- Home
- Conferences
- Conference Proceedings
- Conferences
PGCE 2010
- Conference date: 29 Mar 2010 - 30 Mar 2010
- Location: Kuala Lumpur, Malaysia
- Published: 29 March 2010
41 - 60 of 100 results
-
-
Successful Application of Thin Bed Petrophysical Evaluation Workflow in Deep-Water Turbidite Environment: Case Studies from Fields Offshore Malaysia
As the demand for energy increases, oil companies are moving further offshore in their search for hydrocarbons in previously untouched deepwater reservoirs. In a deepwater turbidite depositional environment, high net to gross reservoirs are often overlain by a significant thickness of low net to gross sandshale sequences. While conventional formation evaluation, performed using standard resolution logs, is sufficient to characterize the thick high net to gross beds, it tends to underestimate and often fails to realize the
true potential of the low net to gross thinly bedded intervals. These thin bed packages, by themselves, can contain significant amount of hydrocarbon. Clearly an alternative method of evaluating log data in thinly bedded reservoirs is required for accurate assessment prior to commercialization. This paper presents case studies from several deepwater turbidite fields offshore Malaysia, where a thin bed petrophysical evaluation workflow has been successfully applied. The study was conducted as part of an integrated study to improve understanding of thin bed potential in terms of its distribution, lateral continuity and production capacity. The thin bed petrophysical evaluation workflow starts with a conventional formation evaluation; followed by constrained log-resolution enhancement processing; an enhanced resolution formation evaluation; cutoff selection for pay determination; and ends with core and formation tests calibration and validation. The results from the conventional and thin bed evaluation are compared to and validated by: core photographs; core x-ray diffraction analysis (XRD); routine core analysis of porosity, permeability and saturation; and formation test data. This paper concludes by highlighting some of the important advantages of using the thin bed
petrophysical evaluation workflow proposed, these include general and specific observations on: net to gross; saturation; volume of clay; porosity; and permeability. Finally recommendations are made suggesting logging programs to obtain optimal results from this thin bed petrophysical evaluation technique. Overall, this paper hopes to serve as one of main references for thin bed petrophysical evaluation in similar environment.
-
-
-
Stratigraphic Architecture and Process Variability of the Transgressive Paralic Cycle II (Early Miocene) Interval, D35 Field, Balingian Province, Offshore Sarawak
More LessDetailed and integrated core analysis (physical sedimentology, ichnology and biostratigraphy) and extensive well log calibration and correlation of over 70 wells (exploration & sidetrack), constrained by seismically-defined surfaces, reveal an intricate stratigraphic architecture of the Cycle II (Early Miocene) section of the D35 Field, constructed from coastal and marginal-marine depositional intervals. The overall architecture reflects a complex interplay and variability of sediment supply, relative sea level changes and depositional processes. Three major stratigraphic intervals are defined by lithofacies characteristics and fieldwide stratigraphic surfaces. The lowermost Interval I is defined by a field-wide basal erosional surface which partly truncates a correlatable coal-capped paleosol horizon in places, and overlies a prominent condensed section. The erosional surface is interpreted as a sequence boundary; it marks a significant fall of relative sea level across the field. The surface is overlain by a thick interval (> 100 ft) of sand-rich progradational unit; it is dominated by cross-bedded sandstones and pebbly-sandstones, which are interpreted to represent a coastal mouthbar complex, which in places are channelised. These cross-bedded sandbodies are interbedded in places with brackish, bioturbated (with several Glossifungites intervals) and wavy-to-irregularly laminated tide-influenced sandstones, indicating that the mouthbar complex is in contact with a brackish water body, and is affected by intermittent marine flooding. This interval is the distal, Lowstand System Tract. A major flooding surface, correlatable across the field, separates the Lowstand Interval I from the overlying Early-to-Middle Transgressive Interval II. This comprises aggradational-to-retrogradational units of laminated-to-massive, brackish estuarine mudstones, interbedded with tidal flat and minor bay head delta sandstones, often capped with minor coals and paleosol horizons. The stratigraphic and cyclic stacking of brackish mudstones-paleosol-coal facies association signals recurring marine flooding and land progradation throughout the deposition of Interval II, with minimal sand input. The Late Transgressive Interval III is characteristically marked by the dissappearence of coal-capped parasequences, and the domination of thick brackish estuarine mudstone. It is distinguish from the E-TST in many wells by the last coal before thick mudstone interval. A Maximum Flooding Surface separates the L-TST from the Highstand System Tract (HST). This is marked by the return of the coastal and estuarine margin, coal-capped parasequence set. The HST here is thin and poorly developed, or has been eroded by the subsequent fall in relative sea level, which forms the upper bounding surface for Cycle II and the Sequence Boundary for Cycle III. This truncation surface marks the end Cycle II.
