S field has unique geological condition, the depth of maturity based on geochemistry analysis start from 800 m and classified as shallow depth rather than in the core of Kutai basin at 4000 m. It was caused by gravity tectonic from north which lifting the middle miocene formation from below. This situation gives the benefit to find source rock in shallower depth for unconventional exploration.
To characterize and predict the source rock especially for Total organic content value is using a well-known method called ΔLog R. This technique has been applied in many field with success stories. Beyond it is success, this method is less recognizing to predict in coal, because of the huge separation between Porosity log and Resistivity log. This study aims to applied this method in delta plain environment with abundant of coal source rock using between Density log, Sonic log, and Neutron log combine with Resistivity log. Besides that, TOC accumulation will be compared with Cyclostratigraphy trend, which trends contain much TOC content and by this vertical distribution to generate lateral correlation.
Basic principle for ΔLog R method is to seek the overlay between porosity log and Resistivity Log. Assuming when TOC is high the sediment rocks has good porosity and higher Resistivity reading. Those are the effect from kerogen in shale and generation of hydrocaron. In immature organic rocks it has good porosity but Resistivity log shows lowest value. Most of organic accumulation is in non reservoir. To eliminate the reservoir zone by using the Gamma ray log. This TOC value will be validate using several geochemistry analyses from cores.
Cyclostratigraphy-INPEFA log, is cyclic deposition that refer to orbital change that effect insolation on earth. This situation cause fluctuates of Eustachy and change the sea level. When sea level drop or N-Trend and coarse sediment will deposit and the other hand P-Trend or warming phase. Predicted TOC accumulation is much higher when warming phase. This trend will help to know TOC distribution around the field.
Arisandy, Mellinda (PETRONAS Carigali Indonesia Operations) | Mazied, Miftah (PETRONAS Carigali Indonesia Operations) | Putra, Bayu P (PETRONAS Carigali Indonesia Operations) | Yogapurana, Erik (PETRONAS Carigali Indonesia Operations) | B Mohd Idris, Jamin Jamil (PETRONAS Carigali Indonesia Operations) | Darmawan, Hendra I. (PETRONAS Carigali Kuala Lumpur)
This paper describes geochemistry analysis, hydrocarbon charge and entrapment model for prolific "MA" Block in the West Natuna Basin. Even though the area is currently at a mature exploration stage, the behaviour of hydrocarbon distribution in the area is still poorly understood and the link between discovered hydrocarbon and possible kitchens is still unknown. This study is an attempt to understand hydrocarbon expulsion, charging and entrapment in "MA" Block to de-risk further exploration efforts.
Several localized inverted half-grabens were identified through seismic interpretation. Nearby wells were then selected in evaluating source rock quality and maturity. In order to determine hydrocarbon expulsion model, 1D-3D burial history and thermal maturity models were constructed using integration of source rock and fluids geochemistry, temperature, seismic, and well data. Hydrocarbon charge and entrapment models were then simulated using 3D basin modeling software and calibrated with existing proven accumulation to produce a risked understanding of hydrocarbon distribution in the study area.
This study suggests that the most possible source rocks are the Late Eocene and Oligocene shales of Lama Formation and Lower Gabus Formations. Both source rocks are indicated by type I & type III kerogen. Lama source rock was confined in the initial grabens and post mature in deep paleo-grabens. This study confirmed that charging is derived from four (4) kitchen areas: Anoa, Gajah, Kakap, and Kambing grabens. The oil samples from "MA" Block indicated lacustrine facies. Rock geochemistry analysis portrayed oil-prone and gas-prone source rock.
In general, hydrocarbon was migrated from the southeastern area (Kambing graben) and southwestern area (Gajah graben). Hydrocarbon was later on accumulated in the nearest structural entrapments (anticlines). In the deep grabens (Kakap and Kambing), the hydrocarbon expulsion was starting as early as 37 Ma and 31 Ma, respectively, while in shallow graben (Anoa) the expulsion was starting at 29 Ma. The earliest structural trap commenced at 21 Ma, aligned with the initial compressional regime that was affecting the West Natuna Basin. Notable accumulative erosion in Miocene was nearly 1000 m at inverted structures, by which partly removed regional seal and reduced reservoir effectiveness. Significant yet-to-find hydrocarbon is predicted to be concentrated in the Anoa, Kakap, and Northeast Kambing area.
