OTC-24839-MS

Optimized Platform Placement to Cover All Geological Targets in Baronia Field M. Anas Sofian, Christophe Leuranguer, and Noor Farhana Musiran, PETRONAS Carigali; Afiqah Fathiah Ahmad Saifuddin, Thomas Wong, and Ilen Kardani, Halliburton

Copyright 2014, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference Asia held in Kuala Lumpur, Malaysia, 25–28 March 2014. This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright.

Abstract Platform placement and sizing are critical steps for enabling subsequent operations, such as well construction, logistics, and facilities installation to be performed efficiently and safely. This paper introduces the most economical, yet efficient, solution for an enhanced oil recovery (EOR) project in which 25 wells were to be drilled in the Baronia field, offshore Sarawak, Malaysia. Collaborative teamwork from drilling, reservoir, facility, geology, and production groups was required to develop the best solutions to minimize construction work, simplify well trajectories, and use all available resources to help minimize the overall budget. In addition, this paper evaluates the drillability of each well based on available drilling technologies and rig capabilities in the market.

During the initial design stage, all 25 wells were planned to be drilled from two new wellhead platforms (WHPs) to intercept all geological targets. Major well collision problems were encountered against adjacent wells in the congested Baronia field; however, after several iterations of surface nudging and slots designation, all wells were drillable, with a total footage of 227,527.1 ft drilled.

The first iteration was performed by placing one new single WHP at an optimized location and using spare slots and sidetracking from an existing platform. This optimized design reduced/saved 39,868.61 ft compared to the initial stage and eliminated the requirement for another new platform. The second iteration was performed by shifting the new WHP 300 ft closer to the production platform to enable bridge linking and help reduce construction work on the pipelines. The total footage to be drilled from this location was reduced again by 3,622.63 ft. Finally, the setup was further optimized by equipping the new platform with splitter wells, which reduced the number of conductor pipes required without decreasing the number of wells to be drilled.

Overall, the platform placement and sizing optimizations saved USD millions during the planning stage by eliminating one platform, decreasing drilling footage, minimizing construction work, and helping reduce health, safety, and environmental (HSE) risks.

Introduction The Baronia field is located about 40 km offshore, northwest (NW) of Lutong, Sarawak, Malaysia, in block SK15 of the Baram Delta area (Fig. 1). It was discovered in 1967 (Pratap et al. 2000) by Well BN-1 and production commenced in May 1972 from two isolated appraisal/development wells, BN-4 and BN-5. To date, 72 wells have been drilled in this field. To gain more productivity, horizontal wells were introduced in the Baronia field some 22 years after its first production. During those years, horizontal well drilling technology was just introduced within the operating company and the Baronia field was the first to be implemented (Jadid and Mustapah 2007).

Structurally, the Baronia field is characterized by a simple, internally faulted, relatively flat, low relief domal anticline structure elongated toward the south-southwest (SSW) and the anticline is resulted from a rollover associated with growth faulting combined with Pliocene compressional folding. The main prospective sequences are comprised of interbeded sandstones and shales with minor siltstones of Late Miocene (Jadid and Mustapah 2007).

There are four drilling platforms in the Baronia field; two 12-slot drilling platforms (BNDP-A and BNDP-B), two 15-slot drilling platforms (BNDP-I and BNDP-J), and five 3-slot jackets (BNJT-C, BNJT-D, BNJT-E, BNJT-F1, and BNJT-H1)

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(Fig. 2). The first field development started from the drilling platform BNDP-A in 1974, and continued to 1979 from a second drilling platform, BNDP-B.

Drillability Criteria The following criteria are given to ensure that each well is drillable from a given location and reach the geological targets as shown in Fig 11: • Drilling risks • Anti-collision • Dogleg severity • Hydraulic • Torque and drag • Rig capability • Technology availability • Cost efficiency A number of significant drillability criteria were taken into account in the well design for a cost efficient planning and to alleviate any drilling risks. Study from the offset wells will give useful information regarding the drilling problems which may have happened in the past so that the mitigation plans can be clearly defined. All anti-collision risks and mitigation plan should be lay up in detail and communicate to all parties during the planning and execution phase. Correct geographic system, geodetic datum and map zone need to be established and agreed upon in order to have an accurate coordinate system. All anti-collision policies were followed in the planning stage especially on meeting the criteria of clearance factor of more than 1.5 and the sigma value was set to 2.445 as per the operating company’s requirement. The formula for calculating the clearance factor ratio is:

𝐷𝑖𝑠𝑡𝑎𝑛𝑐𝑒  𝑏𝑒𝑡𝑤𝑒𝑒𝑛  𝐶𝑒𝑛𝑡𝑟𝑒𝑠(𝐷𝑖𝑠𝑡𝑎𝑛𝑐𝑒  𝑏𝑒𝑡𝑤𝑒𝑒𝑛  𝐶𝑒𝑛𝑡𝑟𝑒𝑠 − 𝐷𝑖𝑠𝑡𝑎𝑛𝑐𝑒  𝑏𝑒𝑡𝑤𝑒𝑒𝑛  𝐸𝑙𝑙𝑖𝑝𝑠𝑜𝑖𝑑𝑠 + 𝐶𝑜𝑚𝑏𝑖𝑛𝑒𝑑  𝐶𝑎𝑠𝑖𝑛𝑔  &  𝐻𝑜𝑙𝑒  𝑅𝑎𝑑𝑖𝑖)

Actual survey and planned trajectories need to be updated in the database before commencing any close approach analysis. The anti-collision scans were run against all wells with wellheads within 15km of the reference well or as per company’s policy. In this analysis, numbers of iterations were made to come up with optimum wellbore trajectory including shifting the targets after thorough discussions with the subsurface team to meet anti-collision criteria. All the EOR wells in Baronia field were planned with clearance factor of more than 1.5 and anti-collision procedures were generated and must be adhered to by the directional drillers offshore. Dogleg severity (DLS) is defined as the change in the inclination, and/or azimuth of a borehole, usually expressed in degrees per 100 feet of course length. In the metric system, it is usually expressed in degrees per 30 meters or degrees per 10 meters of course length. There are various factors in determining the dogleg severity but the best practice is to keep it as mild as possible. However, since the Baronia field is very congested, some of the wells have to be kept at certain dogleg severities to avoid collision with proximity wells and this scenario is called anti-collision DLS. Excessive DLS will affect the other measurements such as torque, drag, casing wear, buckling limit, drillstring sideforces, cyclic fatigue, hole cleaning efficiency, casing running, and placement of completion tools. Besides that, the severity of the mechanical loads imposed on drill string elements namely the torque and drag, tensile strength reduction due to bending stress in doglegs need to be considered. The drill string experiences both torque and drag since the drill pipe is in rotational as well as performs linear motion. Drag is the increase in string weight when pulling out of the hole or the reduction in string weight while tripping in the hole while torque is the force required to turn the drill string. More severe doglegs will cause higher torque and drag. Torque and drag simulation was performed to ensure the rig’s drill pipes would not reach the buckling limit and tensile strength limit due to excessive compression and tension. Total value of the hook load during pulling out of hole needs to be calculated and compared against the rig’s hoisting system. Moreover, directional drilling hydraulics plays an important role in determining the drillability of a well for a successful hole cleaning. Failure in hole cleaning can cause excessive overpull on trips, high rotary torque, stuck pipe, hole pack-off, excessive equivalent circulating density (ECD), cuttings accumulation, formation breakdown, slow rate of penetration, and difficulty running logs and casing. Therefore, it was important that the wells were simulated to ensure they met the hydraulics requirements. It was desirable to avoid planning wells with a tangent section within the critical hole inclination range, between 45° to 65°. There were instances that the critical range for hole cleaning was unable to be avoided, the tangent section was planned as short as possible instead. The flow rates were also selected for good hole cleaning for each hole

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sections for example 1000-1200 gallons per minute for 17-1/2” and 12-1/4” hole sections. Execution of the hydraulics analysis took into account the rig’s capability in terms of the mud pump efficiency. It was ensured that the total stand pipe pressure was limited to the rig’s liner pump’s availability and the total pressure loss to provide hydraulics energy to downhole tools were below the pop-off pressure. All these criteria were optimized to come up with the most feasible and cost efficient well designs, which supported by the available technology in the market as well as the rig’s capability. Initial Scenario: Two New WHPs. At the initial stage of the project, the EOR wells were planned from two new wellhead platforms (WHPs), BNIT-A and BNIT-B, to intercept all geological targets given (Fig. 3). A 3D view of the 25 EOR wells from BNIT-A and BNIT-B is shown in Fig. 4.

