Mohamad Othman

How to Get the Most Out of Your Oil Rim Reservoirs

Oil production from oil rim reservoirs has always been a challenge due to their thinly spread oil resources and complicated production mechanisms. Movement of oil/water and gas/oil contacts could be very sensitive to conventional production operation and cause detrimental early water/gas breakthrough. The low oil production volume and hence low recovery (typically less than 18%) make the oil rim field development economically less attractive. However, integration of state-of-the-art engineering approaches, innovative technical initiatives and new technologies can make a significant change in the oil rim reservoir development. This paper, which is a brief of the author’s recent SPE distinguished lecture on the same topic, disseminates the applied fundamentals, critical elements and proven practices to maximize the hydrocarbon recovery in successful and integrated oil rim developments. The paper covers the reliable volumetric assessment and development concept (i.e., sequential, concurrent, etc.), robust and proactive reservoir management/monitoring policy to advice on depletion strategies and production to control the conning and cusping of water and gas. In addition, utilizing new technologies, appropriate production technology advice to assist timely development decision making, best simulation and modeling approach for the applied technologies (e.g., Horizontal/Multilateral wells, smart wells/completion, ICD/ICV, tracer, etc.) and complicated mechanism and dynamics involved in oil rim development are explained and discussed. The recommended workflow, guideline and technical initiatives will be elaborated throughout the paper and the success and value creation of the recommended methodology will be demonstrated in various real case studies. The paper demonstrates progressive and step-by-step recovery factor improvement up to additional 20% in the studied real cases.

Production Integrated Smart Completion Benchmark for Field Re-Development

For marginal field development and mature field re-development, the main art of maximizing reservoir contact is to design wells that could enable commingle production simultaneously depleting not only the major but also the selected minor sands in the field. Field implementation cases in Malaysia have been shown that this could significantly minimize the well count, increase the well productivity, and improve the ultimate recovery per well particularly in the multiple-stacked and compartmentalized reservoirs. Commingle production from several sands may have the risks and the uncertainties, among others, of layer cross-flow, excessive GOR production and early water breakthrough at certain sand intervals due to uneven pressure depletion, uneven gas and water mobility. These production risks and uncertainties shall be evaluated for ensuring the predicted life-cycle production performance of the designed commingles production wells. Minimization of these risks could involve developing of a pressure drawdown management plan, the optimization of injection fluid conformance control and the prediction of reservoir pressure change. The resulting pressure drawdown plan may then generate a requirement for individual down-hole flow control at each commingled sands. Accordingly, the smart completion comprises of inflow control devices such as passive ICD and/or active ICV with or without down-hole pressure and inflow monitoring devices namely, PDG or DTS installation can then be adequately designed. This paper is to illustrate a production integrated smart well completion design process starting from reservoir drainage and injection points selection, the determination of well reservoir contact trajectory, the production evaluation and risk analysis, and to the selection and application of smart completion devices. The case of a deepwater reservoir field development smart well completion design was used to demonstrate the viability of this integrated engineering approach. This approach is a partial effort to achieve effective field development by lowering the overall field development cost and maximizing the oil and gas recovery. The presented reservoir engineering workflows and completion design methodologies is to constitute a new smart well completion benchmark for well design and production optimization and serve as an engineering guide for optimizing the well construction cost in Malaysia.

Smart Horizontal Well Drilling and Completion for Effective Development of Thin Oil-Rim Reservoirs in Malaysia

For thin oil-rim reservoirs, well placement, well type, well path and the completion methods shall be evaluated with close integration of key reservoir and production engineering considerations. This involves maximizing reservoir fluid contact and drainage, optimizing the well productivity, and optimizing well life-cycle production profile along the wellbore. Field implementation cases in Malaysia have been shown that this integrated approach to design and drill horizontal wells can significantly minimize the well count, enhance the well performance, and improve the ultimate recovery per well in thin oil-rim reservoirs with varying reservoir complexity and uncertainties. 45 horizontal wells were progressively drilled and all completed with ICD in a relatively flat thin oil-rim reservoir offshore in peninsular Malaysia. In this successful oil development, well path between the GOC and OWC was optimized to delay the water breakthrough and reduce the decline trend in different reservoir sectors with varying horizontal well length up to > 2,000 m. Good performance of the ICD was confirmed by PLT surveys and by tracer effluents evaluation with different type of tracers implemented in various sections of the horizontal well completion. For a low pressure thinner oil-rim reservoir in offshore Sabah, horizontal wells were drilled with ICV completed in the gas cap. This smart well design enables having in-situ gas lift operation during the initial oil production, and progressively changing to the planned gas-cap blow-down operation for maximizing the overall hydrocarbon recovery. In another oil-rim reservoir, a long horizontal wellbore with ICD design was completed with dual-strings to further optimize drawdown pressure distribution along the long wellbore and improve oil drainage and oil recovery.