Overpressures (abnormally high fluid pressures) represent a significant geohazard and drilling problem. Prediction of overpressures is very important for well planning and safe drilling. However, accurate and reliable prediction requires an understanding of the origins and distribution of such overpressures. Petrophysical properties of the sediments are affected by different overpressure generation mechanisms and in turn help in understanding the types of such mechanisms. There are two distinct overpressure generating mechanisms, namely compaction disequilibrium (undercompaction) and fluid expansion (unloading), each of which have different petrophysical signatures and hence different prediction methodologies. The most common cause of overpressure generation in the majority of the sedimentary basins in the world is undercompaction, in which pressure increases due to rapid burial/loading of the sediments in an effectively sealed impermeable environment. This type of overpressure is normally associated with abnormally high porosities and shows up in changes in velocities. The secondary type of overpressure mechanism is fluid expansion. Thermal induced overpressure is the most common fluid expansion mechanism. This mechanism is very common in areas of high geothermal gradient and can result in significant overpressures. This mechanism, however, is not always present. Thermally induced overpressures result in decreasing effective stress in contrast to overpressure due to undercompaction where a constant effective stress is observed. Thermally induced overpressures are difficult to predict and require a different prediction methodology. Improved knowledge of overpressure generating mechanisms and distribution of pore pressure in a basin provides critical supporting information for the asset team in hydrocarbon exploration and production. This information not only has an immediate impact on drilling cost and safety but also provides insight to key elements in petroleum system analysis.
This paper presents a study showcasing the geological control on origin and distribution of overpressure in a HPHT (high pressure, high temperature) field from offshore (water depth ~100-150m) South East Asia. Historically, the offset wells in the field were drilled through complex geological settings including high overpressure (~17-18 ppg), high temperature (170-185 deg C) and variable stress fields. The lithology is dominated by shales and most of the wells drilled in the area encountered drilling challenges with respect to high overpressure development. An initiative for a pore pressure prediction study was undertaken in a semi-regional scale involving ten offset wells in the study area. The main focus was to understand the overpressure mechanism and distribution in the study area vis-à-vis the geological setting and control. This was followed by predrill prediction for the planned wells, as one of the objectives of this study was also to aid in future development well drilling. Well planning based on the study results were done for two prospect wells which were located in similar shallow water.
Anis, Apollinaris Stefanus Leo (Schlumberger) | Syarif, Zilman (Saka Indonesia Pangkah Limited) | Setiawan, Ade Surya (Schlumberger) | Hidayat, Azalea (Saka Indonesia Pangkah Limited) | Murtani, Anom Seto (Saka Indonesia Pangkah Limited)
Ujung Pangkah Field which located at offshore East Java Indonesia, is known for its challenging nature from geological, reservoir and drilling perspectives. Drilling experiences in this area shows severe wellbore instability in overburden shale and in fractured carbonate reservoir. Hydrocarbon production directly exacerbate drilling problems and production issues that were not expected came earlier than predicted, for example early water breakthrough. At least two or three operators facing similar severe wellbore instability problems in the area.
Due to the complexity of subsurface systems and coupled interactions between depletion and stresses, the present-day stress state in Ujung Pangkah Field which have undergone production will be different from the pre-production stress state. Therefore, a comprehensive analysis will require numerical modelling involving coupling of 3D geomechanical model with fluid flow during production operations from dynamic model. Present-day stress state is subsequently used for wellbore stability analysis of planned development wells in Ujung Pangkah Field. Investigation of the behavior of natural fractured reservoir during depletion and its impact to reservoir management is also attempted. Two-way coupling of geomechanic and dynamic models were conducted whereby porosity and permeability update due to production were simulated based on uniaxial pore volume compressibility tests. Hence, porosity and permeability of fractures are not considered static anymore but dynamic due to stresses changes and production.
The result of coupled simulation is able to reduce wellbore instabilities significantly in the planned well. The stable mud weight windows for planned wells are extracted from the model. The stable mud weight window in the reservoir interval is narrow to no stable drilling window in all the planned wells due to depletion. In general, the preferred direction to drill, requiring lowest mud weights, is in the direction of minimum horizontal stress which in this case is Northwest-Southeast (NW-SE). However, it was found that azimuthal dependency of mud weight is insignificant due to low horizontal stress anisotropy.
Reservoir compaction and sea-bed subsidence were also calculated using the outputs from the model. The result is useful for completion and platform integrity.
Ridha, Muhammad (Universitas Diponegoro) | Nurdiansyah, Mukhammad (Universitas Diponegoro) | Zamili, Jonathan Sofiawan (Universitas Diponegoro) | Triwigati, Purnaning Tuwuh (Universitas Diponegoro) | Muslih, Yan Bachtiar (Universitas Pertamina) | Farida, Widiastuti Nur (Pertamina Hulu Energi)
This study area is located on Dolok River, Banyumeneng, Western Kendeng Basin, which has a direct relation to the Sunda Shelf as the largest sediment supply for Kendeng Basin. The study aims to determine the changes of depositional succession on Late Neogene in the Western Part of Kendeng Basin and identify the diagenesis process and the implication to the physical properties of Calciclastic Submarine Fan (CSF) Deposits.
