IPTC Abstract. Introduction

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1 IPTC Doubling a Marginal Field's Reserves by Understanding the Application of "Enabling" Technology Ong Tee Suan, Newfield Exploration; Mark Lambert, Newfield Sarawak Malaysia Inc; Barry Goodin, Senergy Australia Pty Ltd; Mohamad Othman, PETRONAS Copyright 2011, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Bangkok, Thailand, November This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum 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 where and by whom the paper was presented. Write Librarian, IPTC, P.O. Box , Richardson, TX , U.S.A., fax Abstract Successful application of enabling technologies in the phased development of Malaysia s marginal East Belumut field resulted in reserves doubling between Field Development approval in 2006 and post development in The field development has multiple challenges given the thin-oil column (46 feet) entirely within the transition zone, unfavorable crude quality, a large gas-cap and extensive bottom water, a large but low relief structure, and a shallow poorly consolidated sandstone reservoir. Developing such a marginal field requires extensive reservoir simulation to plan the optimal well spacing, counts, lengths, landing depths, and withdrawal rates. To implement the plan, drilling and geosteering technologies must achieve extended reach wells with long (greater than 6000 feet) open-hole horizontal sections. Completions require Stand Alone Screens (SAS) and Inflow Control Devices (ICD) to prevent sand production and to distribute the drawdown evenly along the entire well length. The ICD designs are modeled using segmented well simulation models with ICD configurations. After the initial development, extensive field trials are conducted to measure well drawdown, water breakthrough timing, and water-cut increase. Production Logging Tools (PLT) and tracer technologies are applied to confirm the entire horizontal section contributes to total fluid inflow. The field trial data is subsequently used for validating the simulation result and optimizing the next phase of development. At the end of 2010 the field has two and a half years of production history from two successful phases of development (14 wells drilled). A third phase of development drilling has begun in second quarter 2011 (up to an additional 27 wells). The oil production build-up and rate are performing better than those envisaged in the original sanction plan. As a result the reserves have doubled since the sanction time. Introduction East Belumut field is located 160 miles northeast of Terengganu, Malaysia near Vietnam and Indonesia. East Belumut s primary oil reservoir is a Tertiary-aged, areally extensive, highly porous and permeable oil reservoir. East Belumut is considered a marginal field development due to initial reserves of less than 30MMbbl. East Belumut is a particularly challenging development due to the thin 46 foot oil column, the low-gravity (23 API) high-viscosity (3cP) oil, and the productive interval being entirely within the oil-water transition zone. Furthermore the thin oil column is sandwiched between an underlying bottom aquifer and a gas cap. East Belumut was discovered by a major International Oil Company (IOC) in 1970 and appraised by them from 1994 to Following the appraisal program, the IOC deemed the field to be uncommercial and relinquished the field. Newfield Peninsula Malaysia was awarded block PM323 containing the East Belumut field in August 2005 and committed to developing the field on a fast track development schedule. In 2008 Newfield began a phased horizontal production well

2 2 IPTC drilling program that initially addressed development uncertainties prior to the more extensive drilling in The uncertainties include structural-stratigraphic variability, pay continuity and heterogeneity, optimal parameters for drilling and completing long horizontal wells, performance of inflow control devices, horizontal well spacing, and vertical positioning of horizontal wells to minimize gas and water coning. After drilling and completing 15 long horizontal wells, East Belumut is producing 28,000 bopd. By the end of the development drilling program the expected well count is 30 to 40 horizontal producers. Geology East Belumut field development focuses on a shallow broad 4500 acre three-way dip closure bounded to the west by a highangle fault complex (Figure 1). The reservoir is comprised of braided fluvial sandstones capped by lacustrine deltaic sandstones and shales (Figure 2). Median net to gross in the fluvial and deltaic sandstones is 98 and 30 percent respectively. A field-wide low permeability shaly siltstone 15 to 50 feet thick separates the deltaic and fluvial sandstones (Figure 2). The fluvial sandstones are medium to coarse grained with high median porosity and permeability (30 percent and 1400 md respectively). The overlying deltaic sandstones are fine-grained with relatively lower porosity and permeability (median 25 percent and 180 md). Early appraisal wells defined the structure and stratigraphy and encountered the gas-oil contact (GOC) and oil-water contact (OWC) (Figure 2), thus the oil resource is well established. The crude has 23 API specific gravity and high viscosity (3cp at 174 F), causing a high water to oil relative mobility ratio. Gas-oil-ratio (GOR) is 205 scf/stb (1.11 FVF), the bubble point is 1623 psia, and the pour point is 5 F. Challenges Determining the optimal development and recovery factor (RF) for this type of reservoir is challenging as there are no analogues in the Malay Basin (and few analogues worldwide) for a meaningful reference. East Belumut development challenges are as follows. Depletion strategies Reservoir pressure maintenance and gas and water contact movements from gas injection or natural water drive. Vertical positioning of horizontal wellbores to minimize gas and water coning. Lateral well spacing that maximizes RF but minimizes interference. Optimal well count that maximizes RF. Effective length of horizontal wells. Reservoir Management Optimum withdrawal rate based on GOR and water cut performance. Optimum gas injection volumes to manage reservoir pressure. Drilling and Completion Ability to drill long (greater than 6000 ft) horizontal wells while maintaining the horizontal and vertical position of the drillbit within a narrow (+/- 3ft) window in a poorly consolidated sandstone reservoir. Managing the mud weights and Equivalent Circulating Density (ECD) to prevent the horizontal sections from collapsing but also prevent hydraulically fracturing the poorly consolidated formation. Effective wellbore cleaning while drilling extended reach horizontal wells. Selection and correct installation of sand control technologies in extended reach wells. Preventing plugging of sand screens with filter cake during initial production and ensuring sand screens do not fail over the long term production life. Ability to deploy sand screen completions to bottom without rotating and damaging the screens (limited string weight is available for sliding screens due to shallow reservoir depth and extend reach of wells).