An Integrated Reservoir Simulation-Geomechanical Study on Feasibility of CO2 Storage in M4 Carbonate Reservoir, Malaysia

The M4 Field is located north of Central Luconia Province in the Sarawak Basin, East Malaysia. The reservoir is approximately 2000 m below sea-level where the water depth is approximately 120m. An integrated geomechanical study for CO2 geological storage has been conducted to evaluate the feasibility of injecting and storing CO2 in the M4 depleted carbonate gas reservoir. The storage feasibility of M4 reservoir is impacted by interaction of the reservoir rock with carbonic acid formed by dissolution of injected CO2 in the water which has risen close to the cap-rock. The geomechanical study needs to assess the risk of CO2 leakage from the reservoir due to degradation of the integrity of the cap-rock by the injection operations, and interaction of the injected CO2 and carbonic acid with the cap and reservoir rocks.

Production Integrated Sand Control Benchmark for Mature Field Development

Current offshore marginal field development and mature field re-development in Malaysia consistently encountered high development cost and low recovery or incremental recovery. Wells are being drilled and completed at a high cost of 15 to 30 M

Thinly Bedded Reservoir Characterization, From Qualitative to Quantitative Approach, Case Studies in a Cenozoic Basin of Malaysia

per well while the estimated ultimate recovery (EUR) per well is as low as < 0.4 M Bbl. The associated well development cost (WDC) can be higher than 75

Simulation of Chemical Interaction of Injected CO2 and Carbonic Acid Based on Laboratory Tests in 3D Coupled Geomechanical Modelling

/Bbl. This high WDC cost can be further aggravated by a significant increase in completion cost if an expensive sand control method is required to mitigate risk of sand production. Rock mechanical properties, stress and pressure distribution can vary widely, from layer to layer, rock facies to facies in the reservoir. Reservoir pore pressure and its distribution could also change drastically during the entire production life cycle. With results of field case studies as examples, this paper is to share our engineering approach in first determining where and when we need sand control based on the geo-mechanical sand-free critical drawdown pressure (CDP) evaluation for the selected well type, configuration and completion. The generated CDP will be later coupled with the current pressure and fluid distribution predicted from the reservoir simulation model and confirmed with the historical pressure and production data for well type, completion and sand control strategy in mature fields. Decision to implement a proper sand control can be made by comparing the CDP with the minimum drawdown pressure (MDP) required to meet the expected production rate target. Sand control method selection shall then be based not only on the sand particle size distribution, well life and the mode of well production (single selective or commingle) but also on maximizing reservoir contact and oil and gas recovery per well. The presented workflows and methodologies is to constitute a new sand control benchmark for well design and production optimization and serve as an engineering guide for optimizing the sand control cost in Malaysia.

Challenges in Determination of Water Content and Condensed Water in a Multistacked Sour Gas Field Containing High CO2 Content Offshore Malaysia