The methods used in this study are field observation which was used to gather the stratigraphic record of deposits and rock samples analysis through petrography, microfossil, diagenesis, porosity and permeability. Measured stratigraphic section was used to determine the depositional pattern, facies and processes. Petrography analysis was used to determine the composition and diagenetic features. Moreover, the microfossil analysis was used to determine the relative age and the bathymetry of deposits, while the porosity was calculated using the mass-weighted method and permeability was calculated using the permeameter gas method to determine the quality of deposits as the hydrocarbon reservoir.
Generally, the section shows the progradation sequence characterized by the Lobe Fringe deposits which gradationally change to the Outer Shelf deposits. The lower part was characterized by thick Hemipelagic Mudstone and Thin-bedded Calciturbidite Facies, showing the part of Lobe Fringe Deposits. The second part was divided into MTD type 1 and 2, MTD type 1 consist of Conglomeratic Calciturbidite, Clast-Supported Debrites, and Graded Calciturbidite, then the MTD type 2 is slumped levee deposits, showing the high-density turbidity current channel complexes on the Gullied Upper Slope. The third part was characterized by conglomeratic calciturbidite, graded calciturbidite, clast supported debrites, and hemipelagic mudstone, included into Braided Axis Channel facies. The fourth part was characterized by the interbedded of Thin-Bedded Calciturbidite, Laminated Calciturbidite and Hemipelagic Mudstone Facies, showing the Levee facies. The upper part was characterized by thick Cross-Bedded Calciclastic deposit, showing the Outer Shelf depositional environment. Furthermore, the Flute Cast shows the NW-SE paleocurrent direction which indicates that the Sunda Shelf Paleo-Environment was considered as the major sediment supply for this area. Moreover, the Foraminifera analysis shows the Lower Bathyal - Middle Neritic bathymetry on Middle - Late Miocene (N9 N18). The porosity and permeability quality ranged from 2.13 - 6.38% and 7.54 - 86.38 mD. Combined with petrography analysis, it can be analyzed that the diagenesis processes of Banyumeneng CSF deposits are micritization or grain-coating clays, compaction, cementation, neomorphism, and dissolution. The poorly-sorted materials and highly-cementation process may restrict the pore-throat and reduce the permeability as well. As the outcrop exposed, the meteoric water acts to dissolve the cement, leaving the small porosity inside. Therefore, the pores tend to be the secondary pores which are formed by the post depositional dissolution.
Xu, Wei (CNOOC Research Institute Co., Ltd.) | Zhang, Yingchun (CNOOC Research Institute Co., Ltd.) | Fang, Lei (CNOOC Research Institute Co., Ltd.) | Jing, Zhiyi (CNOOC Research Institute Co., Ltd.) | Zou, Jingyun (CNOOC Research Institute Co., Ltd.) | Liu, Jun (CNOOC Research Institute Co., Ltd.)
The Albert Basin of Uganda is located at the northern end of the western branch of the East African Rift System. It is a graben rich in oil and gas with a shallow research degree. In the south of the basin, a fan delta system controlled by the boundary fault is developed in the Miocene formation. Due to the few wells and poor quality of seismic data in this area, it is difficult to predict the spatial distribution of sedimentary reservoir sands. In this paper, sedimentary forward modeling coupled with 3D geological modeling is used to provide new ideas for reservoir prediction.
Sedimentary facies analysis is based on core description, well logs, paleontology, heavy mineral content and grain size data. Quantitative analysis of accommodation space, source supply, and sediment transport parameters can help explain the main factors that controlled the sedimentation. Milankovitch cycle method was used to establish the time scale of the basin. The simulation results were combined with 3D geological modeling to quantify the characteristics of the sand body distributions.