-
-
-
Deepwater Thin-Bed Depositional Settings : A Geological Framework from NW Sabah
More LessDeepwater clastic depositional systems can have various thin-bedded depositional elements from a variety of settings. A systematic geological observation and classification using image-logs, cores and conventional/ sharpened logs, from the K Field, NW Sabah Province has been performed in this study. The thin-bedded deposits were looked at to assign depositional settings which could be one of several environments like proximal and distal levee, passive channel-fills and distal sheets. Available core demonstrates visible sedimentological characteristics like grain-size variations and trends, nature of bedding contacts, bedding-density and trends, sedimentary structures and post-depositional imprint. These observations when integrated with log and borehole-image response, at various scales, allow for a geological framework of thin-bed groups within the study area. The thin-bedded intervals typically lack the Bouma Ta division and commonly comprise of the parallely laminated Tb and rippled Tc divisions along with ome Td-e divisions, in combination or in isolation. The occurrence of these sedimentary beds in association with other features like mud-clasts, convolute-bedding, and climbing-ripples is indicative of the affinity of these beds to belong to one thin-bed depositional setting versus another. Core-based observations when calibrated against OBMI image-logs become a strong geological tool to help propagate validated observations into other wells or uncored intervals, where only image and log data is available. With these fine-scale observations it has been possible to package thin-bedded zones into genetic units at a coarser scale. These units are bound by surfaces that show distinctive breaks in well-log signatures and are potential strong reflectors in the seismic domain. It is possible to generate a model that predicts the stacking of these genetic units which are related to the cyclical depositional style in deepwater settings, primarily driven by relative sea-level fluctuations. A commonly observed cycle of deposition in deepwater during one lowstand cycle starts with mass transport deposits (MTD) at a sequence boundary, overlain successively by thickly-bedded good quality sheet sands followed upward by channel-levee-overbank complex capped by a condensed section (Fig. 1). In the K Field area this cycle is clearly seen. Mass transport complexes (MTDs - thickness range ~30-100m) are overlain by thick-bedded well developed massive sands (ThkSstn - thickness range 10-30m) which is followed upward by thinly-laminated sand-shale heterolithic package (thin bedded turbidites, TBT - thickness range 30- 100m) with variable net:gross (Fig. 2). H43 H86 Accommodation space in the toe-of-slope and proximal basin-plain controls facies distribution and architecture. Sea-floor radient, sea-floor mobility and rugosity, sedimentary budget and volume, net:gross in the system controls the type and distribution of accommodation space (Prather, 2001). In the K Field area local sea-floor rugosity is created by deposition of MTDs during early lowstand, which leaves an uneven depositional plain on the sea-floor. Following this event, typically a sheet-like well-developed sand unit is laid down which partially ponds the local sea-floor rugosity in the form of thickly-bedded sand packages, i.e. ThkSstn. Thereafter a graded to nearly graded system takes over, during which a channel-levee overbank complex forms which deposits thin-bedded turbidites, the TBTs (Fig. 2b and Fig. 3). This system is somewhere between the two extremes of a graded basin-plain setting and a successive fill-and-spill slope minibasin. Another category of sea-floor topography other than rugosity created by MTDs, albeit at a much slower but bigger scale, is attributed to active tectonic compression of the basin and the creation of toe-thrusts and the associated relief. The effect of this tectonic imprint on the sea-floor and hence on the depositional architecture is not very clear on the reservoirs of interest in the K Field area. The thinly-bedded (TBT) packages have been observed to represent two classes, one is high net:gross sand-shale package and the other is a low net:gross sand-shale package. Both classes are inferred to represent levee-overbank complexes, with the former being proximal levees and latter distal levees. The sedimentary characteristics that support the thinly-bedded deposits to be levee-overbank deposits are as follows: • interbedded sand and shale package, occurring as heteroliths (in analogy with modern observations) • consistent, parallel stratigraphic dips without much variance (Fig. 2a), unlike the other units especially MTDs • parallel-laminated to ripple cross-laminated sands and climbing ripple cross-laminations having mostly Bouma Tb-Tc-Td units (Fig. 3) • rip-up mud-clasts • convolute lamination. The sedimentary attributes mentioned above are not all common in all the thin-bedded intervals but they are typically observed and are presented here in order of importance. The occurrence of thin-bedded turbidite sections within a lowstand cycle of deepwater deposits hold a
key for facies modeling, determination of depositional architecture leading to reservoir simulation and producibility estimates. Due to lack of good quality seismic, affected by shallow gas cloud effects, geobody xpressions are not always clear and high-resolution observations like image and core should be employed for reducing uncertainty in facies analysis.
-
-
-
The Major Trends of Palynomorphs Distribution in Three Fluvial Systems, Peninsular Malaysia
More LessThree fluvial systems on the west and east coast of Peninsular Malaysia were assessed in term of their palynomorphs distribution pattern. They were chosen on the basis of their contrasting depositional setting, accessibility, availability of supporting published data and extent of disturbance by development. The one on the west coast is tidal-dominated Klang-Langat River. The other two rivers are located on the east coast. The first one is Pahang River which is characterized by a huge sediment output and located on a wave-dominated coastline. The other is Sedili Besar River which also debouches into a wave-dominated coastline but with low sediment output. The study was conducted on 352 sea bed and river bottom sediment samples that were collected between April to December, 2007. Samples were processed using a standard palynology preparation technique and ‘spiked ‘ with Lycopodium tablet which allow estimation of the absolute pollen abundance. The data for mangrove and hinterland pollen are evaluated and presented separately, each as pie chart diagrams that depicts the relative abundance of palynomorph in broad ecological groups. For mangrove, the ecological groups are Rhizophora , back mangrove, Acrostichum and Nypa, while the hinterland pollen groups are freshwater, riparian, peat swamp, coastal, seasonal, kerapah and temperate. The trends indicate that pollen grains and spores, are widely distributed by mainly water currents and to lesser extent by wind. Overall, palynology tells us less about the local environment, but more about the nature of the local or regional landscape. Mangrove pollen from the coastal plain is transported upstream up to the upper reach of the tidal limit and downstream with the dominant stream flow, out to the sea. As a result, sediments in the offshore area contain pollen signals which approximately mirror the main vegetation character onshore. Pollen from the river sources may not travel far beyond the offshore as shown by a drastic decrease in pollen abundance in the offshore area. It appears that, in the offshore area pollen could have originated from other places and carried via tidal current and that they reflect the vegetation in those areas. Rhizophora group is more common in the west coast, reflecting the broader lower coastal plain and dominance of tidal influence. Away from the pollen source on both coastlines, the pollen abundance gradually decreases, demonstrating the effect of pollen dispersal by wave and tidal current. The hinterland pollen reflects the broader aspects of the landscape. This is indicated by the dominance of alluvial swamp pollen as opposed to peat swamp. The effect of ecological disturbances by development and plantation is also clearly observed in pollen distribution pattern.
