Multilateral Drilling In Middle east PDF

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Multiple questions and intelligent answers Many Middle East operators see multilateral drilling as a logical ‘next step’ from horizontal drilling, which has become commonplace in the Middle East. Multilaterals are particularly effective in complex carbonate reservoirs, but they have not been widely adopted as a result of general skepticism over risks, and more practical deterrents, such as the engineering of reliable, safe junctions in production strings. All that is changing. One ingenious solution is a prefabricated, subsurface wellhead assembly that can be ‘unwrapped’ and installed downhole, splitting the main bore into two smaller, equalsized, lateral bores and providing a high-pressure seal at the junction.

Asset teams are now turning their attention to the application of multilaterals in more hostile environments, where economic returns are greatest, and to the potential for 'intelligent' systems for remote monitoring and adjustment of reservoir conditions to achieve optimum completions. In this article, Bernard Montaron, Tim O’Rourke, and John Algeroy introduce these rapidly advancing technologies.

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or many years, field engineers and operating companies in the Middle East have battled with the challenges of obtaining maximum exploitation of reservoirs as safely and economically as possible. During the 1980s, improvements in horizontal technology were adopted quickly in the region to bring about significant improvements in productivity. The logical next step, keeping abreast of drilling technology, was to drill multilateral wells that allowed all the benefits of horizontal wells to be carried forward to multilayered or ‘stacked’ reservoirs as branches from a single main borehole. Seen by some as risky and not sufficiently proven, multilateral drilling made its somewhat shaky debut in the Middle East in the mid-1990s. Much work has been done since, particularly to improve the construction and integrity of multilateral junctions, and today’s confidence is evidenced by the hundreds of multilateral wells now in existence.

All-Union Scientific Research Institute for drilling technology (VNIIBT). He went on to develop a new, boreholesidetrack, kickoff technique, and a device for stabilizing and controlling curvature without deflectors. However, his main contribution to drilling technology was still to come. This involved expanding on the theory, previously proposed by American scientist L. Yuren, that production could be improved by increasing the diameter of the borehole. He stated that branching the borehole in the productive zone “just as a tree’s roots extend its exposure to the soil” would increase production. The theory was put to the test in the Bashkiria field complex (in what is today Bashkortostan, Russia) where Grigoryan drilled Well 66/45, the first multilateral well, using turbodrills without rotating drillstrings.

In the Bashkiria complex, late Carboniferous reefs had trapped vast oil reserves. However, most of the wells had been producing since before 1930 and were producing low volumes when Grigoryan drilled the first multilateral. In 1953, Grigoryan selected Bashkiria’s Ishimbainefti field to drill Well 66/45 (Figure 3.1). This field contained an interval of Artinskian carbonate rocks with good reservoir properties over a wide area. The target was the Akavassy horizon, which was an interval with thicknesses varying from 10 to 60 m (33 to 197 ft). Nine branches were drilled from the borehole below 375 m (1230 ft). This was done without whipstocks or cement bridges, drilling by touch, with each branch extending from 80 to 300 m in different directions into the producing zone. The drill bit was allowed to follow the pay zone into the most productive areas and curved

Figure 3.1: Well 66/45, drilled at Bashkiria, now Bashkortostan, Russia, was the first multilateral well. It had nine lateral branches that tapped the Ishimbainefti field reservoir

Well 66/45

No revolutions in Russia

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25 50 75 100 125 150 175 200 Measured depth, m

Multilateral drilling has its origins in Russia during the 1940s. At that time oil was a strategic commodity in the Soviet Union and served as a ‘currency’ that could be exchanged for grain or other consumer goods. High quotas were imposed on drillers to bore as many holes as possible, in the belief that the more holes drilled, the greater the chance of tapping a reservoir and the greater the likelihood of an increase in production. This supposition was contested by a Soviet innovator and inventor, turned drilling engineer, Alexander Mikhailovich Grigoryan, who believed that more oil could be produced by following a known oil sand rather than simply penetrating it with a number of boreholes. In 1941 Grigoryan drilled one of the world’s first directional wells – Baku 1385 – nearly 20 years earlier than anyone else. Without a whipstock or rotating drillstring, he used a downhole hydraulic motor to penetrate oil-bearing rock, significantly expanding reservoir exposure and production. This was the first time that a turbodrill had been used for both vertical and deviated sections of a borehole. Grigoryan’s pioneering work led to scores of other successful horizontal wells across the USSR and he was promoted to department head at the

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automatically to follow the planned trajectory. Speed and penetration rate depended on the hardness of the rock and the power of the downhole motor. The nine producing laterals of Well 66/45 had a maximum horizontal reach of 136 m from the kickoff point and a total drainage of 322 m (1056 ft). It cost about 1.5 times as much to drill as the other wells in the field, but penetrated 5.5 times the pay thickness and, at 755 B/D, was 17 times more productive. Over the following 27 years, a further 110 multilateral wells were drilled in Russia – 30 of them by Grigoryan himself. About 50 of these early multilaterals were exploratory and the remainder were for delineation of reefs and channel structures.