Sedimentary facies analysis shows that the Miocene formation in the south of Albert Basin deposited in a shallow lacustrine environment. A proximal fan delta deposition with subaqueous distributary channels was controlled by the east boundary faults. Firstly, the accommodation space was estimated according to the thickness of the stratum and the change of the ancient water depth. The source supply was estimated by the area of the project and formation thickness, and the transportation parameters were estimated according to the nonlinear transportation model based on the traction flow with a little gravity flow. Secondly, an astronomical stratigraphic framework of the Miocene strata in the south of Albert basin was established through the Milankovitch cycle stratigraphy, and it was used to restrain the process of stratigraphic forward modeling and to reproduce the sedimentary evolution process in the geological historical period. Thirdly, the stratigraphic forward modeling results were resampled into the geological model, a 3D reservoir probability distribution model is established from trend modeling to quantitatively characterize the spatial distribution of sand bodies. Finally, the sandstone distribution simulation results were transformed into quantitative control constraints for 3D geological facies modeling. Thus, the new approach significantly promotes the facies model quality and provides robust results for petrophysical property models.
Integration of stratigraphic forward modeling with 3D geological modeling can effectively solve the problem of reservoir characterization in an early stage of oilfield development through the interaction of the dual model coupling. This method has unique advantages in the reservoir research in the area with fewer data and great variation of sand.
Abdullatif, Osman (King Fahd University of Petroleum & Minerals) | Osman, Mutasim (King Fahd University of Petroleum & Minerals) | Yassin, Mohamed (King Fahd University of Petroleum & Minerals) | Makkawi, Mohamed (King Fahd University of Petroleum & Minerals) | Al-Farhan, Mohamed (King Fahd University of Petroleum & Minerals)
The Miocene deep sea turbidite sandstone of Burqan Formation is important hydrocarbon reservoir target in Midyan region, Red Sea, NW of Saudi Arabia. Excellently exposed outcrops of Burqan Formation in Midyan region provide good data to examine and evaluate the reservoir rocks. This study integrates field observations (sedimentologic, stratigraphic and structural) and measurements from outcrop analog of the turbidite sandstone to investigate and characterize the reservoir heterogeneity, quality and architecture. The methods and approach followed used sedimentologic and stratigraphic analysis based on vertical and lateral outcrop sections and photomosaic so as to reveal the vertical and lateral distribution of the lithofacies and their geometries at outcrop scale. Moreover, terrestrial laser scanning (LiDAR) was utilized in this study to capture outcrop meso to macroscopic sedimentologic and stratigraphic and structural features details (strata surfaces. geometry distribution, faults, fractures). We integrated field observations with laboratory analyses to characterize the microscopic sedimentologic heterogeneity of lithofacies, texture, composition and petrophysical properties of the turbidite sandstone.
The stratigraphic analysis shows variation in outcrops from proximal to distal parts, within 15 to 20 km traverse across the outcrops belt (west to east) of Burqan Formation. The sandstone body thickness varied between 2 – 4 m in the proximal parts and between 0.5 – 1 m distally. Also, these variations in thickness was associated with increasing of shale/sandstone ratio from proximal to distal parts. The sandstone bodies width revealed from outcrop mosaics extend laterally between 100 to over 150 m. The lithofacies consists of both matrix and clast supported conglomerates, pebbly sandstone and coarse to very coarse and medium grained, massive, trough and horizontally stratified sandstone. These facies were interbedded with siltstone, mudstone and shale. The sand bodies were vertically and laterally stacked in the proximal parts and decreases in the medial and distal parts, however, locally the shale and mudstone lithofacies interbeds and form baffle zones. The region is tectonically and structurally active, therefore, at outcrop scale the repeated tectonics and rifting in the region resulted in faulting, shearing and fracturing which added complexity to the turbidite sandstone reservoir architecture. Moreover, tectonic affected reservoir/seal relationship, reservoir continuity and distribution of inter-reservoir barriers and baffles.
The results of this high resolution outcrop analog study might provide information and data base on types and scales of geological heterogeneities and their impact on reservoir quality and architecture within the interwell spacing. Moreover, it might also provide guides for exploration and development and help in decision making to avoid risks under the complex geological setting in the Red Sea region and other hydrocarbon basins under similar geological setting.
The purpose of the paper is to present the results of using local sand resources in Saudi Arabia for the manufacture of resin coated proppant as a ceramic proppant alternative for deep conventional gas development. Crushed Miocene sandstone, old river sand and dune sand has been tested for a source to manufacture resin coated sand proppant. Compared to Northern White Sand in USA, each sand source has its own set of limitations such as angularity, low aspect ratio, clay, carbonate scale or iron oxide coating, and/or micro-fracture damage. Complete resin bonding to the particle surface required clean quartz surface free of sharp edges and no dust contamination. Conductivity testing of the resin coated sand at reservoir pressure and temperature reveals that over 95 wt% of the mesh sized sand particles should pass the room temperature crush test before coating.