-
-
-
Hydraulic Top Seal Failure – The Relationship Between High Pore Pressure and Hydrocarbon Preservation in Hp/Ht Regions
As drilling worldwide aims for deeper targets, particularly in High Pressure/High Temperature (HP/HT) conditions such as experienced in the Malay Basin, (e.g. Bergading Deep, Sepat Deep and Gulin and Deep-1 wells), top-seal failure represents a high risk due to reservoir pressures close to the fracture pressure. A new methodology has been developed to analyse hydraulic failure as part of the risking strategy for prospects in these HP/HT regions. Part of the risking strategy for prospects is an assessment of seal breach risk at top reservoir, i.e. when the seal may be breached by high pore fluid pressures causing hydraulic fractures in the top-seal. Prediction of seal breach through hydraulic failure involves pore fluid pressures reaching or exceeding the minimum stress plus the tensile strength of the seal rock. In a water-wet reservoir, the buoyancy pressure in the hydrocarbon phase is considered to have a minor influence on rock behaviour and hydraulic failure is most closely linked to aquifer pressure. It is therefore necessary to study both the aquifer and hydrocarbon seal capacity in order to assess seal breach risk. To assess seal integrity requires data to define pore fluid and fracture pressures. Fracture pressures and gradients can be derived from analysis of Leak-Off
Test data (LOT), which can be compared with fluid pressures, derived from direct pressure measurements such as, RFT, FMT and MDT data, to analyse minimum effective stress and seal breach capacity (Figure 1). In some basins data show that the overburden can be the least stress, particularly where derivation of overburden from density data has been done. Accurate derivation of a predictive fracture pressure algorithm should include a pore pressure/stress coupling ratio term (which relates pore fluid pressure to horizontal stress magnitude through poroelastic fluid-stress interaction). Sense would dictate that the smaller the seal capacity at top reservoir, i.e. the closer the pore pressures are to the fracture strength of the rock, the greater likelihood of loss of hydrocarbons via fractures. This relationship observed from examination of high pressure wells from the Central North Sea. Using hydrocarbon seal capacity has minimal impact on the delination of dry holes and discoveries (or certainly not with regard to the column lengths present in the studied wells). A similar relationship between pore pressure, least stress and preservation of hydrocarbons is observed in the Scotian Shelf, (Bell, 1999). In the Central North Sea example, analysis of aquifer seal capacity has been onducted at top reservoir, and also at two stratigraphic horizons within the overlying top seal. The most convincing empirical relationship is within the top-seal where, using a cut-off of 50 MPa (750 psi), and a dataset of 66 wells, 88% discoveries of the wells are discoveries in excess of the cut-off. Below the cut-off are a series of dry holes and some discoveries which are non-commercial (Figure 2). In other HP/HT basins such as Mid-Norway, Halten Terrace there is no clear relationship between seal capacity and hydrocarbon preservation, either at top reservoir or at shallower levels in the seal. The implication here are that in the Viking Graben and Mid-Norway regions, other (or additional to pressure) factors exist influencing top-seal failure. These controls are likely linked to difference crustal stresses, with the direction of maximum horizontal stress varying in relation to fault strike, for instance, in each of these areas. Crustal stresses are potentially a combination of ice-loading, isostatic rebound of the crust and rapid
sediment loading in the Plio-Pleistocene. Other factors such as top-sea lithology and thickness are also considered, therefore, to have an impact in hydrocarbon preservation. Also that hydrocarbon pressures do not strongly influence hydraulic seal failure, rather, water pressure exerts the main control. This paper will present the workflow which have been has been established in these studies, and how they can be applied to aid the de-risking of high pressure traps in areas such as the Malay and other SE Asia
Basins.
-
-
-
Cyclic Transgressive and Regressive Sequences During Cretaceous Time, Northern Zelten Platform, Sirt Basin, Libya
More LessTwo marines Transgressive and regressive cycles are recognized during the Cretaceous time, one is represented during Early Cretaceous, when the Sirt area was still an arch. In this cycle, the sedimentation had only taken place on the line base of the arch. The Jurassic sediments partially transgressed the arch but had their depositional edge on the flank of the arch. The other cycle is represented after the northern Tibesti-Sirt uplift collapsed in the beginning of the Early Upper Cretaceous and during the Upper Cretaceous (Campanian) time. The Maestrichtian Sea encroached from the North and further to design the first flooding surface in the area. Thick of dark grey shale (Sirt Shale) followed by deposition of shallowing upward regressive carbonate of the Kalash Formation were deposited in the troughs. The Sirt shale acts as both a seal and source rocks for hydrocarbons trapped in the Cretaceous reservoirs and underlying the Cambro-Ordovician Gargaf Sandstone. The Upper Cretaceous formations are Bahi, Sirt, and Kalash in ascending order. The top of the Kalash Limestone marks the Maestrichtian/ Danian boundary in the study area.
-
-
-
The Use and Methodology of Logging While Drilling Nuclear Magnetic Resonance for Enhanced Evaluation of a Complex Lithology Formation in a South East Asia Offshore Basin
More LessThere are inherent difficulties in obtaining an accurate economic reservoir evaluation in complex clastic lithology environments typical of the offshore sedimentary basins found in South East Asia. Often such an evaluation requires a comprehensive suite of wireline logs to be run. However the target lithologies in these basins can deteriorate quickly, leaving a borehole in poor and unstable condition, which presents clear risks to a wireline operation; in terms of success and data quality. The use of conventional LWD triple combo logs of Gamma-Resistivity-Neutron-Density could be an alternative evaluation solution. However the Gamma, Neutron and Density logs are lithology\mineralogy dependent measurements and various borehole environmental corrections are needed for accurate results. Uncertainties in grain density, mineralogy, clay content, particle size distribution and the unknown properties of both in situ and invaded fluids make accurate volumetric calculations difficult, while poor borehole conditions or excessive invasion further complicate the matter. Both Neutron and Density logs are limited to total porosity estimations and different assumptions, relying on local knowledge or expensive coring and laboratory tests, to accurately define the formation
porosity. Not only can Nuclear Magnetic Resonance measurements resolve uncertainties in formation porosity. In addition, they provide information on porosity components as clay, capillary bound and movable that are vital in yielding the quantitative estimations of formation productivity. In the LWD environment, the Nuclear Magnetic Resonance measurement is acquired not long after the formation is drilled, when least borehole damage has occurred and invasion is minimal, thus maintaining a high level of data quality. The Nuclear Magnetic Resonance (MagTrak) tool has a low magnetic gradient design that enables quality Nuclear Magnetic Resonance measurements under dynamic drilling conditions. The tool has been designed to have minimal impact on the drilling operations and can be programmed for multiple acquisition modes that can be changed down hole by “down-linking” surface commands. Though full memory data for detailed analysis and provision of a T2 distribution spectrum is available after the tool run, the tool can provide T2 spectral data in real time. Additionally, the tool does not contain any radioactive sources, making it a safe and green alternative to LWD porosity measurements that require radioactive sources. This paper describes how the logging while drilling Nuclear Magnetic Resonance tool was used to log a complex lithology in an offshore South East Asian well to determine accurate lithology\mineralogyindependent porosities and how the measurement provided additional valuable petrophysical parameters such clay volume, pore size distribution, irreducible water saturation as well as information on moveable fluids and an estimate of permeability. Further, we discuss the methods used on the logging while drilling data to refine
the conventional petrophysical analysis of the formation and how the Nuclear Magnetic Resonance data was used to provide an estimate of the productivity of the reservoirs in question.