Many benefits Until 1980, when ARCO drilled the K-142 dual-lateral well in New Mexico’s Empire field, there had been no attempts at multilateral drilling outside the USSR. This type of drilling was considered too risky and difficult as well as requiring substantial investment of time and money. For years, because there were few reliable examples of successful multilateral applications, operators lacked benchmarks for identifying suitable candidates for multilateral development. Higher initial costs, the risk of interference between laterals, crossflow, and difficulties with production allocations all hindered the

introduction of multilateral technology. An increased sensitivity to and concern about reservoir heterogeneities such as vertical permeability also deterred multilateral development. Complicated drilling, completion and production technologies, complex and expensive stimulation, slow and less-effective cleanup, and cumbersome wellbore management during production were all seen by operators as further obstacles. Between 1980 and 1995, only 45 multilateral completions were reported, but since 1995 hundreds more multilateral wells have been completed and many more are planned, thanks to improved techniques and increased confidence. Even today there are still acknowledged risks in multilateral wells such as borehole instability, stuck pipe, cementing and branching; but in the 1990s, as more multilaterals were drilled successfully, even the simplest wells confirmed the potential of this emerging technology. The main benefits of these successful wells were increased production, increased reserves, and overall reductions in reservoir development costs. Traditionally, increasing the productivity of known reserves has been achieved by drilling additional wells to increase drainage and sweep efficiency. Multilateral technology provides the required increased contact between the borehole and the reservoir without drilling additional wells. By drilling the

main trunk and overburden to the reservoir only once, surface can continue to be a single installation with obvious cost savings over the multiwell situation. Similar benefits can be seen in offshore and subsea scenarios where a limited number of slots are available, and in onshore locations where surface installations are particularly expensive. Multilateral penetrations are commonly used to increase the effective drainage and depletion of a reservoir, particularly where low permeability restricts hydrocarbon mobility or low porosity limits production flow. When independent reservoirs are targeted, production can either be commingled into a single production tubing string or produced separately in multiple strings (Figure 3.2). Multilateral wells are also economic for rapidly depleting a reservoir; effectively accelerating production, shortening the field life cycle, and reducing operating costs. Multilateral wells are more efficient than conventional or horizontal wells in thinly layered formations or significantly fractured systems, or for specific enhanced oil-recovery situations such as steam-assisted gravity drainage. The application of multilateral technology can also reduce water and gas coning. Improving the vertical and horizontal drainage of reservoirs increases recoverable reserves significantly, while both capital and operating costs per well and per field are minimized. In fact, the cost of achieving the same degree of

Shallow or depleted reservoirs

Layered reservoirs

Fractured reservoirs

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Figure 3.2: In shallow or depleted reservoirs, branched horizontal wellbores are often most efficient, whereas in layered reservoirs, vertically stacked drainholes are usually best. In fractured reservoirs, dual-opposing laterals may provide maximum reservoir exposure, particularly when fracture orientation is known M i d d l e E a s t R e s e r v oi r R e v i e w

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drainage with conventional wells would be prohibitive in most cases, especially in situations such as deepwater, subsea developments. The costs of multilateral wells can be recovered over several reservoir penetrations and, in some cases, the need for infill drilling has been eliminated completely. Multibranched wells can tell operators a great deal about their reservoirs. This is particularly advantageous in anisotropic formations, where the directions of preferred permeability are unknown. In these cases, lateral branches can help compensate for nonuniform productivity, with corresponding economic benefits and enhance formation evaluation.

Accessibility NR – no selective reentry 1

PR – reentry by pulling completion 2

TR – through-tubing reentry

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Classification on the level In 1987 in Aberdeen, Technology Advancement-Multilaterals (TAML) – a forum of experts in multilateral technology from leading oil companies – set out to define a system of classifying multilateral wells in terms of complexity and functionality, which would also relate to difficulty and risk. The complexity of multilateral wells is now described on a scale from Level 1 (the simplest) through 6S (the most complex) (Figure 3.3), with an additional code representing type and functionality. The most difficult part of drilling a multilateral well is producing a stable junction between the main trunk and the wellbore branches. For this reason about 95% of the world’s multilateral wells have been at level 1 or 2. But in 1998, about 50% of the multilateral wells drilled were level 3 or 4. Rapid advances in multilateral connectivity, accessibility and isolation capabilities, together with new junction systems, are allowing operators to select more-complex solutions. Level 1: Openhole sidetracking technique. The trunk and laterals are all drilled in openhole, usually in hard rock with unsupported junctions. Lateral access and production control is limited. This is similar to the pioneering multilaterals that were drilled in Russia.

