PGCE 2005

Depth realizations of reservoir surfaces was required for geocellular modeling of two fields in the MTJDA. In addition, a measure of uncertainty in depth was required. The method of this paper depth applied vertical stretch depth conversion and a primary velocity model that integrated well picks, seismic velocities and time-depth functions with surfaces. The velocity modeling process guided iterative improvement of the input interpretation data. Alternative velocity models were then created using different assumptions to capture variations in velocity interpolation. The largest uncertainties were identified in three plausible alternate models: with less smoothing of the seismic velocities; without seismic velocities; and with shallow gas effects modeled from seismic amplitudes.

Exploration activity in the East Balingian Sub-province (Figure 1) commenced in the 1960’s and resulted in a few discoveries which were predominately gas. Currently there are only two producing fields in this area, the Temana and West Patricia oil fields. In view of the relatively mature stage of exploration in the basin a new sequence stratigraphic scheme was needed in order to provide a detailed framework from which new play concepts could be identified by analysis of the key components of reservoir, seal and source. The present study has established a new practical sequence stratigraphic scheme for the East Balingian Subprovince that follows Vailian sequence stratigraphic principles. The Shell ‘Cycle’ stratigraphy (Ho, 1978 and van Borren et al., 1996) which has been commonly used in Sarawak was innovative for its time. It can be viewed as a forerunner to Galloway-style sequence tratigraphy, as it was largely based on biostratigraphically defined, shale prone marine flooding events. However, review of the Shell Cycles in the East Balingian wells indicates that they are not consistent with seismic correlations defined on modern 2D and 3D seismic. Shell has moved on from the Cycle nomenclature to a sequence stratigraphic approach and recently published the results of its internal study (Morrison & Lee, 2003).

The Middle Miocene Miri Formation records part of the infill of an estuarine valley system that was incised during an early Middle Miocene drop in sea level and subsequently infiled during a transgressive episode later in the Middle Miocene time. Around the Miri town in Sarawak, part of this incised valley succession is exposed and exhibit a wide range of siliciclastic lithofacies which reflect a variety of depositional settings. Three main depositional environments are recognised: tide dominated estuary, distal lower shoreface to offshore transition and s.horeface. The estuarine lithofacies association (FA:1) is characterized by distinct and diagnostic tidal signatures - tidal dune cross-bedding with mud draped cosets and forests including mud couplets, bidirectional (herringbone) cross-bedding, rhythmic stratifications, flaser bedding, wave bedding and lenticular bedding. Distal lower shoreface to offshore transition environment (FA:2A) is represented by interbedded laminated and bioturbated siltstone/sandstone, bioturbated siltstone and laminated mudstone/hummocky sandstone interbedding. Shoreface, storm-and-wave facies association (FA:2B) are represented by swaley cross-stratified sandstones, hummocky cross-stratified sandstones, bioturbated sandstones and associated mudstones. The tidal estuarine deposits form mix aggradational to retrogradational parasequence set, which represent the transgressive valley fills resulting from the establishment of an estuarine system (Early Transgrassive System Tract: E TST) (Figure). This stage (Stage I) represents the early phase of a significant relative sea-level rise, and possibly reflects a southward migration of the paleo Miri shoreline. This stage also characterized by great wave actions coinciding with abrupt sea level rising, which resulted in the deposition of several tempestites at estuary mouth. Stage II records the complete drowning event of the estuarine system, with the development of shallow marine settings (Late Transgressive System Tract: L TST), representing the final phase of transgrassive system tract. Parasequence sets of the transgressive system tract generally display clear, landward shift in facies trend. Shallow marine deposits in the studied rock succession overwhelms the estuarine deposits, displaying a retrograditional set of parasequence. The transgressive trend that started with the establishment of an estuarine system culminated with the deposition of offshore transition facies, which represents the maximum flooding surface (MFS). At the outcrops, this MFS marks the turnaround from retrograditional stacking pattern of TST to aggradational parasequences of HST. Stage III (Highstand System Tract) is represented by a well developed shoreface succession. This stage represents the upper portion of the exposed Miri Formation, which was possibly deposited during stable high and slowly falling sea-level. HST parasequence sets show an aggradational trend, formed during stable high sea-level, to progradational trend, formed during slowly falling sea-level. HST is predominantly composed of upper to middle shoreface deposits (swaley and thick hummocky cross stratified facies) that overlie MFS.