-
-
-
3D Seismic Acquisition for Hp-Ht Exploration of Block Pm303: Technical and Hse Issues
Authors Patrick Ravaut and Jaflis Jaafar and Emilie RenouxTOTAL E&P Malaysia (TEPMY) is operator of Peninsula Malaysia Production Sharing Contract PM303 and PM324 since May 22nd 2008. TEPMY and his partner PCSB performed a 1650 sq.km Full Fold 3D seismic survey over the western part of the block PM303 in May-June 2009 with the CGGAlize vessel. The aim of this paper is to present preparation and efficiency of this very successful operation both technically and on HSE aspects. As first acquisition operation in Peninsula Malaysia dedicated for deeply buried HP/HT targets, TEPMY had a special care in both geophysical feasibility study and environmental/social issues. Geophysical parameters definition started in TOTAL HQ in France in July 2008 and was mainly based on in-house re-processing of existing 2D seismic data and first interpretation of 2D data on this area. Main outcome were: - Survey design with long acquisition lines dedicated to cover main prospective areas but also to reduce line-change time and then cost, - Source and streamer depth deep enough to optimize Low Frequencies content for deep targets, - Streamer geometry: 8 to 10 of 6000m long to get far offset deep enough, - Recording length of 9s TWT in order to obtain a full image of the basin to understand pressure distribution at a semi-regional scale in an HP/HT domain. The Call-For-Tender was launched in December 2008 using TOTAL SA Standard contract. CGGVeritas was awarded the acquisition contract in early May 2009 with CGGAlize vessel in a 10 streamers configuration.
Environmental and Social Impact Assessment study was done by Environment Resources Management (ERM) as a TOTAL SA standard. Impact on fishing activity was the main result of this study as many fish-traps exist on the area and will have to be removed to perform safely the seismic acquisition. Recommendation was to communicate on the seismic survey with Local Authorities and Fisheries long enough before the starting date. But also considering having a Fishing Liaison Officer and fishermen
representatives onboard Chase Vessels before and during the seismic 3D acquisition. After meetings and discussions with Local authorities and fisheries, PCSB and other experienced operators, TEPMY and CGGVeritas decided to perform a fish-trap survey prior to shoot the 3D seismic. Five weeks before the anticipated start of the survey the first phase of the fish-trap survey was launched. First phase was dedicated to identify and tag existing fish-trap within the Safe Navigation Area (SNA). More than 100 fish-traps have been identified and tagged. At the same time flyer in different languages (Bahasa Malaysia, English, Thai and Vietnamese) were produced and distributed to a maximum of fishermen. The Indah-3D Seismic Survey started on the 20th of May with a total of 8 vessels: CGGAlize, Supply boat (Main Port Oak) and 6 chase vessels with more than 130 people onboard. Full acquisition last only 5 weeks with an average daily production of 60sq.km. TEPMY had 3 representatives onboard the CGGAlize: 1 geophysical supervisor, 1 navigation supervisor, 1 Marine Mammal Observer - who was also TOTAL HSE Rep on-board -, 2 Fishing Liaison officers onboard Chase-Vessels and 1 full-time experienced operation geophysicist in TEPMY office, for the survey follow-up. We also performed an Audit/Start-up mission at beginning of the survey with TOTAL HQ specialists during the full first week of the project. On more than 70,000 man-hours no LTI has been recorded and only 1 Medical Treatment Case occurred during a safety drill. In order to minimize impact on fishing activities the removal of fish-trap was done independently on each of the three Swaths. No problem was encountered with fishermen during the project. The project recorded only 59 hours of stand-by and 50 hours of down-time. 34 hours of stand-by time are related to 1 fish-trap in part of a streamer and down-time to small propellers problem. The acquisition operation is considered very successful thanks to: A good preparation, involving all parties, a good supervision, a good management of fishing activity, a good production of the CGGAlize, achieving a Job Efficiency of 93.3%.
-
-
-
Logging While Drilling Images Provide Feature Recognition as an Aid to Evaluation of a Fractured Granite Basement Reservoir
More LessThe evaluation of unconventional reservoirs, such as fractured granites, has become more important as the more common sedimentary reserves become harder to find. In Vietnam the majority of the country’s hydrocarbon production comes from fractured granite basement, making evaluation of this reservoir type an essential part of the country’s hydrocarbon exploration programme. Much work has been done on finding the best methods to appraise and quantify these reservoirs, as more traditional logging methods, primarily developed for sedimentary basins, are unable to fully characterize their unique petrophysical properties, due to uniformly high resistivity, very low matrix porosites, and widely ranging neutron and density measurements. The key to a full evaluation appears to be the measuring and mapping of natural fractures, and determining which of these are critically stressed; as it has been found that these are the main source of commercial pay. High resolution borehole images are ideally suited for this task, as they not only serve to identify natural fracture orientation, but also provide the most valuable, if not only, information on local stress directions. This paper discusses the use of a high resolution Logging While Drilling (LWD) electrical imaging tool as an aid to evaluating a Vietnam granite basement reservoir. The image produced was used as the reference for a fracture characterization study, in order to identify and map natural and drilling induced fractures. The identified fractures were used as input for a geomechanical analysis, including calculation of local stress directions. The two studies were then combined with recommendations on the preferred drilling trajectory to intersect natural fractures likely to be conduits to fluid flow, and examine any possible additional benefits from utilizing a high resolution LWD image in evaluation of fractured granite basement.
