How multilateral boreholes impact ultimate recovery strategies

Are uncased laterals the future of accelerated recovery?

Future completions might include multilateral completions with build-in branch monitoring, branch chokes, a water-oil separator, and a pump to inject the separated water downhole.

In the future, how many laterals will be drilled out of one vertical borehole? Well - how high can one count? If most laterals can be completed open hole with branches off of branches, then the expected number might be infinite - almost. If tying back each lateral with casing or a liner and a screen or gravel pack to its parent hole is necessary, then the number will be limited.

The future of multilateral technology will based quite simply on the ability to orient and maneuver drilling, completion, and workover strings through any number of junctions and windows downhole, cased or open, to access branch chokes, sliding sleeves, and other regulating devices.

Small internal diameters (ID) in the lateral casing or drilled boreholes defeat liner, choke, and sliding sleeve installations. In fact, the developing trend toward the use of slimhole drilling techniques may be slowed by the need for maximum diameter casing and borehole to accommodate multilateral functions and tieback equipment.

Of course, lateral placement depends entirely on proper modeling and flow simulation of the pay zones and the requisite 3D and log data that serve as inputs.

Incentives

The cost of drilling a dual lateral well is less than that of two vertical wells. In terms of a return, onshore and offshore completion experience is showing that multiple lateral wells are producing 2.0-2.5 times the amount of production obtained from vertical boreholes. Horizontal completions have been able to obtain a production level 1.5-1.7 times that of a vertical completion.

Also, multiple laterals appear to be the key to finally breaking through the ultimate recovery barrier. In recent years, enhanced recovery methods using injected chemicals, gas, and heat have pushed ultimate recoveries up to 45-60% of in-place reserves, but rarely past the 60% mark. Few injection technologies have emerged in recent years, and producers have been forced instead to seek more exposure of the pay zone in primary recovery operations. Horizontal drilling and completion provided one way to enlarge pay zone exposure to the wellbore, and multiple laterals are opening up still more of the reservoir with fewer vertical boreholes.

Pushing the numbers

Much of multilateral drilling technology originated in the coal mining industry to drain water or dangerous gas from formations. Casing and tying back the laterals was not important, so virtually everything was drilled open hole. The petroleum industry began to explore multilateral technology actively in the mid-1980s. Until 1992, however, lateral extensions exceeding 1,000 ft were rare. Casing and tying back the laterals did not develop until several years ago, and it was then that laterals exceeding 1,000 ft became common.

Prior to then, producers and drillers were skeptical of the rationale of pushing out uncased laterals that often collapsed and created production problems. Also, there was the question of safety. Today, cemented casing connections can be integrity-tested before being placed on production. However, safety concerns will continue until the number of completions grows or new equipment emerges to allay fears.

Also, there is the question of financial return on kickoff, drilling, and completion investments. The technology has proved highly successful for development or infill drilling and to date, most multilateral wells have been drilled on high-return probability wells. But in time that envelope of risk/return will be pushed into more questionable situations. As the number of multilateral wells rises, will the cost of the technology decline accordingly?

Now that dayrates on mobile offshore drilling units are much higher than previous years, is it economic to plan for the pre-drilling of development wells where multiple laterals are involved, or should these wells await lateral drilling with a platform rig, which operates at a much lower dayrate?

Life cycle strategies

Multilateral technology is changing pro duction strategies to maximize reservoir drainage. Lateral wells represent the first time in decades that producers, providing the cost of kickoff and lateral drilling can be reduced over time with new technology, have a real opportunity to boost field ultimate recovery without sacrificing near-term production volumes.

An example of the sort of returns to be obtained by lateral drilling and completion technology can be found in the US Gulf of Mexico. At least one-half of the drilling activity taking place now in the US Gulf is re-entry drilling and re-completion of old wells to tap behind the pipe reserves passed over when producers either didn't see them on well logs or couldn't install more than one or two completions in separate zones. Had the technology been available decades ago, much of the oil and gas reserves being tapped now would have been available then, significantly boosting well productivity.

Now that laterals provide an obvious return, producers are trying to fit the costs of multilaterals into life cycle spending and returns. From a cost efficiency standpoint, for example, should laterals be cased, partially cased from the vertical borehole, or left completely open? While the decision is conventionally driven by casing diameter, the number of laterals needed, tie-back arrangements, reservoir geology, production flow characteristics, and the incidence or frequency of re-entry or re-completion, the decision is becoming complicated by the expected rollback in the cost of drilling new laterals.

If ultimate recovery can be boosted by simply completing laterals and discarding them and drilling new laterals in other parts of the pay zone, then the impetus is to leave the initial laterals through the pay zone uncased. Why put money into long-term hole integrity and completion equipment when the laterals could more economically be abandoned when production ebbs and the money spent on new laterals?