3 IPTC Facilities and Platform Sizing Upfront design of platform size, well slots, production, and export facilities that is flexible enough to cater for production uncertainties. Solutions Due to the inherent high risk nature of this marginal field development, significant resources were spent in pre-development planning to quantify the possible outcome of various development scenarios. Execution of the selected scenario was carried out in three drilling phases. An initial phase quantified the uncertainties and risks by collecting and analyzing geological and production data. The early learnings were compared against the assumptions made in the pre-development planning and incorporated in subsequent drilling phases with the objective of optimizing the entire development. Similarly, extensive resources were invested in planning the drilling and completion of the long-reach horizontal wells. Key learnings were quickly incorporated throughout the field development. Pre-development: Full field reservoir simulation and sector modeling were used to quantify the range of recovery factors (RF) for different depletion strategies under two possible geological scenarios. Prior to development it was known that low permeability shaly siltstones occur between the overlying deltaic sandstones and the underlying fluvial sandstones (Figure2). However, it was unclear how laterally extensive the siltstones were and if they compartmentalized the gas-cap. Thus the two geological scenarios were (1) a field-wide vertical barrier with a small effective gas cap and (2) several local vertical barriers with a large single gas cap. An additional geologic uncertainty was the extent and strength of the aquifer. Field development parameters such as well spacing, well count, horizontal well length, and well landing depth were evaluated under these two geological scenarios. While full field modeling (FFM) is useful to address the range of possible outcomes of the field development, smaller sector models better represent the performance of single or multiple wells (Figure 5). This is because finer areal gridding and thinner layering are imposed on the sector model to facilitate small-scale reservoir dynamics while keeping a lower overhead than the FFM. It is necessary for flux boundaries to be preserved in the sectors extracted from the FFM. In addition to the above, Local Grid Refinement (LGR) and Multi-Segment Well modeling (MSW) were used to further bracket and quantify the RF. Describing fluid dynamics in the transition oil zone is crucial for predicting RF in this thin oil column reservoir. Drill-stem tests (DST) conducted by the previous IOC in the appraisal wells did not experience water production break-through. However the DST perforations were near the top of the oil column, the testing duration was short and without artificial lift, and thus the DST results may not be representative. The sector models predict the horizontal wells will produce water almost immediately because the completion is in the transition zone with 40% water saturation. Several modeling techniques and parameters were explored to retard the production of water without sacrificing the relative permeability function curves derived from the special core analysis. Later, the relative permeability function curves were validated against the actual water production performance and subsequently used for the predictions. Horizontal well completion design was driven by reservoir simulation results from Multi-Segment Well (MSW) modeling which mimics the performance of Inflow Control Devices (ICD) with various port sizings (Figure 5). The reservoir simulation predicts the life-long benefits of ICD in this type of reservoir, and more importantly, quantifies the benefits based on different design scenarios. Detailed completion modeling of the horizontal wells was carried out using nodal analysis techniques and Netool to determine the individual ICD settings and to ensure that the completions could provide the required capabilities. Early Development: Phased drilling programs permitted early learnings to be systematically applied so that the overall field development was optimized. Early phases allowed for field testing of drilling, completion, and reservoir parameters while preserving the flexibility for refinements in later phases. Seven wells were drilled as Phase-1 and covered the entire structure to confirm the extent of closure, reservoir continuity and quality, and fluid contacts. As drilling, geosteering, and completion practices were progressively refined, the horizontal length of the wells increased up to 6900 feet. Two wells were drilled at a close spacing for pressure interference test with the aim of assessing the well spacing effect. A wide range of enabling technologies was selected to overcome drilling and completion challenges. For example, keeping the drill bit within the required tight vertical window was achieved with a point-the-bit Rotary Steerable System (RSS). The drill bit position was also optimized with specific geosteering techniques, advanced Logging-While-Drilling (LWD) tools, and Real-Time-Operations (RTO) monitoring from the office (Figure 3). Due to inherent MWD survey error, geosteering

