RAPID ADVANCES IN DRILLING and completion technologies in the 1990s increased usage of multilateral well applications around the world. Building upon directional and horizontal drilling techniques developed during the 1980s, multilateral methods have enabled operators to increase recoverable reserves while decreasing drilling, completion, and environmental costs.
In 1998, multilateral technologies were evolving toward intelligent well completions, in which underground gathering, fluid processing, and injection systems are outfitted with surface-adjustable chokes and pressure, temperature, and flow-rate gauges.
History
The practical use of multilateral technologies dedicated to oil field applications began in the U.S. in the 1940s and Russia in the 1950s.
According to a 1939 article in Petroleum Engineer, the first U.S. endeavor began when Leo Ranney, president of Ranney Oil Mining Co., drilled an 8 ft vertical shaft and put mining machinery and men at the bottom of the hole in a small field near McConnelsville, Ohio.
Journalist Bill Rintoul later described the project in an article in the Bakersfield Californian. "They used the machinery to drill horizontal holes radially like the spokes of a wheel," he wrote.
In a classic 1954 paper on later drainhole drilling, H. John Eastman wrote of Ranney`s second endeavor in Venango County, Penn. "Ultimately, four 1,000-ft laterals and four 600-ft horizontal holes were drilled. The first two long holes produced by gravity, and 1 month after the drilling was completed, total production from the holes was 20 bo/d. This was considerably more oil than the 20 conventional wells yielded, and their production was not affected."
Curved drill guides
After World War II, inventor John A. Zublin began drilling horizontal "drainholes" for J. Paul Getty and others in the California oil fields. According to Casper Zublin, Zublin`s son, "My father drilled multiple drainholes, as many as four going in different directions but no closer than 10 ft apart vertically."
Early on, multilateral wells exhibited enhanced production capabilities. In 1945, J. Zublin sidetracked a well originally drilled in 1918 in Midway-Sunset field. According to Eastman, "Eight drain holes were drilled in the oil zone below the 121/2-in. casing [string]...each one averaging 53 ft in length. Six 6-in. turbine bits were used [to drill] the holes between 883 and 929 ft depth." Production immediately increased to 25 bo/d from 3 bo/d.
In 1948, Zublin abandoned turbines, redesigning the bottom hole assembly so that ordinary rock bits could be used. According to his son, this drilling system comprised two sets of tools used for two applications: a curved drill guide (CDG) and a straight-curved drill guide (SCGD). Both tools worked in combination with a select number of flexible joints (FJ) placed above the drill guides.
The CDG, which drilled the build section, comprised three concentric pieces acting as one (Fig. 1). The outermost, 41/2-in. ID tubular piece had a flexible and resilient section (in one plane) serving as the mechanism for transmitting weight. Inside the tubular piece, a flexible nonresilient tube, which looked like a series of hollow universal joints, transmitted torque.
The third and innermost piece was a high-pressure hose that carried drilling fluids. The entire CDG assembly, when relaxed, formed a partial circle with a 30-ft radius.
The tool was mechanically straightened to fit into the 7-in. casing string. The outer section did not rotate and acted as a guide to initiate and drill the first section of the lateral hole.
Eastman wrote, "The FJs formed nonresilient, hollow-tubular sections capable of transmitting both weight and torque. Six dovetail-shaped intermeshing teeth were cut through the wall of the tube around the circumference of each section with a torch. The teeth resembled keystones...."
Inside each FJ was the same type of hose used in the CDG. During drilling, the FJs rotated normally, following the CDG as it drilled a curved bore along a 50-ft radius.
Once horizontal, the continuously curved CDG was tripped out and exchanged for a partially curved SCDG, which incorporated a flexible section across the middle 10 ft of the tool. The SCDG drilled a more or less horizontal hole for 75-100 ft before frictional forces overcame the ability of the assembly to continue.
C. Zublin said his father reentered about 250 vertical wells in California, West Texas, and Wyoming, recompleting each well with an average of two laterals apiece.
However, he said that interest in the technology eventually died. "By the late 1960s, downhole fracturing technologies made horizontal drainhole [and mulitlateral] technologies obsolete, mainly because of cost and limited displacement considerations."
Russian endeavors
Russian engineers began implementing multilateral drilling and completion technologies commercially during the 1950s, expanding upon technological achievements with downhole motors.