Until reservoir engineers have more experience with cost-efficiencies of replacing old producing laterals with new ones and measuring the impact on ultimate recovery, producers will approach lateral boreholes and completions with conservative long-term strategies. Now that producers are beginning to develop data from producing through cased and uncased sections in horizontal wells, a clearer picture may develop for applications on multilateral options.

Injection downhole

In the future, the ability to inject water, gas, or steam downhole while simultaneously producing in another part of the reservoir will enable producers to lower well costs dramatically. Another future application will be to separate oil and water downhole and inject the water into a formation, either one that is separate from the producing reservoir for disposal purposes or one that is connected in order to enhance recovery.

If a 1,600-ft long lateral exposes more of the well, two opposing laterals of such length open up 3,200 ft of reservoir along one axis. With thick sections or vertically-shaped pay zones this is ideal, but in the case of thin reservoirs stretched out over long distances (areal or sectioned), reservoir exposure may accelerate production initially but do nothing for ultimate recovery.

In the case of thin zones, injection and production employed in the same borehole can optimize recovery in oil wells differently. For example, injection capability can be installed at the downdip end (water/oil interface) of one 1,600-ft lateral, and a production completion at the updip end of the other 1,600-ft lateral (below the gas cap). Both injection and production are handled through the same vertical borehole. The injection front can sweep the zone along the entire 3,200-ft lateral distance of the zone, substantially boosting ultimate recovery.

One of the more interesting multilateral trends is to move separation and injection processes into the same borehole, a situation made much easier with multilateral technology. Producers and injectors drilled separately from the surface have been customary because of the wide lateral distances required. Now, these distances can be spanned with opposed multilateral wells.

Also, in terms of boosting ultimate recovery from reservoirs and minimizing surface treatment and facilities, manufacturers are working on a method of separating oil and water downhole. Once this is achieved, and is feasible without moving parts, then operating a pump to inject the water into a separate lateral should also be feasible.

Lateral problems

One major difficulty in planning laterals is whether to complete the entire lateral open hole (barefoot), cased near the main borehole with a choke, or cased (or lined) throughout to protect the completion from collapse or sand intrusion. Is the investment in casing, or lining a lateral, worth it if there is a risk of an early water-out?

The more consolidated the formation, the more likely a lateral will produce for some time without casing. Every producer has a different approach and decision tree for the degree of completion in the lateral. The ease of re-entering the well and drilling a new lateral or being able to use chokes or sleeves to close out watered-out laterals and open up non-producing branches that were drilled earlier will determine just how far the industry goes with casing laterals.

The downhole merging of production from compatible formations minimizes the number of production strings in the main borehole, but it poses another problem for producers. When water production increases, the lack of instrumentation on each lateral makes it difficult to determine the origin of the increased water and installing instrumentation on each lateral is costly.

In the future, the ability to monitor production from each lateral and adjust chokes to raise or lower volumes from each lateral will decrease the amount of surface treatment.

For production in the US Gulf of Mexico, the US Minerals Management Service requires production figures from each zone or interval. For many wells, this implies the installation of production monitoring instrumentation on each lateral. Discussions surrounding this topic of the requirement are ongoing.

The future

Through the present, 80% of multilateral wells have been openhole sidetracks with no lateral liner, no completion equipment left behind, and no isolation of lateral wellbores. Although openhole branches will remain popular, the condition of the surrounding formation and the criticality of the lateral will determine whether more laterals will be equipped with liners.

More definite in the future of multilaterals will be the installation of some type of isolation control near the junction or in the main borehole. Unless lateral line re-entry is needed to access completions, liners in the future could be run with chokes for control purposes.

Future multilateral completions equipment development is likely to focus on five areas:

Tool packages that eliminate numerous drilling and completion string trips for each function.
Using sealed branching devices for lateral kickoff and eliminating cement for simple root junctions.
Packing more production options and control devices in limited ID.
Installing automation packages that regulate chokes on laterals according to pressure, flow, and multiphase differentials.
Downhole oil-water separation and injection package downhole.

References:

DeLuca, M., "Multilateral completions on the verge of mainstream," Offshore Magazine, April, 1997.
Longbottom, J, Dale, D., Bruha, S., Waddell, K., "Development, Testing, and Field Case Histories of Multilateral Well Completion Systems," OTC 8537, May, 1997.
Robison, C., "Overcoming the Challenges Associated with the Life Cycle Management of Multilateral Wells; Assessing Moves Towards the "Intelligent Well," OTC 8536, May, 1997.
Brooks, R., Stratton, J., "Development and Application of a Through-Tubing Multilateral Re-entry System," OTC 8538, May, 1997.
Strack, M., Nem, E., Leismer, D., Buytaert, J., "A New Concept for Multibranch Technology," OTC 8539, May, 1997.