-
-
-
An Insight into the Tectonic Framework and Structural Evolution of a Frontier Area in Sarawak Offshore Basin, Malaysia
More LessTectonic framework and structural evolution controls the sedimentation of petroleum system elements in a basin. The present study integrates the results of offset well analysis, regional seismic mapping, and gravity modeling, to bring out a better understanding of the tectonic framework and structural evolution of a frontier area in offshore Sarawak basin. Regional depth structure and isochron maps based on reprocessed 2D seismic data were analyzed to characterize the structural fabric of the study area. Depth structure map at basement top reveals a strong overprint of the reactivated, NW-SE to N-S younger trend, over a less distinct NE-SW older trend, especially in the eastern half of the study area. The NW-SE trend is consistent with the regional lineation and the
basement high features, interpreted on regional Bouger gravity anomaly maps. The basement map, output from 3D inversion of free air gravity data over the study area, also corroborates these structural elements. Four distinct structural high axes, designated Trend1 to 4, aligned NW-SE to N-S, have been identified in the eastern half of the study area, on depth structure maps at Middle Miocene Unconformity (MMU), and Base Pleistocene levels. Trend 1 towards west, is aligned along the West Balingian line, a
regional strike slip zone recognized in the shallower part of this basin. West of this zone, no significant tectonic elements have been observed, other than the NE-SW trending faults, resulting from an earlier phase of extension. The other three structural high axes identified are located between Trend 1 to the west, and the West Baram line to the east. The alignment of the structural high axes along older basement trends, suggests basement involved structuring related to wrench tectonics. Isochrons of post MMU sequences indicate a progressive shift in the timing of wrench activity, from Late Early Miocene (?) towards west at Trend 1, to Recent towards east at Trend 4. Further studies are required to explain the causative mechanism. The study has helped in understanding the timing of the structures with respect to hydrocarbon migration, and has a direct bearing on the hydrocarbon prospectivity of the study area.
-
-
-
3D Prestack Depth Migration with Compensation for Frequency Dependent Absorption and Dispersion
Spatial variations in the transmission properties of the overburden cause seismic amplitude attenuation, wavelet phase distortion and seismic resolution reduction on deeper horizons. This poses problems for the seismic interpretation, tying of migration images with well-log data and AVO analysis. We developed a prestack depth Q migration approach to compensate for the frequency dependent dissipation effects in the migration process. A 3D tomographic amplitude inversion approach may be used for the
estimation of absorption model. Examples show that the method can mitigate these frequency dependent dissipation effects caused by transmission anomalies and should be considered as one of the processes for amplitude preserving processing that is important for AVO analysis when transmission anomalies are present.
-
-
-
InnoExtm - Innovative Exploration Concept
More LessGeosat Technology has developed InnoExTM, an integrated exploration approach. The underlying principle is to use various exploration technologies in order to maximize the exploration accuracy and to reduce exploration and subsequent development costs and risks: The InnoExTM key phases are: 1. Phase 1 :GEOSAT remote sensing analysis: three(3) independent methods are used to define hydrocarbon prospects :
• Structural lineament analysis: Systematic search for linear objects through an automated process -
computer program (SLARD)
• Analysis of thermal infrared images
• Spectral analysis: Analysis of multi-spectral space images for the survey of hydrocarbon deposits are
connected with the determination of specific anomalies of spectral brightness. Specific anomalies are
caused by up-streaming fluxes of water and gases that affect the temperature of the field.
• Additional available data will be incorporated:
o Geological data
o Lithological data
o Geophysical data
Basic principle is the determination of structures which have an active hydrocarbon system. These active hydrocarbon systems can be detected via the quantification of micro-seepage on the surface with its various characteristics. After the data selection, and data processing, the results of the three(3) independent methodologies are superimposed and interpreted and special hydrocarbon assessment maps created. Scope of phase 1 is to identify prospective hydrocarbon areas that should be further analyzed. By this approach areas for further ground evaluation and exploration can be reduced to 10-15% of the initial survey size. Hence the high graded prospective areas thereby identified qualify for additional ground works that are subsequently effectuated through phase 2 of our InnoEx approach: The application of 5 non-seismic methods over the high graded areas determined through phase 1: 2. Micro-Biological and Geochemical method (MBGE) (ground work): known as Microbial Oil Survey Technique 3. High Resolution Ground Magnetics (HRGM) (ground work) testing for distinctive magnetic signatures of hydrocarbon reservoirs. 4. High Resolution Ground Gravity (HRGG) 5. Magneto Telluric (MT) (ground work) for measuring low frequency currents in the Earth’s crust and
determining the type of sub-surface structure encountered: minerals, petroleum reservoirs, geothermal fields, ground water, etc. 6. High Resolution Geo Electrochemical (HRGC) (ground work) to determine the exact drilling point of oil and gas prospects detecting the metallic ion anomaly of the surface (High Resolution Geochemistry) All ground works are carried out in cooperation with companies specialized in this field. The data collected is then processed. Currently Geosat is developing a specific software to enable the combined analysis of the data from the different key phases. Based on the results of the Geosat study and the complementary non-seismic ground work the seismic acquisition program will be carried out over the predefined areas with an already proven active hydrocarbon system. The result of this analysis concept is a highly cost effective method that combines data from various independent exploration technologies to complement the seismic methods, fine tuning the interpretation and making the drilling and testing stage more accurate and focused. The variables and their interpretation (weighting etc.) can be easily adapted to the changing circumstances; the multifaceted technological approach guarantees a higher accuracy and increasing exploration success quotes. The result of this EXPLORATION concept is a highly cost effective method that combines data from various independent exploration technologies to complement the interpretation of the acquired seismic data and making the drilling stage more accurate and focused. This technological approach guarantees a higher accuracy and is increasing exploration success rates substantially.
