Nasir B. Darman

Geophysical issues and challenges in Malay and adjacent basins from an E & P perspective

Malay Basin, a northward-trending pull-apart extensional rift basin, formed during the late Eocene-early Oligocene and then underwent thermal subsidence and sedimentation during the early Miocene. Reorientation of regional stress fields during the mid-Miocene caused structural inversion resulting in east-west anticlines and half grabens.

EOR : The New Frontier in the Malay Basin Development

Tapis is one of the largest oil fields in the Malay Basin with almost thirty years of production. It is also the oldest pattern waterflood field in Malaysia. The field has undergone continuous implementation of improved oil recovery (IOR) strategies that include major workover campaigns, step-out drilling, and infill drilling programs. Application of IOR has increased the recoverable reserves and production capacity for economic operation of the field.

An Integrated Laboratory Workflow for the Design of a Foam Pilot in Malaysia

An integrated laboratory workflow for the design of a foam pilot in Malaysia. Max Chabert (Rhodia), Lahcen Nabzar (IFPEN), Siti Rohaida, Pauziyah Hamid (Petronas PRSB). We present the laboratory feasibility study dedicated to the design of an enhanced water alternating gas (EWAG) process for a Malaysian oilfield. The field is currently submitted to produced gas injection, mainly consisting of CO2. We focus here on the design of a water soluble foaming surfactant formulation using advanced characterization methods and the evaluation of this formulation in corefloods experiments. On-field conditions make the design of a surfactant formulation particularly challenging, with a reservoir temperature of 100°C and only sea water available for foaming formulation injection. The ultimate goal of this design study is thus to obtain an industrially realistic formulation yielding stable foams in reservoir conditions (including in presence of oil) at an affordable price. We set-up a specific laboratory workflow to design a foaming surfactant formulation adapted to reservoir settings. An automated screening routine based on robotics was used at ambient and reservoir temperature to pre-select the most performing formulations for foam stabilization among more than 400 binary and ternary mixes. Formulations solubility maps were obtained using automated image analysis. Only formulations perfectly soluble in the window defined by injection and production waters salinities were retained for further testing. Selected formulations were then characterized for foam stabilization in reservoir pressure and temperature conditions using a high pressure variable volume view cell. Adsorption of the selected formulations on reservoir crushed rock was optimized by exploiting synergistic effects between surfactant families. A formulation yielding over 2 hours foam half-life in reservoir conditions with a static adsorption below 1 mg/g was obtained. This formulation was further characterized in petrophysics application tests using analog Berea sandstones and reservoir rocks. These tests were designed to mimic potential pilot conditions in terms of injection strategy, injection rate and gas composition. High values of mobility reduction factors were obtained, including in presence of residual oil. This set of results is a first step toward application of an enhanced WAG foam process.

Breaking Oil Recovery Limit in Malaysian Thin Oil Rim Reservoirs: Water Injection Optimization

The goal of an oil field development project is to accelerate the hydrocarbon production and maximize the recovery at a lowest cost. For a thin oil rim reservoir with a large gas cap on top and a strong aquifer below, achieving such goal can be very challenging since recovery of both oil and gas shall be maximized. A successful project shall entail plan first to accelerate the oil production maximizing the oil recovery prior to the gas cap blow-down.

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.

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

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

Modelling of Asphaltene Precipitation and Deposition during WAG Application

Asphaltene precipitation and deposition from reservoir fluids during oil production life is a serious problem that can cause plugging in the formation, wellbore and production facilities. Precipitation and deposition may occur during primary production, during the displacement of reservoir oil by Co2, hydrocarbon gas or WAG application.