As reported at the Fourth Annual Petroleum Conference in 1953, Alexander Mikhailovich Grigoryan completed Well No. 66-45 in Bashkiria, U.S.S.R., consisting of three laterals and six branches. Grigoryan said oil production increased from 44 b/d (offset well) to 755 b/d, proving the economic potential for the technology.
"These laterals were sidetracked from an open borehole without the use of cement bridges or whipstocks." In total, Grigoryan drilled about 30 multilateral wells in Bashkiria, East Siberia, and West Ukraine and near the Black Sea using both turbine and electrodrill technologies. His work ceased in the 1980s when "the U.S.S.R. forbade the drilling of such wells."
Grigoryan said his method "allows each lateral to be kicked off in about 30 min instead of hours or days needed by Western techniques."
His method includes the following steps:
1.Drill main borehole in the interval of intended production.
2.Decide upon and mark entry points.
3.Run special tools on regular drillstring.
4.Align sidetracking tool with orientation instrument.
5.Sidetrack lateral or branch, normally in one run.
Revival
In the late 1970s, U.S. and European companies began their own multialateral endeavors, led by Elf Aquitaine, Texaco Canada, ARCO, and Union Pacific Resource Co. (UPRC).
According to Michael Chambers, associate completions-engineering advisor for Mobil E&P Technical Center, "The Austin chalk of South Texas, with its extensive network of vertically fractured formations, provided an excellent proving ground for the development of multilateral technologies."
UPRC said that from the late 1980s through 1998 it completed more than 1,000 multilaterals in the play.
TAML (Technical Advancement for Multilaterals), a group of about 20 operators, estimated its member companies drilled 2,780 multilateral wells as of August 1998. TAML predicted that by July 1999 a further 723 multilateral wells would be drilled but noted that low oil prices during 1998 might reduce the number.
Multilateral system selection
Multilateral completions consist of two or more directional or horizontal well bores, drilled from a single parent well bore, enabling drainage from, or injection into, multiple reservoir targets. Under certain conditions, multilateral wells have saved time and money compared with drilling many individual well bores.
Chambers said the decision to drill multilateral wells should be based on an examination of operational and economic risks, expected well-system performance, and well-bore management procedures.
"Every reservoir has its own specific driver as to whether multilaterals should be used," he said. "Many reservoirs that are shallow, very thick, unconsolidated, and quick to drill do not make multilateral candidates."
Chambers said multilateral technologies should be used to optimize drainage patterns through customized well configurations.
Advances in drilling and completion techniques allowed reservoir drainage through three main production configurations:
1.Commingled production.
2.Individual production strings tied back to the surface.
3.Commingled production with individual branches that can be shut off and reentered.
Cost comparisons
Chambers said the incremental costs for adding lateral legs fall as drilling depth increases (Table 1).
Thus, for a typical 13,000 ft true vertical depth (TVD) well in Canada, a dual lateral might cost 1.9 times as much as a vertical well. However, the cost for a 3,000 ft TVD dual lateral would be 2.2 times that of a vertical well.
Selection of a multilateral system involves four major considerations:
1.The type of lithology in the junction area.
2.The type of pressure seal required in the junction.
3.Re-entry capability.
4.Flow type-commingled or separated.
The level of complexity needed for each multilateral application, as dictated by these four considerations, introduces problems associated with technology transfer, communications, service and equipment selection, and benchmarking.
Classification system
The growing complexity of procedures, equipment, and well configurations led TAML to introduce a common classification system that became an industry standard for multilateral communications.
The system has two tiers: complexity ranking and functional classification.
The complexity ranking consists of six numbered levels (Fig. 2). It provides a first-pass indication of the well`s complexity, based on junction complexity.
The functional classification includes letters and numbers. It has two sections-well description and junction description.
For example, a Level 5, E-2-IN-D well has been completed with pressure integrity at the junction (Level 5), is an existing well (E), contains 2 junctions (2), is an injector (IN), and contains a dual-bore completion (D).
Level classifications
Levels dominate the TAML language of multilateral technologies. A Level 1 system includes uncased main and lateral well bores (Fig. 3). A Level 2 system comprises a cased main well bore but an uncased lateral. A Level 3 system embeds mechanical integrity at the junction.
A Level 4 system includes cased and cemented main and lateral well bores. A Level 5 system isolates the main and lateral well bores with packers and tubing, providing pressure integrity. A Level 6 system provides full pressure integrity achieved with the main and lateral casing strings.
At the close of 1998, there were at least eight multilateral configurations involving the six levels of complexity:
1.Open-hole sidetracked laterals (Level 1).
