Drilling and Completion Technology

Multilaterals and intelligent well systems applied to a mature field

They’re not just for deepwater subsea wells.

Brent Emerson and Richard White, Baker Oil Tools

Over the past decade there have been highly publicized successes of both Multilaterals (ML) and Intelligent Well Systems (IWS). Most applications show the technology’s value in offshore, deepwater or subsea environments. However, a large percentage of the world’s oil comes from mature fields. So, the question becomes: How does this technology benefit heavy oil provinces, mature fields or land wells? Petroleum Development Oman (PDO) successfully applied ML and IWS. The following case history combines these two technologies.

FIELD DESCRIPTION

Mukhaizna field, discovered in 1975, is the third largest oil field in south Oman. It contains heavy, viscous oil of 14–16° API. The Upper Gharif 2 (UG2) and the deeper Middle Gharif (MG) are the two oil-bearing reservoirs and are formed from unconsolidated, laterally continuous, Permian age sands. They share a common oil water contact and the Khuff formation’s red clay and tight carbonates act as a cap rock. The reservoir zones contain 2.35 billion bbl (374 MMm³) of OOIP and are separated by the laterally extensive Middle Gharif shale (MGS).

The basic well design includes 13-3/8-in. surface casing to isolate an upper loss zone and to allow the 9-5/8-in. production casing to be cemented to surface. Wire-wrapped screens or slotted liners provide downhole sand control in the 800-m openhole section. The wells are lifted with electric submersible progressive cavity pumps (ES-PCP) that are installed at reservoir depth and are tolerant of sand production. Production comes primarily from the UG2 reservoir at the crestal part of the field, but production is steadily increasing from the MG completions. MG development was delayed due to its relatively small size and because of concerns over early water breakthrough from an underlying aquifer, (Fig. 1).

Fig. 1. Petroleum Development Oman’s Mukhaizna 64 onshore well in south Oman combines multilateral and intelligent well completion technologies to produce heavy oil.

CHOOSING TECHNOLOGY

Five similar multilaterals were completed in a nearby field. Taking into consideration that many variables exist, including pump parameters, clean-up system used, formation variables and completion type (when comparing dual lateral performance to that of singles), the statistics of the five wells gave a strong indication of a general performance increase attributable to two legs. The dual lateral also relies on the use of Hook Hanger technology to achieve this increase.

The choice of ML was based on several drivers. The team expected ML technology to accelerate production, increase the recovery efficiency, optimize the drilling cost and reduce opex cost. The team also expected ML to sustain well inflow by preventing sand entry into the mother bore. Sand entry could plug-off production from one leg.

Due to logistical restraints, getting to the well for remedial action can take a substantial amount of time, so by using ML oil deferment would be reduced. The use of ML would also ensure well integrity, since TAML Level 3 technology stabilizes the hole and reduces sand influx hazards.

DESIGN OBJECTIVE

PDO had thermal development plans for the field and needed an understanding of the reservoir’s pressure behavior. Reservoir monitoring and management technology is lagging in low-cost, multilateral technology, compared to drilling technology. To address this problem, the company initiated and promoted the development of a low-cost, semi-selective completion that allows for flowrate testing of individual legs by differential and closed-in reservoir pressure monitoring separately for each leg or reservoir.

They set well objectives that would develop the reserves, increase field production and simultaneously provide sand control in the producing intervals, while appraising the field’s structure and reservoir development. There was also a need to isolate a water aquifer, which caused drilling losses, from the hydrocarbon bearing formations and a need to appraise the field’s water break-through potential.

To construct the well, a tangent section was needed to install an ES-PCP for artificial lift. While drilling, the well trajectory needed to avoid bellying, since this reduces pump efficiency and the oil production rate.

PDO also needed to confirm the suitability of the Level 3 multilateral junction systems in the field. By maintaining access to both the main bore and the lateral leg, a Level 3 completion makes mechanical shut-off possible in case of water or sand production.

Since the company hoped to commingle production, they needed to test the feasibility of a selective completion with a hydraulically-actuated sliding sleeve. This completion would permit cost-effective production allocation and zonal shut-off.

