Chemical Enhanced Oil Recovery (EOR) processes are being considered for large field applications with recent high price of crude oil. However, applications are generally directed towards onshore environment, with temperature less than 85oC, using fresh water as the injection water. Malaysian oil fields are located offshore, with high reservoir temperatures of more than 100oC and use sea water as injection water. This paper reports on laboratory results that were part of an R&D project investigating the feasibility of increasing oil recovery through chemical EOR processes for oil fields in Malaysia. Chemical EOR processes investigated include surfactant, surfactant-polymer, alkaline-surfactant, and alkaline-surfactant-polymer. A unique 2-stage softening prepared seawater for the two processes using alkali. Thermal aging studies at 119oC were used to screen chemicals for stability and degradation. Interfacial tension and phase behavior tests of stable chemicals were used to select formulations. Linear corefloods and thermal degradation tests were used to select polymers. Oil recovery studies used field proportioned injected chemical volumes in radial corefloods. Dilute surfactant processes without alkali recovered little incremental oil. This was attributed to heavy consumption loss of surfactant. Average incremental oil recovery in coreflood studies by alkali-surfactant flooding was 14.6% OOIP and by alkaline-surfactant-polymer flooding was 28.6% OOIP respectively. This proved that there is potential for chemical EOR application in Malaysia. INTRODUCTION Despite the very harsh environment for chemical EOR processes in Malaysia, PETRONAS has undertaken an R&D project whose scope of work includes:Phase 1: screening of suitable reservoirs and chemical processes,Phase 2a: detailed chemical laboratory design,Phase 2b: reservoir modeling to estimate process performance,Phase 3: economic evaluation andPhase 4: conceptual pilot design. This paper focuses on the laboratory aspects of the study (Phase 2a) of the Angsi I-68 reservoir that was selected in Phase 1. It includes the overall chemical EOR processes evaluations and design, and observed incremental oil production from coreflood experiments at laboratory scale. Chemical EOR Considerations Chemical EOR processes in offshore environments are constrained much more by "footprint" or available space on platforms than are their onshore counterparts. Therefore, the simpler the process utilized the better. An ideal process would be to simply add a liquid surfactant to the seawater currently being injected. The objective would be to mobilize waterflood residual oil trapped by capillary forces by reducing interfacial tension. A single liquid surfactant would require only storage, metering, and blending into the injection stream. Any other chemicals added would have the same requirements, which may be complicated if, for instance, the chemical were a solid rather than a liquid. However, an objective of the R&D program was to investigate a range of Chemical EOR processes that may be technically viable. These included surfactant (S), surfactant-polymer (SP), alkaline-surfactant (AS), and alkaline-surfactant-polymer (ASP).

Highly paraffinic (or waxy) crude oil can cause significant problems in the pipelines due to wax–oil gel blockage resulting from the precipitation of the wax components. Once blockage of the pipeline occurs and flow ceases, the pipeline flow cannot be restarted with the original steady state operating pressure but instead requires significantly higher pressures to restart the flow. Due to this, it is important to maintain the oil at a temperature above its natural pour point. The incorporation of chemical products known as wax inhibitors and pour point depressant (PPD) reduce the pour point and viscosity of oil. This paper introduces an indigenously synthesized wax inhibitor from the hydrophobically modified polybetaines (zwitterionic) family for treating waxy crude A located in Peninsular Malaysia. The synthesized wax inhibitor had been evaluated as flow improver, crystal modifier and pour point depressant. The wax inhibitor coded CRODDA-AA, works efficiently since it can reduce the pour point of waxy crude A by 12°C and the viscosity about half of the original value at 1000 ppm concentration, as well as lowering the yield stress by 8 Pa at 51°C. In order to assess the use of the CRODDA-AA wax inhibitor for squeeze applications, a core flood study was conducted to determine its adsorption capability onto formation. A formation damage study was also conducted to ensure that there is no formation damage coupled with the injection of wax inhibitor. It was found that wax inhibitor CRODDA-AA can be retained in the formation up to 88.5% without significant formation damage. As a next step, it is planned to run the core flood and wax inhibitor release tests to refine the design of squeeze treatment.