The limit of resolution of seismic data is a complex issue that involves not only wavelet frequency, phase characters, data quality (S/N), interference, tuning, but also criteria on how to measure resolvability, which can hamper confident lithology, porosity and fluid prediction of thinly bedded reservoirs. Widess‟s classic paper (1973) concluded that for thin beds (below λ/8 wavelength), the seismic character, peak/trough time and frequency do not change appreciably with thickness, and also amplitude varies almost linearly with thickness, which goes to zero at zero thickness. Thus, λ/8 of wavelength is considered to be the fundamental limit of vertical seismic resolution which depends on velocity and mainly frequency. Tirado‟s work (2004) revised Widess‟s model, which is not applicable to the real reflection, and concluded that as the bed thickness decreases, there is a gradual increase in the peak frequency, but below a certain thickness (at some fraction of tuning thickness), the peak frequency rolls off and return to the peak frequency of the wavelet at zero thickness. Thus, the key factor in determining seismic resolution is by enhancing the frequency spectral bandwidth which, nowadays, can be effectively achieved either by acquiring Broadband Acquisition or conducting Broadband Seismic Re-Processing. We demonstrated various case studies on thinly bedded reservoirs using qualitative and qualitative techniques in a Cenozoic basin in Malaysia. The qualitative techniques involve the -90° Phase wavelets with Relative Colored Inversion, Spectral Decomposition, and ThinMAN broadband spectral inversion. The quantitative approach includes an integrated multi-disciplinary technique combining with Cascading AVO Simultaneous inversion and Stochastic Inversion calibrated with conventional and SHARP-OBMI logs, which together, significantly enhance imaging of the thinly bedded reservoirs. This unique integrated workflow has been applied in the field study, resulting in an increase of about 30% of hydrocarbon in-place volume, and has been successfully validated with available production/well data as well as newly drilled wells.

Offshore Chemical EOR: The Role of an Innovative Laboratory Program in Managing Result Uncertainty to Ensure the Success of a Pilot Field Implementation

The M4 field is located in the North of the Central Luconia Province in the Sarawak Basin, East Malaysia. The reservoir is approximately 2000 m below sea-level where the water depth is approximately 120m. A study for CO2 geological storage has been carried out to address the feasibility of injecting and storing CO2 in the M4 depleted carbonate gas reservoir using 3D coupled geomechanical modeling. The water level in the reservoir has risen close to the cap-rock which implies a strong aquifer. Laboratory tests were carried out on core samples before and after injection of a CO2 saturated brine solution, and the results were used in the determination of material property strength and elastic property degradation due to acid-carbonate interaction. Triaxial compression tests on carbonate samples from three different depths at the peak loading stage of the tests for different confining pressures were performed. The effects of CO2 saturation on UCS, Young‟s modulus and Poisson‟s ratio were determined. The permeability measurements from the pore volume compressibility tests and permeability measurements obtained during the measurements of petrophysical properties were used to evaluate the effects of acidcarbonate interactions. The 3D geomechanical model coupled the reservoir pressures derived from a dynamic model with a stress simulator in order to calculate changes in effective stress and volumetric strain within the 3D model. The derived changes in volumetric strain were related to a change in porosity and permeability which were then passed back to the dynamic model in a staggered solution scheme. At each “stress step” in the solution process, a further modification was made to geomechanical material properties due to the increased CO2 saturation from injection. The material parameter modifications were based on the results of the laboratory tests above. In this way, the material property degradation due to CO2 injection was accounted for during the coupled reservoir geomechanical simulations. The paper discusses the results of these tests and the derived variation of material permeability, elasticity and strength parameters with CO2 saturation for subsequent input to the coupled geomechanical solution scheme. In this way, the potential risk due to the chemical interaction from CO2 injection could be evaluated quantitatively. Introduction Controlling the trapping of CO2 in the subsurface is of fundamental importance for safe geological storage of CO2. Rock formations can be impervious enough to act as flow barriers to CO2 over geological periods of time. Delineating such a seal, safeguarding its integrity under operational conditions, and verifying its isolation effectiveness are key objectives in achieving a successful CO2 storage project. During CO2 injection, increasing fluid pressure, temperature variation, and chemical reactions between the gas and rocks inherently affect the state of stress inside the reservoir and its surroundings. In addition, the mechanical properties of the rocks may be altered by their exposure to CO2 and/or pressure and stress changes. Furthermore, rock mechanical properties, pore pressure, in-situ stresses and the stress evolvement under injection conditions control re-activation of a fault, and therefore risk of fault seal breach. The impact of the resulting stress and pressure change and associated deformation on cap

Meeting the Challenges in Alkaline Surfactant Pilot Project Implementation at Angsi Field, Offshore Malaysia

The amount of condensed water should be carefully estimated in gas development plans, especially for fields with high CO2 content. This may affect the design of the well, surface facilities such as water treatment equipment and CO2 removal units, and flow assurance and corrosion control strategies. However, reliable prediction of the water content of gas with high CO2 level in contact with formation brine is still a challenge.