2.Open-hole completions from a cased main bore (Level 2).
3.Lined lateral from a cased main bore (Level 3).
4.Lined lateral from a cased main bore (Level 4); the lateral liner is connected to the main bore casing string.
5.Lined lateral from cased main bore (Level 4); the lateral liner is supported and isolated at the junction with cement and connected to the main bore casing string.
6.Cased main bore and lateral with completion tubulars creating a mechanical connection and seal between the lateral liner and main bore casing (Level 5).
7.Cased main bore and lateral with direct connection and mechanical seal between the casing and liner at the junction (Level 6).
8.Cased main bore and lateral utilizing prefabricated junction splitter run into enlarged well bore (Level 6S).
According to TAML, by August 1998, about 1,500 Level 1s, 1,000 Level 2s, 100 Level 3s, 80 Level 4s, 10 Level 5s; 1 Level 6, and 60 Level 6Ss had been completed.
Austin chalk
UPRC by 1998 had drilled the majority of horizontal and multilateral wells in the Austin chalk.
Although the company normally completed the laterals barefoot as Level 1 and 2 junctions, it used a wide variety of multilateral well configurations, including dual and triple-stacked laterals; dual and triple-opposed laterals; and forked wells that included complicated turn-and-build sections.
UPRC did not incorporate complex junction levels exceeding Level 2 because the strong lithologic nature of the Austin chalk creates a solid substrate for junction installation, negating the need for mechanical and hydraulic isolation.
According to Nick Spence, production engineer for UPRC, "Compared to a vertical well, you can triple a well`s production by drilling a horizontal well. Then again, you can double production by drilling opposed, dual laterals." Spence said typical triple-opposed multilateral wells (six legs) produce about 1,000 bo/d.
Additional benefits include cost reductions. Duane Phillippi, drilling coordinator for UPRC, said the cost to drill and complete a dual lateral well is less than the cost to redrill two wells. These cost reductions increase with the addition of laterals.
Phillippi also cited an environmental bonus. Multilateral wells reduce the need for surface locations and are an attractive alternative to infill drilling operations because existing surface locations can be utilized.
A triple-opposed, multilateral well containing six lateral legs requires a complicated series of procedures to reach target objectives within the Buda, Chalk A, and Chalk B zones.
Triple-opposed procedures
In Milam County, Tex., UPRC targeted those three pay zones, using four laterals and two branches. Depths below sea level are Chalk B, 5,560 ft; Chalk A, 5,600 ft;, and Buda, 6,020 ft.
Typically, the up- and downdip Buda laterals were drilled first as Level 1 completions out and underneath surface casing. The downdip Chalk B lateral and Chalk A branch are drilled first, in order, as Level 2 and Level 1 completions. Finally, the updip Chalk B lateral and Chalk A branch are drilled, also as Level 2 and Level 1 completions.
The procedure began with setting of 103/4-in. surface casing at 1,000 ft followed by drilling of a 97/8-in. hole section to 5,000 ft. Next, a steerable assembly in slide mode built angle to an inclination of 57°. The assembly then rotated through the tangential section, occasionally sliding to maintain angle, until the intermediate casing point was reached at 6,440 ft (10 TVD ft into the False Buda). A 75/8-in. intermediate casing string was set at this point.
Underneath intermediate casing, the crews drilled the updip leg of the Buda lateral with a 63/4-in. insert bit and build assembly, slide-drilling into the target at an azimuth of 309° and an inclination of 91.6°. Logging-while-drilling (gamma ray) and measurement-while-drilling tools were used to geosteer within the pay zone. Next, a steerable assembly drilled the first lateral, rotary-drilling to 11,400 ft measured depth (MD; 5,830 ft TVD), making necessary course correction by sliding.
The downdip Buda was drilled in the same manner with an inclination of 89.1° and an azimuth of 165°. This lateral was drilled to 11,480 ft MD (6,100 ft TVD). At this point, a GR/CCL (casing collar locator) log was run from the top of the Austin chalk to 600 ft above the top of the chalk.
Next, an isolation packer assembly was run on wireline 50 ft below the base of the chalk. A packer was set, and 6 ft of sand was dump-bailed on top of it. A retrievable whipstock was then run in the hole, and the hole was logged.
The whipstock was positioned so that a second whipstock could be set above the chalk. A steering tool was then run in the hole, and the whipstock was oriented to the high side in preparation for the third lateral. The whipstock was then set, the steering tool tripped out, and milling procedures commenced into the Chalk B (downdip). Milling exited the intermediate cased portion of the well.