Ensuring a pilot project a success operationally, while gathering reliable data for a full-field implementation is critical. For this reason, various aspects of project planning and operational considerations need to be addressed. This include conceptual design, facilities and operational considerations, resources planning, integration of activities and most importantly, pilot objectives. However, all these planning will not be successful without a properly designed and executed laboratory test program. Such laboratory program will minimize result uncertainty and ensure the proposed pilot meet its objectives. The first Chemical EOR (CEOR) pilot project in Malaysia involved an Alkaline-Surfactant injection utilizing high salinity injection water in a high temperature reservoir. It pioneered the Single Well Chemical Tracer (SWCT) method for EOR project evaluation in Malaysia. The main objective of the pilot is to assess the effectiveness of the Alkaline-Surfactant formulation to improve oil ultimate recovery through the reduction of residual oil saturation. Being the first of its kind in Malaysia, an extensive laboratory program is required to ensure the injected alkaline surfactant formulation performed at its most optimum and conclusive data is gathered. This data will be used as input to the future field development plan. This paper presents a comprehensive laboratory test program covering pre-pilot, pilot and post-pilot laboratory analysis designed for offshore high salinity injection water and high temperature reservoir. It highlights the challenges imposed by offshore operation to design an optimum chemical solution considering that salinity and hardness of the water used to dissolve the chemicals are critical for an alkaline-surfactant system. It also discusses the continuous and controlled quality check process to validate the performance of the alkaline-surfactant solution. Finally, it presents the chemical adsorption study to evaluate chemical flood potential for the future full field CEOR implementation. Introduction PETRONAS has undertaken a 3-year R&D project which evaluated the feasibility of a CEOR process for Malaysian oilfields. The research also identified suitable chemicals that can withstand the high temperature and high salinity environment and suitable candidate reservoir for pilot implementation (Othman et al. 2007). Based on the R&D study, Angsi field, located east coast of Peninsular Malaysia was selected for pilot implementation. The execution of this pilot project was also targeted to establish the required technical, operational and management skills before embarking on a large scale full field chemical flood. The results of the CEOR pilot project are crucial to the future decision making for full field implementation. A lot of considerations were given to gather reliable and conclusive data, within which, will manage results uncertainty. One of the ways is to ensure accuracy of the chemical preparation and injection process. All these can be achieved by a properly designed laboratory test program to tackle specific issues on optimum chemical slug design and quality of chemicals injected. It also aimed to measure the degree of chemical loss to reservoir rock, in which will evaluate the sustainability of the chemicals in a high temperature reservoir.

Drilling experience in K-shale in the Malay Basin of Peninsular Malaysia highlighted the issue of wellbore stability in the formation. A wide range of drilling problems has been experienced, ranging from sloughing shale to tight hole and stuck pipe. Subsequently, a major collaborative project between CSIRO Petroleum and PETRONAS Research &Scientific Services Sdn Bhd was conducted to address the problems. The aim is to develop a technical framework of drilling fluid design and consolidate into a methodology for overcoming wellbore instability-related problems in the shale. This paper describes the outline of the project and the approach adopted in the development of the methodology. The approach is based on drilling fluid-shale interaction and proven rock mechanics principles which include an extensive laboratory testing program on downhole core specifically cut for the study. Based on the gathered drilling experience and laboratory tests conducted on downhole core material, dominant time-dependent failure mechanisms of the shale were identified. Examples of critical mud weight contour plots and design charts of pressure change (due to drilling fluid-shale interaction mechanisms) which form part of the consolidated methodology for designing optimal drilling fluid are presented. Comparisons between predicted mud weights determined from the contour plots and mud weights used in one of the fields showed an overall good agreement between the mud weights, drilling experience and hole size. Counter to operational expectations, the results from the laboratory study showed that some water-based muds, through correct fluid design, are capable of preventing time-dependent instability in the shale. The methodology provides a pragmatic approach for managing shale instability problems in drilling extended reach wells in the Malay Basin as well as other regions worldwide. The approach would result in an increase in drilling efficiency and a reduction in drilling cost. Introduction A wide range of wellbore instability-related problems has been experienced in K-shale in the Malay Basin of Peninsular Malaysia, ranging from sloughing shale to tight hole (remedied by reaming) and stuck pipe, and a range of drilling fluid designs has been implemented. The instability may be induced by either in-situ stresses that are high relative to the strength of the formation (stress-induced) or physico-chemical interactions of the drilling fluid with the shale or a combination of both1–6. The dominant instability mechanism(s) is dependent on the properties of the shale, in-situ stress environment and drilling fluid system used. One of the most effective options for solving and managing the shale instability problems concerns drilling fluid design (weight, type and chemistry). A collaborative project between CSIRO Petroleum and PETRONAS Research &Scientific Services Sdn Bhd (PRSS) was conducted to address the problems for PETRONAS Carigali Sdn Bhd (PCSB). The aim is to develop a technical framework of drilling fluid design and consolidate into a methodology for overcoming wellbore instability-related problems in the shale. This paper describes the outline of the project and the approach adopted in the development of the methodology. The approach is based on drilling fluid-shale interaction and proven rock mechanics principles which include an extensive laboratory testing program on downhole core specifically cut for the study. In addition to mechanical (stress-induced) instability mechanisms, other key drilling fluid-shale interaction mechanisms, including mud pressure penetration and chemical potential mechanisms, were included in the study.