4 4 IPTC focused on the relative position of the bit within the transition zone using resistivity modeling. Changes in resistivity are due to changes in water saturation or lithology. Therefore borehole cuttings and LWD data were used to distinguish fluvial from deltaic sandstones, the later having a fine-grained texture and higher bound water which suppresses resistivity. Identifying the lithology permits removing bound-water effects, so to focus only on relative changes in water saturation within the oil transition zone. A Synthetic-Based-Mud (SBM) system provided the required fluid properties for drilling these extended reach wells, including the use of fine ground barite for rheology and filter cake flowback properties. The range in mud weights is very narrow for stabilizing the horizontal wellbore but not hydraulically fracturing the reservoir. For hole cleaning and stability, the required mud weight and Equivalent-Circulation-Density (ECD) were achieved through optimizing well design, bottom hole assembly (BHA) design, and drilling parameters. Premium Stand-Alone-Sand-Screen (SAS) systems provided the required level of sand control for long horizontal wells (greater than 6000 ft of screen interval) while permitting filter cake to be flowed back through the screens once the well commences production (Figure 4). To accommodate the sand screens in the open hole section, the hole diameter was widened from 8-1/2 to 9-1/2 using Hole-Opening-While-Drilling reamers. Ultra-low friction solid body thermoplastic centralizers assisted in deploying the screens to bottom. Multiple swell packers then compartmentalized the completion interval to isolate zones of high and low permeabilities as well as shaly nonpay. Inflow-Control-Devices (ICDs) were installed to control fluid inflow and pressure drop along the entire horizontal well length (Figure 4). Managing pressure drop should reduce gas and water coning along the wellbore. Measuring Performance: Production and reservoir pressure data were measured at a regular frequent basis to understand the reservoir behavior in different quadrants of the field. Nonpermanent, wireline retrieved Downhole Pressure Gauges (DPG) were installed in five wells to measure field-wide pressure decline during early production and record well pressure drawdown at the sand face. Fluid withdrawal rates were progressively increased in each well while the DPG measured the water-cut response as a function of pressure drawdown. Production Logging Tools (PLT) and chemical tracers were run in selected wells to assess the inflow profile along the horizontal section, with special focus on toe contribution. Gas Injection volume was carefully monitored, together with the water-cut and GOR performance, to ensure the injection and production performance was aligned to the reservoir management requirement, i.e. injecting at 90% of produced gas. Incorporating Learnings: The 3D static model was updated with newly acquired geological information throughout the phased drilling. The new wells confirmed that the low permeability shaly siltstone did extend across the entire field creating a vertical barrier between the overlying deltaic sandstones and the underlying fluvial sandstones, thus reducing the size of the effective gas cap (Figure 6). The well data also confirmed that reservoir quality, fluid contacts, and the transitional oil zone were similar fieldwide. The targeted placement of the Phase-1 wells reduced the uncertainties related to structure, reservoir continuity and quality, and the lateral extent of the tight siltstone barrier. As a result, there is high confidence in the resulting resource assessment. The static model was subsequently conditioned for FFM reservoir simulation and all production performance and pressure data were incorporated and history matched. The history matching process is important to calibrate the relative strength of the bottom water drive and the gas-cap, and to quantify the amount of gas injection required to achieve maximum recovery. During the process, the design of the ICD (i.e. port size and the number of open ports) was refined using updated sector models which incorporated the PLT results and utilized the MSW module (Figure 5). Numerous cases were then simulated on the updated history-matched model to optimize the remaining development program, with particular emphasis on well spacing, landing depth, horizontal length, production rates, and GI/GP. Well and reservoir performance to date indicate that RF can increase further with additional development wells (Figure 7). Results to-date The results are very encouraging and at the time of writing the final estimated ultimate recovery (EUR) is projected to be double what was expected in the initial Field Development Plan (FDP). The production build-up and sustained rates have exceeded expectations even though only one third of the field has been developed. Reservoir and well performance information, such as pressure trending, well interference, and water-cut and GOR trends, are all very positive. Due to their positions within the transition zone the Phase-1 wells did have water breakthrough, but much later than predicted by the reservoir simulation. The dynamic model was updated with the early production results and it predicted a further

