Directional/complex wells

Integrated Approach Overcomes Depleted-Reservoir Challenges

This paper describes challenges faced in a company’s first deepwater asset in Malaysia and the methods used to overcome these issues in the planning stage.


This paper describes challenges faced in a company’s first deepwater asset in Malaysia and the methods used to overcome these issues in the planning stage. Because of the depleted nature of all three reservoirs located above the untapped reservoir, a need exists to drill through these depleted intervals with an extremely narrow margin window (less than 0.5 lbm/gal). An added complexity is the location of the reservoir, directly below a hydrates bulge. To address the challenges of this well, an integrated approach between various disciplines has proved to be a critical success factor.


The field is offshore Sabah. The first phase of the development was completed in 2014, with 16 wells drilled.

The development includes gas reinjection and seawater injection. The hydrocarbons are trapped in a four-way dip closure developed in an anticline structure containing four sand reservoirs separated by sealing shale layers. The Phase 1 development targeted the two main reservoir units (B and C) in the middle of the four reservoir sands. The pressure maintenance for the development of these two main reservoir units is provided by a combination of downdip water injection in the water leg and crestal gas injection in the gas cap. The second phase, comprising two oil producers and two water injectors, aims to maintain the oil-production plateau.

One of the Phase 2 objectives is to target the deepest untapped reservoir (D) in the field with Well 4. However, as mentioned previously, Well 4 must drill through depleted intervals with extremely narrow drilling margins. Two of the four wells (Wells 1 and 2) only will drill into the depleted B reservoir in the final reservoir hole section, while the third well will cross the depleted B reservoir before drilling into the depleted target reservoir, C, in the final hole section.

Phase 2 will offer the opportunity to acquire further data. Because of the stacked arrangement of Reservoirs A, B, C, and D and the wells targeting different reservoirs, a possibility exists to sequence the drilling campaign in a batch mode and to use data acquisition, operational learnings, and prediction validation before committing to drilling the intermediate and reservoir sections of the most difficult well (Well 4).

The projected formation pore pressure and fracture gradient (PPFG) poses significant drilling challenges because of depletion plus the geomechanical requirements. The Reservoir C water injector is predicted to have a limited drilling margin because of the depletion of Reservoir B.

Well Design

Wellbore Strengthening. This technique is used to improve fracture strength through proper selection of loss-circulation-material (LCM) particle-size distributions and concentrations on the basis of laboratory testing that bridges anticipated fracture geometries (i.e., fracture width) in the formations.

Wellbore strengthening was used in Phase 1 to increase casing-shoe strengths and the overlying shale section above the reservoir in an effort to increase the drilling and cementing margins and enable the casing shoes to be pushed to their intended depths. For Phase 2, where the reservoirs are depleted and the overlying shales require higher mud weights for borehole stability, the drilling margins will be much narrower. In the case of Well 4, where no margin is currently foreseen between the mud weight and the depleted-sand fracture gradient, this technique is the only way of improving the fracture strength to a point at which the well can be made drillable.

Managed-Pressure Drilling and

Cementing (MPD/MPC). Phase 2 wells are expected to have approximately 0.5‑lbm/gal margins between the recommended borehole stability mud weight and the fracture strength across the wellbore-strengthened clastic reservoirs. Conventional drilling cannot deliver these wells because of equivalent circulating density (ECD) exceeding the fracture strength of the sands. MPD is expected to enable safe and successful drilling and completion of the wells. Similarly, MPC enables the safe and successful cementing of casing strings with minimal loss, improving the likelihood that cementing objectives will be met.

A surface-MPD backpressure system makes possible reduction of the static mud weight and reliance upon ECD effects during drilling operations to provide sufficient bottomhole pressure to meet shale-stability requirements. The MPD system then can induce surface backpressure during pumps-off events to ensure that the minimum equivalent mud weight for shale stability is maintained. A mud weight of 9.5 lbm/gal was chosen; this is overbalanced against the predicted pore pressure but underbalanced to the shale-stability mud weight.

Casing-Seat Strategy. Casing-seat options were evaluated from various perspectives. Ranked well objectives guided the multidisciplinary discussions and team recommendations. Because of the specificities of this project in terms of reservoir architecture, depletion, and mud-weight requirements, the typical practice of placing the casing shoe in a shale interval before drilling into the reservoir sand has significant implications. Some considerations for selection of casing shoes include shale stability, drilling margin, and differential sticking.