-
-
-
Performance of Horizontal Wells of Bentiu-3B Sandstone Reservoir of Greater Bamboo Field (Block-2, Sudan) in View of Very High Viscosity of Oil and Profile of the Horizontal Wells – Case Study
Authors Kush Raj Keshari Singh and Elamin SulimanApproximately 100 mmbbl 2P OIIP has been established in Bentiu 3B sub layer of Greater bamboo fields by various exploratotory, appraisal and Development drilling. The vertical variation in viscosity viscosity from Bentiu 1A to Bentiu 3B has been the challenge for the exploitation of established reserve by conventional wells. The exploitation strategies in Greater Bamboo Fields were conceptualized to develop the Bentiu-1 and Bentiu-3 layers separately in view of high viscosity contrast. A number of horizontal wells have been drilled to optimally exploit particularly high viscous Bentiu- 3B reservoir. Since the viscosity of the Bentiu-3B reservoir is extremely high it was decided to carry out performance study of some key wells completed as horizontal well. An attempt is made to analyse the performance of these key well completed in highly viscous oil bearing Bentiu-3B sub layer and its relation to the Horizontal well profile, proximity to the Oil Water contact, Reservoir quality in the Horizontal well, Shale layers within the Horizontal well, and the fault as well as edge water in the proximity. The paper discusses the technical details of four cases of which two wells belong to each Bamboo West and Bamboo Main fields. In the Bamboo West both the wells has been analysed in detail and it has been found that in one well the TVD was gained more resulting to the proximity to the OWC whereas the other well was planned at the edge of the structure and close to OWC and fault. In the Bamboo Main one well has been drilled in zig zag profile which has no reason based on the all available data analysed. This type of horizontal wells, although planned suitably, if not drilled perfectly result in the poor performing well. The option of sidetracking could have been better option and saved the well from disaster. The other well drilled had poor data control from the nearby well. The well trajectory was planned up dip but when drilled, initially the trajectory was up dip later become down dip. The performances of the horizontal well are greatly affected by the drain whole profile in the exploitation of high viscous oil. If the profile of the Horizontal well is maintained as gaining TVD profile i.e. down dip profile the tendency of the water to move up will be relatively lowered. This has been observed in the analysed horizontal well but their proximity to the OWC has made them more water prone. The horizontal wells drilled with Zig Zag profile, even at the best place of structure are the poor performer whereas the wells with up dip (loosing TVD Profile) may perform initially better due the structural advantage but they are susceptible for water hold up and ceased production. The paper recommends various processes and way forward to drill horizontal wells and exploit this high viscous oil of not only Bentiu-3B but also similar reservoirs.
-
-
-
Passive Seismic Tomography: A New Era for Hydrocarbon Exploration
More LessPassive seismic plays an important role in the investigation of the interior structure of the Earth. Passive seismic is a 3-D seismic imaging of the target geology without using artificial surface sources. It uses multi-component seismic receivers to take advantage of shear wave energy generated by the microearthquakes thereby delivering a shear wave (Vs) velocity distribution estimate of the subsurface in addition to the conventional compressional (Vp) image. Recently, the passive seismic tomography surveys became an essential tool for the oil industry and modern reservoir management. The passive seismic technology is applied to investigate the relatively shallow depths that lie in hydrocarbon exploration window. In addition, some of the problems that are encountered in the conventional seismic explorations, for example salt domes effects, are solved using this technique. Passive Seismic Method constitutes the passive seismic transmission tomography in which 3-D images are created using the observed travel time of seismic signals originating from micro-earthquakes occurring below the target; and passive seismic emission tomography where the micro-seismic activity itself becomes the imaging target. The most straight-forward approach is to observe and record the direct arrivals of the seismic waves from these events and to map the distribution of hypocenter locations. Passive seismic technology, as an imaging and processing technique, challenges the following issues:
1. Identification of anisotropic flow and well targeting.
2. Determination of the three-dimensional VP and VP/VS velocity structure.
3. Analyzing the seismicity.
4. Getting under salt formations.
5. Description of the deformation processes of the reservoir.
6. Delineation of leaky fault structures, mapping active and conductive fractures of faults, at an
intermediate scale between borehole imaging and 3-D seismic imaging.
7. Predictive reservoir models thus Reducing uncertainty.
The Gulf of Suez, Egypt, is characterized by its high hydrocarbon potentialities where most of Egypt oil production comes from. The basic problems in exploration at the Gulf of Suez come from its complex geologic structural setting as well as the presence of anhydrites that mask the structures below. Therefore, Passive seismic transmission tomography (PSTT) creates 3-D images using the observed travel time of seismic signals originating from micro-earthquakes occurring below the so masked structures. The cost/benefit justification of 3D seismic applies to Passive Seismic. Deeper pool tests drilled with this coverage will have a much higher success rate. Coverage will provide risk-reducing information content. For example: new interpretation could prevent drilling of unsuccessful step-out wells ($1 MM savings per well). Additionally, PSTT may be the only viable seismic option for certain areas. One of the most important parts of the passive tomography investigation is the quality control of the results. This can be done using many different procedures and their correlation can lead to safe conclusions about the resolution power of the dataset and therefore the quality of the tomographic inversion results. The method used does not only verify the estimation of their accuracy, but also points out the areas of higher and lower analysis precision, thus making it easier to control the interpretation of the results. This paper represents the passive seismic technology as an alternative to the conventional seismic exploration for delineating the structures that are masked by salt domes and Anhydrites in the Gulf of Suez and other regions, as well.