Initially, there were 25 wells planned to be drilled from WHPs BNIT-A and BNIT-B, to consist of the following: • Oil producer: 11 wells. • Gas producer: 7 wells. • Water injector: 6 wells. • Gas injector: 1 well.

Although major collision problems were experienced within the proximity wells of this congested Baronia field, after

several surface nudging iterations, effective slots designation, and proper planning, all the wells from these two platforms were achievable and the total measured depth (MD) was 227,527.11 ft. Further evaluation with respect to a drillability check (torque and drag, hydraulics, casing, and cementing design) confirmed the feasibility.

Optimized Scenario 1: One New WHP and Use of Four Spare Conductor Slots from Existing Platform. The new single WHP, BNIT-A, was placed in one optimized location, which was 2000 ft away. The optimization of the location of BNIT-A was performed on one centralized platform based on placement of horizontal drainage; the two outermost horizontal drainage alignments emphasized two wells to be two-dimensional (2D), while the rest of the horizontal wells were to be mid to quite severe three-dimensional (3D) horizontal profiles. Based on a 2000-ft radius to obtain a maximum of 3°/100 ft dogleg for the horizontal wells, the optimized platform coordinates for BNIT-A were selected.

The outer conductors’ well designation was performed effectively to kick off below the shoes at 600 ft MD at 2.3°/100 ft along specific gyro azimuth to disperse the bottomhole location outside the platform to avoid collision.

With respect to the inner conductors’ well designation, the planning was performed by true vertical depth (TVD) separation kicking off at different TVD depths to avoid collision. It is imperative to kick off the inner slot wells at the shallowest depth first, and then progress to the deepest kickoff for the best option of well dispersion of the outside platform (Fig. 5).

Additionally, full use of four spare conductor slots and two wells sidetracking from the existing BNDP-J platform was achieved at this stage. Six wells for targets located southwest of the field were replanned from BNDP-J to replace the eliminated BNIT-B WHP (Fig. 6).

Summary and Findings. Because of more stringent constraints of directional planning, this exercise triggered several

iterations of optimization cycles between drilling and reservoir engineering, in which “well creaming” was performed thoroughly to eliminate the low economic value wells. In addition, horizontal targets were realigned to simplify the well profile. Five wells were dropped from the initial plan of 25 wells with a very minimum impact on reserves, and hence improved the overall project economic tremendously.

All of the wells again were proven to be achievable with a total MD of 187,658.50 ft. The optimized location and the use of the spare conductor slots as well as the well creaming exercise saved the total footage by 39,868.61 ft; this is a massive savings with respect to drilling (Fig. 7). The most significant outcome from this, however, was the ability to reduce the number of new WHPs to a single new WHP, hence a significant reduction to facilities costs. This has potentially saved the overall project (Project CAPEX) approximately USD 250 million at the conceptual stage.

Optimized Scenario 2: One New WHP at Bridge Linking Location to Existing Platform BNDP-I. Further optimization work was undertaken to achieve greater cost savings for the project. The idea was to place the new platform at a site, which is 300 ft from the existing complex, BNDP-I, to enable bridge linking (Fig. 8). No live wells were ensured underneath the proposed location within a safe radius of 150 ft and the wells were set to kick off deeper, alleviating collision risk.

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At this stage, there were 20 wells planned to be drilled from platforms BNIT-A and BNDP-J, to consist of the following: • Oil producer: 5 wells. • Gas producer: 7 wells. • Water injector: 7 wells. • Gas injector: 1 well.

Summary and Findings. This bridging of the platform enabled the operating company to share platform facilities, such as

personnel living quarters, and achieve significant cost reduction on pipelines, which greatly contributed to lowering the budget of the overall project (Project CAPEX) as well as future projects (Project OPEX) (Fig. 9). The total footage to be drilled from this location was 184,035.90 ft. This, again, further shortened the total MD by 3622.63 ft. Additionally, significant reduction to project costs of USD 63 million was achieved through this optimization process.

Optimized Scenario 3: Hybrid Platform Design with Splitter Wells at Four Corners. A more optimized platform design was created to incorporate a 36-in. dual splitter system, with 2 × 13 3/8-in. surface casing, to be deployed with no restriction with regard to the surface casing deviation and kickoff depth (Fig. 10). The selection of wells for splitters was the first kickoff below the conductor shoes for wells with higher dogleg and complexity. The second kickoff was by 200 ft TVD separation. Surface dispersion of wells to be collision-free was important. Therefore, nudging of all wells for the best possible kickoff position was imperative.