Well-Trajectory Planning. A study was undertaken to assess the advantages of drilling the wells from step-out (SO) locations compared with drilling from the existing drill centers (DCs) for all reservoir targets. Three options were considered.

Option 1—Two Producers (SO) and Two Injectors (SO). The goal is to develop Well 1 (B producer) and Well 4 (D producer) by SO locations from existing DC A, and Well 2 [B water injector (WI)] and Well 3 (C WI) by SO locations from existing DC B.

Option 2—Two Producers (DC) and Two Injectors (SO). The goal is to develop Well 1 (B producer) and Well 4 (D producer) from existing DC A, and Well 2 (B WI) and Well 3 (C WI) by SO locations from existing DC B.

Option 3—Two Producers (DC) and Two Injectors (DC). The goal is to develop Well 1 (B producer) and Well 4 (D producer) from existing DC A, and Well 2 (B WI) and Well 3 (C WI) from ­existing DC B.

To allow WI wells to be drilled from existing DC B, the drilled lengths would be significantly longer and the trajectories more complex (i.e., 3D). The WI wells from SO locations have relatively simpler 2D trajectories. Well 3 would increase to an extreme-reach-drilling (ERD) well length if the surface location was moved to DC B. In view of the significant technical advantage of the more-favorable trajectories for the WIs from the SO locations, the decision was made to drill from SO locations.  


Wellbore Strengthening. Four different wellbore-strengthening formulations were tested using slotted disks and a series of differently sized aloxite disks. On the basis of this testing, a wellbore-strengthening model was created by the ­fluids contractor that suggests that formation strengthening of 0.5 to 1.0 lbm/gal is achievable. However, these models are generic and rely on a range of rock properties within the sands and the shales. Depletion-­drilling studies for projects in the Gulf of Mexico (GOM) have concluded that vendor models require field-specific calibration and are influenced heavily by the LCM program used. A newly introduced company model built over a period of 6 months, based on analysis of extended-leakoff-test data in conjunction with previous loss and nonloss events from GOM projects, verifies the need for field-specific calibration and will be used in the future in the GOM fields.  

In tandem with the basic wellbore-strengthening plan, a contingency remediation-fluid strategy will also be developed in case wellbore-strengthening effectiveness is below expectations.

MPD/MPC. Hydraulics modeling was performed to determine mud-weight requirements to be used with the MPD system. Using the lowest mud weight possible to maximize drilling window and flexibility, mud-weight requirements are achieved using MPD backpressure (or until fracture limit). Two MPD systems were evaluated [i.e., surface backpressure (below tension ring) vs. riser-level manipulation (e.g., riser pumping)], considering system maturity, availability, accuracy, reliability, and redundancy of the contractor’s equipment. The surface backpressure system was selected predominantly because of the short project timeline.

SO Well Trajectories. Stepping out from a DC entails drilling the wells at a distance from the manifold that exceeds the length of the conventional rigid jumper used to connect the well to the manifold and tying back by subsea flowlines to the nearest DC. This allows the tophole locations to be moved closer to the reservoir target, thereby enabling simplified well trajectories and avoiding the need for 3D ERD wells, which, in turn, reduces well complexity and drilling risk arising from ERD. The benefits of stepping out include

  • Lower well cost because of shorter well length and lower drilling risk
  • Significantly reduced risk of nonproductive-time overrun and well-integrity issues, with a simpler well trajectory
  • Reduces risk of falling objects damaging existing subsea infrastructure
  • Yields recovery similar to ERD trajectories
  • Trajectories oriented in the direction of minimum horizontal stress to allow lower mud weight for borehole stability

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 28517, “Deepwater Extended-Reach-Well Planning Through Depleted Reservoirs,” by Beng-Hooi Shi, Jennifer Koh, Dexter Liew, and Guat-Lee Chio, Shell, prepared for the 2018 Offshore Technology Conference Asia, Kuala Lumpur, 20–23 March. The paper has not been peer reviewed. Copyright 2018 Offshore Technology Conference. Reproduced by permission.