Another major objective was to prove economic and operational feasibility in drilling and completing multilateral wells. Future applications of this technology could increase efficiency in depleting field reserves.

CONSTRUCTION SEQUENCE

A dedicated rig drilled the 17-1/2-in. top hole and installed the 13-3/8-in. surface casing. The casing, which isolates an aquifer, was set and cemented before drilling into the formation.

Intermediate casing. To accommodate the ES-PCP lift system, 7-in. liner completion and the dual lateral junction system, a 12-1/4-in. hole was drilled next with 9-5/8-in. production casing cemented in place to isolate the reservoirs. A 262-ft (80-m) tangent section was needed for the downhole ES-PCP pump. The casing shoe was set.

Horizontal Leg 1. The mainbore horizontal leg was drilled with 8-1/2-in. bits and completed with 7-in. slotted liner, which was hung off in the 9-5/8-in. casing. The slotted liner provides maximum inflow and a future contingency for remedial sand control using 4-1/2-in. or 3-1/2-in. wire-wrapped screens or slotted liner. The well was then acid stimulated.

A weight-actuated, liner top packer ensured isolation of the mainbore reservoir section from the annulus. This allowed for isolation of the mainbore when drilling the lateral and subsequent sand entry during production.

Production packer. The 9-5/8-in. casing was scraped and a production packer was set. The 7-in. casing was run between a tie-back locator and the packer assembly for correct space out. The top of the packer assembly was used as the datum for setting the whipstock casing exit assembly.

Integral to the packer assembly was a dual-acting, Knock Out Isolation Valve (KOIV). This valve holds pressure from above or below and prevents debris from entering the mainbore liner during milling and drilling operations. Integral to the packer assembly was a 5-1/4-in. seal bore extension, which would be used at a later date to land a seal assembly in the IWS completion.

Casing exit. The whipstock assembly allows for milling the window and the required rat-hole to drill the lateral. The system needs only one trip to mill the window and one trip to retrieve the whipstock. An MWD is incorporated in the BHA to orient the whipstock face, which allows the driller to orient the whipstock and mill-out the casing at a pre-determined angle.

This approach was critical for subsequent re-entry into the mainbore without using dedicated diverter assemblies. By relying on gravity alone, the horizontal conditions allow the assembly to “fall” down into the lower leg. This significantly reduces the number of trips needed to build the junction.

The weight actuated Bottom Trip Anchor (BTA) was set and the bolt connecting the mill to the whipstock face was sheared, so the exit portal was created. The BTA provides the anchoring mechanism to prevent radial or axial movement during subsequent milling and drilling.

Horizontal Leg 2. Directional drilling was a challenge. An optimal well path was essential so that dog-legs, especially in Leg 2, were minimized. Low doglegs in the well profile optimize lateral equipment installation.

The 8-1/2-in, openhole section was drilled using a density-neutron-resistivity-inclination-at-bit system to avoid “bellying” the well. The driller’s intent was to use the system to insure that the well continually slopes downhill to avoid “gas locking” the ES-PCP. Tubing conveyed logging allowed for a caliper log 50-m outside the casing exit for optimum External Casing Packer (ECP) placement, i.e. not in any unacceptable washouts.

Whipstock removal. The whipstock assembly was retrieved using a lug tool, which mates with a profile slot in the whipstock. By running an MWD above the tool, the correct whipstock orientation was confirmed to the initial setting of the whipstock train. Overpull unlatched the BTA and the whipstock assembly with debris management system was retrieved.

Junction construction (Leg 2). Once the whipstock assembly was retrieved, the liner assembly with bent sub, slotted liner, and Hook Hanger was run into the well with the “hook” engaging the casing at the bottom of the casing exit window. Since the whipstock was removed, the bent joint allowed the liner to “kick” out into the lateral. This has proven successful and does not require additional runs for installing and retrieving diverters.

Once the hanger landed, the liner running tool was released and the well was acid stimulated. In one trip, the ECP was inflated, the lateral diverter was released and the lower zone was opened for production by breaking the KOIV in the production packer assembly. Re-entry into the mainbore was achieved with gravity alone due to the prior placement of the whipstock assembly.