5 IPTC delay in water-cut if the wellbores were shifted up 3 to 6 feet. This was tested midway through Phase-1 and indeed higher initial production rates were realized and a further delay in water-cut break-through was seen. The GOR performance is not as high as predicted in the early reservoir dynamic model. This is likely due to the smaller effective gas cap created by the tight siltstone barrier that separates the deltaic sandstones from the fluvial sands. This barrier was initially believed to be a local buffer to gas encroachment, however it is now believed to be a field-wide barrier prohibiting gas encroachment. DPG data confirmed low pressure drawdown ranging from 20 to 100 psi, which includes the pressure drop across the ICDs. This equates to world class Productivity Indices (PI) for the wells in the range of 100bpd/psi to 800 bpd/psi. When withdrawal rates were increased, the measured drawdown and water-cut did not increase linearly. Continued adjustments helped pin point the optimum withdrawal rate, which eventually were confirmed by reservoir modeling work. Both the Operator and the Regulatory Body were concerned about flow contribution from the entire length of these longreach horizontal wells. To address this issue, the Operator investigated the horizontal well contribution using both tracer and PLT technologies. A non radioactive oil soluble tracer was installed inside the ICD housing and run in the last of the Phase 2 production wells. Tracers were also placed at the toe of two horizontal wells and the heel, middle, and toe of a third well. While providing only indicative non quantifiable results, the tracer did confirm expected levels of inflow contribution from the toe of horizontal wells greater than 6000 ft in length. In order to further understand and to quantify the inflow contribution of the long horizontal wells, the Operator conducted production logging in two wells using tractor conveyed production logging tools (PLT). To ensure that the wells could be logged, they were first cleaned out using coil tubing. The PLT and tracer results confirmed that the entire completed horizontal interval including the toe is contributing as designed (Figure 8). Furthermore, the pressure drawdown derived from the PLT shows the entire wellbore has the same drawdown, thus minimizing the effect of hot spots and further confirming the application of ICD technology and the ICD port design (Figure 9). The initial plan was to observe the Phase-1 performance for 18 months before embarking on Phase-2. However, due to exceptional Phase-1 results, Phase-2 was initiated 6 months later. The reservoir and well performance data collected by that time was already sufficient to justify further development. Phase-2 consisted of 7 horizontal wells and has been on production for the last 12 months with excellent results (Figure 10). Future plans Phase-3 consists of 10 wells approved by the Regulatory Body and scheduled to be completed by the middle of Phase- 1 and Phase-2 drilling and production results over the last two and a half years have provided significant input on how to proceed with Phase-3. Refined drilling and geosteering techniques allow for horizontal lengths exceeding 6900 feet. Completion designs guarantee contribution from the entire horizontal length, and optimized well placement and production rates maximize oil production while managing GOR and water-cut. Overall the Operator is encouraged to increase the well count to optimize the field RF (Figure 11). The Operator s understanding of the field has resulted in a more than doubling of the booked P90 reserves for this marginal field and is likely to double the EUR that was predicted in the original FDP Key learnings from the East Belumut development program have already been applied to other assets with similar positive results. The creative application of enabling technologies facilitates success in the development of marginal fields.

6 6 IPTC Figure 1: East Belumut broad structure and fluid contacts Pre Development Figure 2: East Belumut type log showing depositional facies and fluid contacts

7 IPTC Figure 3: Realtime Logging While Drlling to monitor the drill bit s vertical positioning within ± 3 ft window Figure 4: Premium Stand Alone Sand Screens (SAS) and Inflow Control Devices (ICD) used in the completion of the horizontal section

8 8 IPTC Figure 5: Sector modeling to quantify ICD effect Figure 6: Field-wide tight shaley siltstone that seperates deltaic and fluvial sandstones and splits the gas cap

9 IPTC Figure 7: East Belumut reserves increasing over time Figure 8: Production Logging Tool (PLT) results showing oil contribution from the entire horizontal section

10 10 IPTC Figure 9: PLT results showing similar pressure drawdown along the entire horizontal section Figure 10: East Belumut Phase-1 and Phase-2 oil production to date

11 IPTC Figure 11: East Belumut proposed full field development in 3 drilling phases