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Level 1: The main bore is cased and cemented but laterals are in openhole, although sometimes they have a ‘drop-off’ liner that is not cemented or mechanically connected to the main casing. RapidAccess* multilateral completion systems that provide selective M i d d l e E a s t R e s e r v oi r R e v i e w

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Figure 3.3: Multilateral configurations and classification by level

drainhole access addressed some of the shortcomings associated with current multilateral practices, such as: • uncertain accessibility to the laterals for workover • casing obstruction and/or reduction of effective inside diameter • reduced casing stress, running casing and placement of the window • inflexible drilling sequence. RapidAccess is designed to be installed for either immediate use or for future use in reentry operations. Sidetracks can be performed and then the whipstock can be retrieved leaving unobstructed, fullbore casing. This allows operators to readily access the sidetracked wellbores remaining. Multiple RapidAccess couplings can be installed in casing strings to allow many reservoir penetrations for optimum field development. In these cases, depth and orientation can be determined by a monitoring-while-drilling survey after cementing, or by coiled-tubing or wireline conveyed USI* UltraSonic Imager surveys (Figure 3.4).

Window from USI log

Window to ICC spacing

Index casing coupling from USI log

The complete system

Figure 3.4: USI log showing an indexed casing coupling (ICC) and a window milled in 7-in., 26-lbm/ft casing using a downhole motor. This log was run to verify the length of a full-gauge window. A USI log can be run in most common drilling fluids

avoid the increased risk of milling in situ. The Level 2 RapidAccess process is shown in Figure 3.5. Level 3: Both connectivity and access are present in Level 3 multilaterals. The main trunk and laterals are cased, although only the main bore is cemented. There is no hydraulic integrity or pressure seal at the lateralliner-to-main-casing junction but there is main bore and lateral reentry access. The Level 3 RapidConnect* multilateral completion system (selective drainhole access and connectivity) provides high-strength junctions – where lateral liners are anchored to the main bore by liner

hangers or other latching systems – and is important in wells where sand or shale may affect well stability. In Level 3 systems, upper laterals can be isolated at the junction to allow production from lower laterals. Selective access to laterals is achieved by the oriented diverter positioning. A complete Level 3 RapidConnect system has several main components (see Figure 3.6): • selective landing sub (SLS) • template • connector.

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The complete RapidAccess System has several main components: • The indexed casing coupling (ICC), a casing nipple with selective key profiles to accommodate sidetracking and completion tools. It uses a muleshoe orienting profile to receive a key that rotates the whipstock or reentry deflection tool (RDT) assembly to the desired orientation relative to the muleshoe’s orienting keyway • The selective landing tool (SLT) is a locating and anchoring device. It has selective keys that allow it to be positioned in the profile of the desired ICC along with its attached tool such as a whipstock, RDT and orientation confirmation assemblies • The RDT assembly is recoverable by overshot. It resembles a small whipstock and acts as a guide for rotary drilling, running liner, completion equipment running and workover operations. Drillers can also carry out window milling in existing wells using conventional retrievable whipstock or cement plug techniques. Premilled casing subs are sometimes employed to

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The most common completion performed in Level 2 and 3 wells is uncemented, predrilled or slotted liners and prepacked (but not gravel-packed) screens. Anadrill uses a drop-off liner completion design in which the top of the liner in the lateral is immediately released outside the casing exit through a hydraulic sub. External casing packers are often used in the drop-off liner completion assembly to isolate zones,

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anchor the liner top and facilitate reentry access to the liner. Another mid-tier approach to multilateral completion offers only individual hydraulic isolation of a lateral. In this case, laterals are drilled using whipstock sidetracking procedures, and any completion performed in the lateral uses a drop-off liner. Conventional casing packers in the main casing with tubing between them – straddle packers

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– are used to isolate each of the laterals hydraulically. Production from the laterals is controlled with sliding sleeves and other flow-control devices. This is an inexpensive and relatively straightforward multilateral completion method that was proven in the North Sea and is now being adapted for deepwater, subsea wells. The critical technology in these completions is operation of flow-control

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Figure 3.5: Level 2 RapidAccess 1. The main wellbore casing is run with indexed casing couplings (ICC) as integral components. 2. The main wellbore casing is cemented. 3. The lower branch is drilled, completed and isolated with a retrievable bridge plug. 4. The coupling orientation is determined from a USI log or by running a selective landing tool (SLT) with Slim 1* slim and retrievable MWD system in the universal bottomhole orienter (UBHO). The coupling can be cleaned during this trip and a gel pill may be spotted in the kickoff section to suspend debris. 5. The whipstock is aligned with the SLT key and run into the well. The assembly automatically aligns and latches and the milling tool is released from the whipstock. 6. A casing window and short section of pilot hole are cut with the special milling assembly powered by a downhole motor. 7. After a lateral is drilled to depth, the well may be left openhole or as a simple cemented or dropoff liner run. The SLT is released and the entire assembly is retrieved. The hole is cleaned out and the bridge plug removed

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8. The process is changed for a cemented liner by replacing the full-size whipstock with a smaller diameter reentry deflection tool (RDT) that is run and latched into an ICC. 9. The bottomhole assembly (BHA) is run and a lateral branch is drilled. 10. A liner is run into the lateral and may be cemented back into the main casing. 11. The liner running tool is released, the hole cleaned up by reverse circulating and the liner running tool is pulled out of the hole. 12. After the lateral is completed the RDT is retrieved by releasing the SLT. RDT and SLT are pulled from the well. 13. The lower wellbore section is cleaned out, the isolating bridge plug retrieved and the main bore is ready for completion N u mb e r 2 , 2 0 0 1