IWS completion. Prior to running the final intelligent completion, a dummy seal and shroud assembly was run to confirm 5-1/4-in. access to the mainbore. A short section of dual, encapsulated control line was also placed across the shroud. This was perceived to be a weak point in the system and a visual check would confirm if any excessive and unacceptable wear occurred.

The assembly was deployed on the 4-1/2-in., 12.75-lb/ft completion string, not drill pipe, to fully simulate the final completion. Access to the lower leg was confirmed with the 5-1/4-in. tie-back seal landing in the seal bore extension of the production packer assembly.

Subsequently, the IWS was run together with the ES-PCP assembly. The shrouded 5-5/8-in. ES-PCP allows for artificial lift and the 3-1/2-in., hydraulically-operated, sliding sleeve provides selective isolation of the mainbore (Leg 1). Additionally, the shroud prevents direct vibration to the hydraulic sliding sleeve itself.

RESULTS

Technical difficulties at Mukhaizna field posed by the heavy oil, unconsolidated reservoir sand and potential early water breakthrough resulted in high development cost. This precluded early field development. The project became an attractive investment by dedicated field appraisal, drilling horizontal and dual-lateral wells and the application of new technology.

The Mukhaizna 64 well was brought online initially at 471 bopd (75 m³/day), which was better than expected.

The option to shut off production from the lower leg in the event of water breakthrough is achieved by closing the hydraulically operated sliding sleeve remotely from surface. Once water coning has dissipated, mainbore production can begin by opening the sleeve from the surface. This reduces cost, since it eliminates production shutdown from the lateral leg and rig down-time associated with manipulation. It also reduces risk from intervention. Furthermore, during transient testing, wellbore storage effects are nearly eliminated without the need for intervention.

In view of the high hook-up costs, and for responsible reservoir management, there is a clear requirement to drill multilateral wells and to complete them with a selective completion. As the field matures and the development costs increase, reducing well cost becomes even more important. Re-entering existing single wells and converting them to multilateral completions is an attractive option where drilling dedicated single horizontals is too expensive.

Based on operational progress and the confidence of achieving the objective with minimum risk, the application of multilaterals using new technology was considered a huge success. Based on production performance, dual laterals are more favorable than single lateral producers because of the higher marginal benefit at marginal cost. Dual laterals are preferable to single wells in no-fracture areas and where subsurface, horizontal-lateral spacing allows. 

REFERENCES

1. Rump, P., Bairagi, R., Fraser, J. and K. Muellar, “Multilateral/ intelligent wells improve development of heavy oil field – A Case History,” IADC/ SPE 87207 presented at IADC/ SPE Drilling Conference, Dallas, Texas, March 2–4, 2004.
2. Al-Azkawi, A., Taylor, G., Chadwick, R. and B. McGowen, “Multilateral wells improve development of heavy crude production in the Mukhaizna field, Sultanate of Oman,” SPE 79021 presented at SPE International Thermal Operations and Heavy Oil Symposium and International Horizontal Well Technology Conference, Calgary, Canada, November 4–7, 2002.
3. Rump, P., Hogg, C. and R. White, “Low risk, high flexibility multilateral/ intelligent well combinations – A case history,” presented at High Tech Wells Russia Forum, Moscow, Russia, June 24–26, 2003.

THE AUTHORS
	Brent Emerson is director of marketing, Wellbore Construction and Open Hole Completions at Baker Oil Tools. Emerson is responsible for developing and commercializing Multilateral, Liner, Expandable and Wellbore Isolation Systems. He has worked extensively throughout North America and the Asia-Pacific rim. Emerson earned a Mechanical Engineering Degree from the University of Texas at Austin in 1988 and is a member of the Society of Petroleum Engineers, Technical Advancement of Multilaterals, and Expandable Technology Forum.
	Richard White is a senior application advisor, Well Bore Construction group, working with multilateral and expandable technology at Baker Oil Tools. During his 25 years with Baker, Richard has held various positions in operations, sales, operations management and marketing. His expertise includes remedial/ stimulation and inflatable systems, completion systems, subsurface safety valve systems, liner hanger systems and multilateral and expandable product systems.