Whilst the parameterization of the acquisition phase of 4D (time lapse) seismic surveys has rapidly become well established, the complexities of the parameterization for the data processing stage are far less established. We discuss robust strategies for the planning, execution and quality control (QC) of 4D surveys. Several case examples demonstrate that
4D QC is the critical element of all stages of 4D projects. To be successful, 4D QC must be pursued as a seamless integration of all the project elements, ideally within a visualization system capable of interactive and "real time" dialogue with those project elements. If the QC
of the 4D acquisition is managed in real time it will be possible to isolate and address each acquisition contribution to the 4D reservoir signal during processing. If the QC of the 4D processing is managed in the same visualization system it will also be possible to isolate and address each processing contribution to the 4D reservoir signal, and it will be possible for project members from all disciplines to work effectively together. All elements of the final data product can then be completely understood, enabling the construction of quantitatively accurate and robust reservoir models for use in reservoir simulation and management projects.

The adoption of 3D seismic at the end of the last century dramatically improved drilling success. The annual spend by the hydrocarbon industry on seismic acquisition now exceeds $5 billion, and the resulting data are an integral part of risk management and drilling strategies. However, despite this the majority of exploration wells drilled globally are commercially unsuccessful. To make a significant improvement in exploration performance more prospects must be tested to avoid relinquishing productive acreage, including those prospects considered high risk (for example stratigraphic plays, which often have little or no seismic expression). There is therefore a pressing need for a non-invasive technology able to minimise the risk of drilling unsuccessful exploration wells by confirming (or otherwise) the presence of hydrocarbons prior to drilling. Controlled source electromagnetic imaging (CSEMI) does just that, by bridging the gap between traditional seismic exploration methods and drilling. Whilst seismic data identify the geological structures that may contain hydrocarbons, under many circumstances they do not reveal the presence of hydrocarbons themselves. The presence of hydrocarbons in a reservoir typically increases its electrical resistivity compared to the surrounding water saturated sediments by an order of magnitude or more. This property of hydrocarbon saturated reservoirs is commonly exploited well logging applications. However these methods require a borehole to be drilled. CSEMI provides a method of determining the resistivity within an identified prospect before drilling. CSEMI detects and delineates resistive sub-seafloor layers, which can be associated with hydrocarbons, and gives an indication of their spatial extent. If correctly applied, this means that the possibility of drilling dry exploration wells is significantly reduced, as is the need for extensive appraisal drilling.

CS Mutiara Petroleum is a PCSB-SEPM joint operating company. It is currently operating the PM301 and PM302 PSC. The theme of this paper is to share CSMP’s experience on how it conducted its exploration campaign (to date) to create value in a mature and highly creamed basin. Through a portfolio management approach with consistent volume, risk & value assessment, the following technical challenges were addressed: • Gas sand prediction (coal versus gas sand). • Low saturation versus low resistivity pay. • Shallow velocity layer impact on depth conversion. These challenges have significant impact on the acreage prospectivity & volumetric assessment. CSMP manage to apply “fit for purpose technology” such as application of simultaneous inversion, spectral decomposition techniques and use of open-hole mini DST to understand and to solve for these key challenges: • Based on the portfolio management approach and applying fit for purpose technology, a drilling sequence of the highest ranking prospects was carefully mapped out which resulted in drilling five successive commercial discoveries.
• An appraisal campaign is underway in anticipation of a fast track development with first gas targeted in 2009.

