casing string. It was positioned in the casing string at approximately 11,800 ft (3,599 m), in vertical hole, just below the depth at which the casing window was to be milled. Designed to have the same inside diameter (ID) as the API drift of the casing string, the latch coupling ensures that no restriction is created. In older wells, this latch coupling device can be installed on a permanent anchor packer to latch the multilateral drilling tools on depth and orientation.

After the casing window was milled, the milling assembly was pulled out of the hole. The drilling whipstock was run in and latched into the latch coupling. The lateral wellbore was drilled off the whipstock with 25? doglegs until the wellbore was landed horizontally. The approximately 4,000 ft (1,220 m) long horizontal section was then drilled, and the 41/2-in., 12.6-1b, L-80 lateral liner was installed.

The 41/2-in. lateral liner was placed approximately 5 ft (1.5 m) outside of the window and a gamma ray logging tool was run to confirm that the radioactive pip tags were correctly positioned. The pip tags were installed in the whipstock and the top of the liner so that measurements between them would correlate to the exact placement of the liner.

The position of the liner was very important because a seal bore receptacle with 3.688-in. ID was included near the top of the liner string to be used as a sealing point for the upcoming stimulation operations.

The primary concern about treating a multilateral well at high pressure is the effect that high pressure will have on the rock formation at the junction. If the fracture gradient of the formation at the junction is exceeded, the formation there could break down and fluid would be pumped into the vicinity of the junction rather than the reservoir. Without protection from the acid and pressure, the junction would potentially be destroyed. The matrix material of the formation there would be dissolved, causing the integrity of the wellbore to break down.

There are very few multilateral junction systems that could be installed to withstand high-pressure stimulation, and those systems typically would fall within TAML level 5 or 6. The economics of this particular field development did not favor an expensive level 5 completion, nor was it practical to change the drilling program to accommodate a splitter-style level 6 junction. Current expandable-type level 6 junction technologies have not yet developed to withstand high-pressure regimes. Therefore, a temporary level 5 completion was designed to isolate the junction from the stimulation fluids.

The junction isolation tool (JIT) was designed to be installed on a Versa-Trieve packer, which is a hydraulically set, retrievable packer with a very high differential pressure rating of 10,400 psi. This packer has, on its bottom, a tailpipe assembly approximately 60ft long with a 3.688-in. locating seal assembly. The complete assembly was no longer than 70 ft (21 m) with a 2.996-in. ID, a length that did not substantially increase the pressure losses during pumping. If, in contrast, the straddle assembly were installed with tubing from surface, friction losses inside the total length of a 3-in. ID tubing would make the pumping pressure far too high.

Another very interesting design feature included with this system was an internal string of 23/8-in. tubing inside the JIT assembly. This inner string allowed for a pressure test of the locating seals before the packer was set. This option is important because the seal assembly was being pushed across a specialized re-entry whipstock into a multilateral junction and it was critical to know that the seals were capable of holding a high-pressure seal before the packer was hydraulically set. If the seals were damaged, it would be apparent because the pressure test would not be successful and the assembly could be re-run with minimal downtime. The details of this particular design feature have been filed for protection with the United States Patent and Trademark Office.

The seals were landed on depth (which was verified by a no-go indication), and the internal string was pressurized to 3,000 psi to test and confirm a positive seal inside the lateral liner.

After the acid-fracture stimulation job was pumped, the well was produced for several days to recover as much of the stimulation fluid as possible. A packer-retrieval tool was then run into the hole and used to unset the packer. The complete JIT assembly was pulled out of the well and laid down on surface. Seal assemblies and packers were sent into Odessa, Texas, to be re-dressed for subsequent operations.
The lower lateral was to be completed in much the same way. The multilateral junction also needed to be protected during the second of the two acid-frac stimulations (one for each of the lateral wellbores). In this case, a re-entry whipstock was not required because the seal assembly was going straight down into the top of the lower lateral liner. The lower lateral liner was installed with a conventional liner hanger, but it also included a 3.688-in. ID seal bore receptacle to receive the JIT seals.

The stimulation program for the lower lateral was exactly the same as that of the upper lateral of the multilateral well. The junction was isolated by the same JIT assembly with a slightly longer space-out to seal into the top of the lower 41/2-in. liner. The total length of this assembly was almost 100 ft (30.5 m) in order reach the liner top. It was important to keep the length as short as possible to minimize friction losses inside the straddle assembly.

The acid-frac stimulation was successful, and the well was placed on production for several days. After most of the stimulation fluid was recovered, the packer retrieval tool was used to pull the packer and retrieve the complete JIT assembly.

With the completion of the world's first selective, high-pressure stimulation of a multilateral well using a junction isolation system, the well was turned over to production operations personnel. It was finally completed with 23/8-in. tubing landed just above the junction on a 7-in. production packer. The well is currently producing commingled gas and gas-condensate from two different horizontal legs that drain the northwest and southeast quadrants of the acreage, respectively. Production rates are satisfactory for the reservoir quality in the area, and the combined dual-lateral production rivals that of the best conventional wells in the region.

The successful completion of this project has prompted West Texas operators to consider more of their Devonian drilling plans as multilateral candidates. The precedent has been set, namely that most wells should be considered for the implementation of multilateral technology before the planning and economic evaluations are complete. Asset managers are also becoming more aware that conventional drilling practices do not always maximize their drilling investments and that ignoring the feasibility of a multilateral project is to ignore their bottom line.