This lateral was also drilled with 63/4-in. insert bit and build assembly, but turned to an azimuth of 165° at an inclination of 89.1°. It eventually reached a TD of 10,603 ft MD (5,641 ft TVD).
The fourth leg was not initiated as a lateral from the main bore but instead was sidetracked from the open-hole section of the third lateral. Thus, UPRC incorporated branched legs into its triple-opposed, triple-stacked well configurations. In this situation, the driller pulled out of the hole to 5,770 ft MD then turned to an azimuth of 158° and an inclination of 89.1°.
Similar procedures followed for the fifth and sixth legs of the updip Chalk B lateral and the updip Chalk A branch, each oriented in a direction to enhance production from all pay zones. Production was typically commingled, flowing freely to the surface.
Level 5 procedure
In September 1998, the Brazilian state oil company, Petroleo Basileiro SA (Petrobras), completed the Voader No. 8-VD 6HPA-RJS well in the Campos basin as a Level 5, dual-horizontal injection well.
According to Cliff Hogg, senior applications engineer for Baker Oil Tools, Petrobras completed the well in 60 days with minimal difficulties. The well set a Level 5 water depth record (565 m) and a Level 5 multilateral junction depth record (1,650 m MD, near vertical), verifying the industry`s ability to implement advanced multilateral technologies in deep water and providing a case study for installing a Level 5 system.
Petrobras completed the lower lateral by setting 95/8-in. casing at 8,993 ft MD. Underneath this string, an 81/2-in. open-hole section was drilled out to 10,493 ft MD with a screen set in the open hole. An SC1 (sand control) packer isolated the screens from the main bore with a backup SC1 packer installed behind the first to ensure seal integrity should one packer fail.
Petrobras completed the upper lateral by setting 7-in. casing at 8,980 ft MD. Underneath this string, a 6 1/8-in. open hole was drilled out to 11,888 ft MD. A 31/2-in excluder screen was run in the open-hole section. Petrobras once again utilized dual SC1 packers in the 7-in. lateral liner section to create a seal with the 31/2-in excluder screens.
A two-trip scoophead diverter and selective re-entry tool system created hydraulic isolation, allowing for commingled fluid flow down to the junction point, diverting into each lateral through a Y-block configuration.
Petrobras and Baker Oil Tool completed the Level 5 junction with the following procedures:
Drill and complete 95/8-in. main bore.
1.Run multilateral (ML) packer with orientation profile.
2.Determine ML packer orientation.
3.Run ML retrievable whipstock assembly.
4.Begin to mill window with first-stage starter mill (Fig. 4).
5.Run second-stage window-milling assembly.
6.Mill window.
7.Drill lateral with geosteering tools.
Create cemented root.
1.Run lateral liner.
2.Inflate external casing packer.
3.Cement lateral liner extending back into the main bore.
4.Retrieve liner running tool.
5.Run lateral production equipment.
6.Run washover assembly in mainbore. Washover liner stub (Fig. 5). Pull stub with spear.
7.Trip back in with the washover assembly. Washover then pull whipstock, drilling anchor, shear disconnect, and debris subs.
(Typically, steps 6 and 7 can be completed in one step.)
8.Make cleanout run.
Run SRT and tie in.
1.Run and set two-trip scoophead diverter and production anchor into orientation packer (first trip). Orientation packer ensures proper orientation of scoophead diverter toward the casing exit.
2.Make lateral clean-out trip.
3.Run selective re-entry tool (SRT) (second trip). The SRT forms a Y-block assembly connected to three tubing strings (Fig. 6). The first, primary well bore tubing string connects the assembly to the surface. Below the Y, a short tubing string ties in with the main bore (95/8-in. casing section), while a longer tubing string ties in with the lateral.
4.Tie in lateral. Seal long tubing string within lateral production packer.
5.Continue to slack off bottom-hole assembly and sting shorter tubing string for main-bore tie-in. Main-bore tubing string seals with scoophead diverter.
6.Pressure up and set the single string packer located directly above the SRT.
7.Level 5 system now in place.
Through these procedures, Petrobras created three hydraulic isolation points, necessary for a Level 5 completion. A packer set above the SRT created the first isolation point (Step 6). The seal between the lateral tubing string and the production packer created the second isolation point (Step 4). Finally, a seal of the main-bore tubing string and the scoophead diverter created the third isolation point (Step 5).
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