-
-
-
Depth Trending – Predicting AVO Variability with Depth
Authors B. Hardy and H. Morris and O. PakpahanIn the quest for finding hydrocarbon reserves we continue to push into the deeper waters whilst looking at stacked reservoirs of deeper prospects. With increasing cost of wells we need to attempt to increase our confidence in the understanding of rock properties and the expected seismic signatures. Depth trending is a technique that uses our understanding of the rock physics and depth dependent behaviours gained at the wells and applies this throughout the seismic cube. Differential compaction behaviour of sand and shale lead to differing depth trends in these two lithologies. Understanding the cross-over point in acoustic impedance for these two lithologies is critical in predicting the AVO response. Depth trending allows us to predict the Vp, Vs and Rho trends of differing lithologies and gain an understanding of cross over points. This knowledge can be used to extrapolate our well data both horizontally and, more importantly, vertically which allows us to make predictions for AVO response at basin scales for plays deeper than current drilling. With the use of various data population techniques, reasonable predictions can be made even in areas with a low amount of wells. In this paper we describe a ‘best practice’ method for depth trending, including fluid substitution in
order to increase data population before comparing different exponential curve fitting algorithms. (Figure 1) Depth trend curves were created for shale, brine sand and gas sand lithologies. These depth curves are then used to predict AVO response for shale on brine and shale on gas interfaces for various depths (Figure 2). We also explore other applications of depth trend data. We forward model using a pseudo well and create a synthetic seismogram. By matching the seismic and synthetic we increase confidence in an undrilled hydrocarbon prospect (Figure 3). Finally we show how depth trend analysis can be combined with Monte-Carlo analysis to form probability distribution functions (PDFs) for various elastic parameters. This can later be used to form Bayesian Classification schemes leading to Facies distribution cubes.
-
-
-
Rock Physics and Reservoir Characterisation of Dolomitic-Sandstone Reservoir
Authors H. Morris and B. Hardy and E. EfthymiouRock physics is the bridge between all well and seismic data that allows us to better understand the sub-surface data. It is from this understanding that we can forward predict into the reservoir characterization of static models. We present here a simple but robust workflow, which allows the geoscientist to understand and capture the variability in the reservoir with the use of rock physics, forward modelling, seismic data conditioning, Joint Stochastic Inversion and Bayesian Classification. By understanding the variables that influence the seismic elastic and AVO signatures, the geoscientist can predict these variables away from the well (to provide evidential fluid fill and lithology variation) and therefore produce more accurate static models. The forward modelling of the various scenarios gave the interpretation team an understanding of the effects under various conditions (brine, gas, high porosities and low porosities). It identified that it would be possible to separate out the lithology effects and the fluid effects, preventing a mis-interpretation, and an insight into where the inversion results and classification would lead (Figure 1). The Data Conditioning of partial stacks proved to be an essential part of the workflow, allowing making the gradient stack a coherent volume rather than a volume dominated by noise. Calibrating the background AVO seismic signature to the wells meant that the synthetic (Figure 2) and seismic responses were aligned in their properties in and around the reservoir. The ability to optimally condition partial stacks
rather than raw gathers meant that the time and cost was greatly reduced, giving operational flexibility. A comparison of a conventional Bandlimited inversion versus the Stochastic Inversion highlighted the weakness of the Bandlimited inversion to capture the detail required due to resolution issues. Stochastic Inversions are an integrated modelling method and are capable of capturing or including very high resolution detail from the well. By using a relatively coarse sample rate of 2ms we were able to prudently predict below standard seismic resolution, and therefore the seismic data drove the inversion rather than geostatistics. Whilst there were discrepancies between the realizations, a consistency in general supported a strong inversion result and a common answer. Acoustic and Gradient Impedance were fundamental in the reservoir characterisation, and the Elastic Impedance acted as a good QC of the inversion prediction and results. The Bayesian Classification and Rock Physics Model calibrated methods both showed similar results in predicting pay vs. non-pay areas, with the Rock Physics Model providing a possibly more refined final result. The overall method shows a robust and coherent approach to understanding and predicting the reservoir characteristics.
It also allowed us to gain confidence in predictions of proximal prospects. The use of the stochastic inversion and Bayesian classification and Rock Physics Models to constrain and calibrate the inversions gives the results enhanced meaning in terms of reservoir properties. The rock physics to reservoir workflow produces a sophisticated high resolution static model which integrates all seismic and well data into one workflow from the basic interpretation through to dynamic modelling (Figure 3).
-
-
-
Field Development Planning for Coal Seam Gas: Challenging the Paradigm
Coal Seam Gas (CSG), alternatively known as Coal Bed Methane (CBM) is one of the exiting new energy plays emerging in the Asia-Pacific as well as elsewhere. CSG reservoirs and reservoir behavior over time are very intrinsically different from conventional plays, therefore conventional field development planning workflows need to be modified to address the focus issues and decisions relevant for CSG: number and type of wells required to achieve the committed gas delivery, timing of development startup taking into account anticipated range in dewatering time, optimum development phasing, optimum facilities layout, mitigation strategy to cover the key downside risks, as well as flexibility required to cater for upside. To date, CBM developments have typically followed a ‘low tech’ approach of pattern drilling with limited emphasis on subsurface studies and instead, a strong focus on ‘on-the –fly’ optimization of the wells and completions concepts. We believe there is potential to overhaul the traditional ways of going about CBM developments by using modern subsurface study and uncertainty management techniques to aid in upfront concept optimization (Figure 1). Objective of this paper is to illustrate this potential and some of the workflows and concepts involved.
As with conventional developments, reservoir characterization and modeling are a key component of the FDP study workflow. A lot of the focus is on mapping the distribution and properties of the reservoir rock. However, in a CSG play coal is the reservoir and gas storage is not in a conventional pore system but adsorbed on a molecular scale onto the internal surfaces of the coal. The reservoir properties that matter for GIIP and UR calculation are therefore different from conventional and include net reservoir (= coal)
thickness, isothermal coal properties (which control the gas adsorption & desorption capacity of the coal), impurities content (i.e., ash and moisture), gas content (i.e., saturation) and permeability of the natural fracture system in the coal. CGS developments to date are typically onshore, shallow and therefore drilling intensive. The wealth of well data brought about by such intense appraisal and pilot development drilling opens the door to elaborate geostatistical analysis as an effective means to highlight spatial trends and variability, deliver multiple realization maps and 3D models of each of the relevant reservoir properties, as well as to recommend optimum appraisal strategy and location. Rigorous analysis of the fracture system via integration of fracture spacing/orientation data from core and scanner tools with welltest results and seismically mapped structures can reveal key clues on permeability and connectivity of the coals. Maps of fracture orientation combined with (sub)seismic faulting can also aid in optimizing well placement. Because GIIP and UR equation is different from conventional, adaptations to existing modeling tool functionality are required to facilitate CSG volumetric computation. Like their conventional counterparts, CSG static reservoir models are then upscaled and transferred to dynamic simulation to establish optimum well count and spacing, predict dewatering time and required water handling capacity, and determine the optimum balance between wells and compression. We have developed fit-for-purpose workflows and toolkits to facilitate data transfer from mainstream static modeling tools to the specialist dynamic modeling packages that can adequately forecast CSG production.