Saini, Dayanand (California State University, Bakersfield) | Wright, Jacob (California State University, Bakersfield) | Mantas, Megan (California State University, Bakersfield) | Gomes, Charles (California State University, Bakersfield)
A critical analysis of the key geological characteristics, completion techniques, and production behaviors of the Monterey Shale wells and their comparisons with analogous major US shale plays—namely, the Bakken and the Eagle Ford—may provide insights that could eventually help the petroleum industry unlock its full potential. The present study reports on such efforts.
The Monterey Shale is very young and geologically heterogeneous compared with the Eagle Ford and the Bakken. Oil viscosity in the Monterey Shale is significantly higher, and one can also notice that Monterey oil production has declined over the years. The Monterey Shale has a field-dependent completion strategy (pattern spacing and fracturing stage), while a horizontal, uncemented wellbore completion is common in the Bakken and the Eagle Ford. In the Monterey, nonhydraulically fractured zones of horizontal and hydraulically fractured wells appear to be making approximately equal contributions to the well’s cumulative production. The ongoing water-disposal operations in overlying injection zones, up to a certain extent, have affected the productivity of both types (long and short production histories) of wells. The geology also appears to have an effect on the production behaviors of horizontal and hydraulically fractured wells.
A preliminary economic analysis suggests that exploitation of the Monterey Shale is still a profitable venture. However, for sustainable development in a current price regime of USD 50/bbl of crude oil, it is necessary that production costs be reduced further. Also, compared with the Bakken and the Eagle Ford, the Monterey sits in regions of extremely high water stress (i.e., frequent occurrences of drought or drought-like conditions). However, oilfield-produced water associated with current steamflooding-based oil- and gas-production operations in the region as a base fluid suggests that it can potentially meet most of the water demand for future fracturing jobs. Also, combined use of a centralized water-management system; a less-costly, more energy-efficient, and high-capacity solar-powered desalination system; and a final sludge-management and/or residual-brine-disposal mechanism might assist the petroleum industry in managing flowback and produced waters while keeping water-handling costs low.
A combination of new enhanced-oil-recovery (EOR) methods for releasing the remaining oil from both nonfractured and fractured zones of horizontal wells and the use of oilfield-produced and recycled water for completing hydraulically fractured horizontal wells might prove to be a significant change for the future exploitation of California’s Monterey Shale resource, which is subject to the toughest hydraulic-fracturing regulations in the nation and is in a region of extremely high water stress.
Benham, Philip (Shell Kuwait Exploration and Production BV) | Cheers, Michael J. (Shell Kuwait Exploration and Production BV) | Freeman, Michael (Kuwait Oil Company) | Choudhary, Pradeep (Kuwait Oil Company) | Tanoli, Saifullah (Kuwait Oil Company) | Warrlich, Georg (Shell Kuwait Exploration and Production BV) | Capello, Maria (Kuwait Oil Company) | Al-Rabah, Abdullah A. (Kuwait Oil Company)
The previous generation of integrated reservoir models for KOC's heavy oil fields in North Kuwait brought insight which enable implementation of development decisions. With field maturation, additional well data and emerging production trends drive a need to update models to ensure relevance for serving the evolving business objectives of sustaining and maximizing incremental production.
This subsurface analysis has been augmented through study of the Jal-Az-Zor escarpment (north of Kuwait City) where stratigraphic equivalents of the reservoir crop out. Field analogues permit direct observations of the reservoir characteristics and heterogeneities that influence production behavior and ultimately project economics. They can resolve questions on spatial continuity of the key reservoir flow units by bridging the scale gap between seismic and well data which directly link to OPEX & CAPEX expenditure through optimal well spacing & design, injection steam/water conformance and BSW management.
It is relatively rare to have available such closely linked field-outcrop analogue data which is so readily accessible. The Jal-Az-Zor Escarpment represents an important cost-effective resource which is only just beginning to be leveraged in an integrated way to benefit field development and operations.
Applications for the field observation data set include but are not restricted to: Lateral and vertical continuity/variability of the reservoir, baffle and barrier lithologies. Role of diagenesis and its control on reservoir quality. Recognition of thin but critical units that need to be retained in the model e.g. high (or low) perm streaks. Appreciation of Microscopic to Field scale heterogeneities compared with well spacing. Field to Core/Log calibration to improve interpretation Multidisciplinary engagement
Lateral and vertical continuity/variability of the reservoir, baffle and barrier lithologies.
Role of diagenesis and its control on reservoir quality.
Recognition of thin but critical units that need to be retained in the model e.g. high (or low) perm streaks.
Appreciation of Microscopic to Field scale heterogeneities compared with well spacing.
Field to Core/Log calibration to improve interpretation