Summary and Findings. With this hybrid platform design, less conductors were necessary to be installed while retaining

the number of wells. This significantly reduced time and cost for conductor installation. Additionally, it left less platform footprint, which enabled the use of a jackup rig instead of a tender assisted rig; hence, a lighter platform could be designed. The platform was then renamed BNDP-K.

Conclusion The success achieved for this EOR project at the conceptual well planning stage was largely contributed to a synergy of collaboration between all parties involved. Early engagement and technical input from specialized service providers from conceptual planning was vital to put the project on the correct path during the beginning stage.

The optimized outcome was also a clear example of effective interdisciplinary teamwork between sections within the project team, such as drilling, subsurface and surface facilities, for agreement on the best tradeoffs between tapping the maximum hydrocarbon reserves and the “drillability” of the options based on sound engineering considerations. This work involved navigating through a considerable iterative process to optimize well planning that eventually led to the best optimized case with a bridge link to a single WHP option (Fig. 11).

In terms of economic savings associated with these solutions, the reduction to the number of new WHPs from two platforms to one central platform as well as enabling a bridge link option demonstrated huge savings to the overall project (Project CAPEX); an estimated value of approximately USD 315 million was saved compared to the original base case scenario (Fig. 12).

In addition to all of the risk factors being reduced with all these solutions in place, the net benefits to the operating company have been positive in terms of financial (CAPEX and OPEX) as well as intangible risk reduction benefits. The collaboration between different parties with a single common objective for an economically efficient solution will be the way forward to achieve such success in the future.

Acknowledgement The authors thank the management of Petroliam National Berhad (PETRONAS), PETRONAS Carigali Sdn. Bhd. (PCSB), and Halliburton for support and permission to publish this paper.

References Pratap, M., Ibrahim, Z.B., and Karim, M.G. 2000. Reservoir Simulation Study of Baronia Field, Offshore Sarawak, Malaysia Indicates

Higher Reserves and OIIP. Paper SPE 64442 presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Brisbane, Australia, 16–18 October. http://dx.doi.org/10.2118/64442-MS.

Jadid, M. and Mustapah, M.F. 2007. A Performance Review of 14 Horizontal Wells in Baronia Field After 12 Years of Production. Paper SPE 107630 presented at the SPE Latin American & Caribbean Petroleum Engineering Conference, Buenos Aires, Argentina, 15–18 April. http://dx.doi.org/10.2118/107630-MS.

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Nomenclature EOR : Enhanced oil recovery WHP : Wellhead platform TVD : True vertical depth TVDSS : True vertical depth subsea CAPEX : Capital expenditure OPEX : Operational expenditure ft : feet in : inch DF : Derrick floor DLS : Dogleg Severity

Fig. 1—Location Map of Baronia field.

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Fig. 2—Baronia field spider plot shows four drilling platform (BNDP-A, BNDP-B, BNDP-I, and BNDP-J) and five jackets (BNJT-C, BNJT-D, BNJT-E, BNJT-F1, and BNJT-H1).

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Fig. 3—Spider plot shows 25 EOR wells planned from two WHPs, BNIT-A and BNIT-B.

Fig. 4—3D view of 25 EOR wells planned from BNIT-A and BNIT-B.

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Fig. 5—BNIT-A conductor plot shows surface separation by proper nudging at specific gyro azimuth for all the wells.

Fig. 6—BNDP-J conductor plot shows four wells are planned from four spare slots (marked in red) and two wells are sidetracking

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from existing wells.

Fig. 7—Spider plot shows 14 wells are planned from an optimized location of BNIT-A, and six wells are planned from existing platform, BNDP-J.

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Fig. 8—Plan view shows the shifting of the platform 2700 ft east-south (ES) for bridgelinking with BNDP-I.

Fig. 9—Spider plot shows all 20 EOR wells planned in the Baronia field from BNDP-J and BNIT-A.

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Fig. 10—Comparison of the previous platform and splitter wellhead platform design.

Fig. 11—EOR project flow chart.

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Fig. 12—Total reduction of Project CAPEX.