-
-
-
Diversity Equals Opportunity: The ‘Romance’ of NE Sabah’s Shelf
Authors S. King, P. Restrepo-Pace, R. Jones, C. Goulder and Y. Ah Chim and C. RussellFluctuating oil prices, threshold economics and changing corporate strategies are all too familiar ‘constraints’ that drive companies into or out-of exploration areas. These factors are many times just as unpredictable as some of the elements of a given petroleum system. Regardless, it is a well known fact that the greatest asset of an exploration company is a diverse portfolio of drilling opportunities, with large upside potential. The geology of NE Sabah’s Shelf offers just such potential. The area is on trend with a prolific petroleum province exhibiting a 30% historical exploration success rate and delivering a 70% oil versus gas split. Recently acquired 2D and 3D seismic data, together with extensive palaegeographic reconstructions and 3D burial history modeling have helped illuminated a range of geologically independent targets in the area, from amplitude supported structures in proven play types, to the romance of previously undrilled basins. The prospective succession in this area can be broken into four largely independent plays: 1. Mid to Late Miocene Deepwater Clastics - A slope canyon system trending WSW-ENE has been identified in the Kindu Sub-basin and several structural and combined structural-stratigraphic closures are mapped. The system is not intersected in any of the near offset exploration wells, but appears somewhat analogous to the South Furious 30 discovery. 2. Late Miocene Shallow Marine Clastics – A proven play on the Sabah Shelf, included stacked gas pay in Titik Terang-1 and stacked oil pay in the South Furious and Barton discoveries. The late Miocene play is DHI supported and several amplitude anomalies showing flat spots and fit to structure have been identified. 3. Pliocene Carbonate Reefs – An extensive carbonate reef system extends south from the Philippines on to the Sabah shelf. The reef system has been targeted by several exploration wells in the far north, with no success, probably due to an absence of local mature source kitchens. Further south however, several prominent un-drilled reefs have been identified. The reefs exhibit possible flat-spots and lie immediately adjacent to the proven Kindu Sub-basin kitchen. 4. Pliocene Shallow Marine Clastics - A thick succession of Pliocene deltaics has been identified in the undrilled Siagut Sub-basin at the very northern edge of the Sabah Shelf. The Pliocene deltaics remain largely uncalibrated by drilling, but based on seismic facies analysis appear somewhat analogous to the proven Miocene play further south. 3D burial history modeling also highlights the potential for oil generation from the Siagut Sub-basin.
-
-
-
Unmasking the Crest, Imaging Below Shallow Gas Using Prestack Q Depth Migration, Irong Barat Field, Malaysia
Seismic imaging of many oil and gas fields in Peninsular Malaysia is degraded by amplitude and frequency attenuation (Q) associated with shallow gas. In addition to the amplitude attenuation, seismic travel time delays caused by abnormally slow velocities associated with these shallow gas accumulations cause time structure distortions in the seismic image. These amplitude, frequency, and seismic traveltime distortions often obscure the seismic image sufficiently that seismic reservoir characterization is impossible. In some areas the seismic image is completely distorted and lost, in these situations conventional marine seismic P wave imaging is not an effective tool. However in other areas the seismic image is degraded, but seismic energy is still transmitted through the shallow gas attenuator. In these situations seismic processing technology can attempt to compensate for the image degradation. Using a Prestack Depth migration engine, we have developed a processing technique to recover the amplitude and frequency loss below these shallow gas zones. This technology uses an integrated Q model, velocity model, and depth imaging system to correct and restore the amplitude, frequency and velocity distortions associated with the shallow gas attenuators.
Initial implementations of prestack Q depth migration have shown that a detailed velocity and Q model of the subsurface is not the only requirement for a successful project. Since Q modeling requires the data to be true amplitude, most conventional approaches for noise attenuation and acquisition footprint removal cannot be applied prior to imaging. This requires the development of special noise mitigation techniques; otherwise the increased noise level can overwhelm the final imaging results. In addition, incorporation of the well data offers clues to the rock physics issues associated with the Q and velocity distortion. ExxonMobil recently completed the first prestack Q depth migration project in Malaysia over the Irong Barat field. A recently signed Production Sharing agreement for this mature field gives ExxonMobil and partner PCSB production sharing rights to 2033. Improved seismic imaging is part of the strategy implemented to recover remaining oil reserves for this mature field. The 142 square kilometer Irong Barat 3D
survey was acquired in 1998. The survey combines conventional marine data with OBC undershoot of the platforms, which adds processing complexity. Image quality on the flanks of the structure is very good, however varying degrees of shallow gas associated distortion are present over the crest of the structure and therefore Irong Barat was considered a good test for the Prestack Q Depth Migration technology. This paper will describe the seismic processing lessons learnt and present the results of the project.
-
-
-
Source Rock Evaluation in the Northern Dezful Embayment, Zagros, Iran
More LessIn order to evaluating some of the source rocks in Dezful Embayment such as Pabdeh and Gurpi 14 wells distributed in different oil fields from the northern Dezful Embayment selected and TOC % calculated by Δ log R method and neural network. Result compared with measured data (by Rock Eval). The result come from neural network have more correlation with measured data than Δ log R results. We calculated TOC % based on combination of resistivity , sonic and level of organic metamorphism(LOM).
In respect to Pabdeh and Gurpi F.m matured in some oilfields and parts of other oilfields, therefore we must calculated initial TOC, so we did oil generation modeling for getting E.Ro (equal Ro) , for calculation of transformation ratio(TR). Consequently, we could calculate initial TOC % and plot Iso TOC contour map in this area, and also make zonation Pabdeh and Gurpi formation based on geochemical criterions .
-