The North West Borneo deepwater fold and thrust belt still holds significant potential
for successful hydrocarbon exploration. Top seal analysis is a critical success factor, and seismic velocity based pore pressure prediction is a key ingredient of an integrated workflow
to study trap integrity and retention risk. Moreover, drilling high-pressure, high-temperature (HPHT), low drilling margin wells in a deepwater setting poses substantial HSE risks and significant financial exposure. Accurate pre-drill pore pressure and fracture gradient
evaluation combined with in-depth shallow hazards analysis leads to appropriate and costeffective well-design. Inflationary overpressures at crestal locations on ridges with little overburden, but potentially long connectivity into the basins pose a special challenge. A well
established procedure using results of regional rock property studies converts acoustic
velocities to vertical effective stress. Seismic interval velocities corrected for shale-related anisotropy effects and calibrated to check-shot velocities from the entire deepwater area yield
an initial idea about overpressure. Pressure sampling from past drilling activity shows that reservoirs on high-relief structures are often inflated relative to seismic-derived pressures, which is corrected for using the centroid approximation. During drilling, real-time monitoring and pressure prediction ahead of the bit contributes to timely adjustment of casing schemes and mud weights, whereas continued updates of pressure-vs-depth plots facilitates early
understanding of hydrocarbon column heights and volumetric scenario modeling. Case studies from recently drilled prospects in deepwater Sabah will be used to illustrate the concepts and workflows.

Accuracy in pore pressure prediction requires prior understanding of the formation of overpressure in the basin. This may be a challenging task as the generation of overpressure can be attributed to several geological processes, either increase in loading stress (compaction disequilibrium) or volume expansion, or combination of both. The most common cause is due to compaction disequilibrium, whereby the causal mechanism can be eadily verified if the porosity in the overpressured shales remains high (undercompacted). In many instances, the origins of overpressure are combination of several of these causes. In the Malay Basin variable pore pressure profiles are observed. Pore pressure profile is variable due to: (1) choice of methods (empirical or soil mechanics), (2) difficulties in selection of normal compaction trend, (3) multiple origins of overpressure, and (4) chemical ompaction effects. The variability of pressure profiles and log cross-plot trends found in the Malay Basin can also be observed in basins elsewhere in the world. Based on the pressure and wireline log analysis conducted for the Malay Basin, a flowchart has been developed to enable determination on overpressure origin in the basin. Overpressure resulting from disequilibrium compaction, fluid expansion, clay diagenesis, lateral transfer and chemical compaction can be recognized by a combination of prediction methods and well log signatures. Examples presented are taken from several overpressured basins around the world. The wider compaction trends observed in these basins are associated with variable sand and clay content, plus pure unloading signatures associated with fluid expansion mechanisms.

Shell’s deepwater portfolio in North West Borneo (NWB) is dominated by Miocene toe thrust anticlines. Although the prospects are broadly supported by direct hydrocarbon indicators (DHI) Quantitative Analysis does not discriminate low from full saturation hydrocarbon. In addition, seismic imaging is poor over some crestal areas, largely due to shallow gas and complex crestal faulting. Electromagnetic Seabed Logging (SBL) is a new technology that utilizes the Controlled Source Electro-Magnetic (CSEM) technique to detect and characterize HC-bearing layers within the subsurface. Modeling suggests that the method is insensitive to low saturated hydrocarbon and has the potential as a tool to de-risk or high-grade prospects in an exploration portfolio. In 2002, a global deployment and implementation plan was exercised for the technology in exploration. In 2004, Shell acquired the region’s first SBL data over 7 prospects in the North-West Borneo Block G and J. Over 350km of EM data was acquired over the prospects within the agreed 30 days of operation. Operational learnings were in abundance, with sliding receivers on the seafloor and potential source-entanglement with submarine cables being included as some of the operational challenges. SBL data was also acquired over the then Malikai-A well. With a processing turn-around time of about a week, the SBL data has positively identified the HC accumulation in the structure, which was proven later with the well and the oil discovery. This result has driven Shell to further utilize this new
exploration technique in the region to accelerate exploration and improve drilling success.