Li, Shi Zhen (China Geological Survey) | Wang, Yue (Schlumberger) | Liu, Xu Feng (China Geological Survey) | Zhao, Xian Ran (Schlumberger) | Zhao, Hai Peng (Schlumberger) | Xu, Lei (GeoReservoir Research)
Production from the Lower Silurian Longmaxi formation shale gas reservoir in Fuling, Changning, and Weiyuan fields in the Upper Yangtze area has reached over 10 billion cubic meters. The Wufeng-Gaojiabian formation of the Lower Yangtze area is a new area of shale gas exploration in China. The objective of this study was to evaluate the potential of the shale gas reservoir in this area.
An innovated lithofacies classification method was developed that incorporates total organic carbon (TOC), grain size, matrix mineralogy, and lithology. An integrated workflow with input derived from microscopic observation, thin section analysis, ion-milled backscatter scanning electron microscope (BSE), X-ray diffraction, X-ray fluorescence (XRF) element analysis, gas adsorption test, and other organic geochemical experiments provides significant advantages for lithofacies classification. This paper applies an advanced technology in pore geometry analysis of various lithofacies, which has demonstrable value in guiding the shale gas exploration in new areas such as the Lower Yangtze area.
Reservoir characterization was performed on an exploration well in the Tangshan area of China. The lithofacies of the Wufeng–Gaojiabian formation shale can be classified into four types: organic-rich argillaceous/siliceous shale, organic-rich/clay-rich siliceous shale, organic-rich siliceous shale, and organic-lean micritic dolomitic mudstone. The first three lithofacies types have potential for shale gas accumulation, and the organic-rich siliceous shale has the best potential. Careful BSE analyses were done on different shale samples, and an interactive algorithm was used to determine the porosity of the organic-rich siliceous shale, which ranges from 5% to 7%. The shale shows heterogeneity in pore geometry; intergranular pores and intragranular pores dominate the pore spaces. The pores are well connected, but organic pores are rarely seen under microscope. Nutrition adsorption tests performed on organic-rich siliceous shale samples show dual pore size distribution characteristics; one set ranges from 2 to 60 nm, and the other ranges from 85 to 125 nm. Macropores dominate the pore space and account for 53% of the total porosity. Mesopores account for 28%, and micropores account for 19%. The percentage of various pore size gives insight into the potential shale reservoir.
The comprehensive reservoir characterization of the shale gas reservoir of the Wufeng-Gaojiabian formation in the Lower Yangtze area, which investigated depositional settings, organic geochemical features, lithofacies, and reservoir properties, suggests that the Lower Yangtze area may have potential as a shale gas exploration frontier. The workflow can also be applied to other shale gas plays in China.
Shale has been a major destination for unconventional hydrocarbon resources for its wide stratigraphic coverage as well as high volumetric hydrocarbon potential. Contemporary success in North American shale plays has intrigued operators worldwide in shale exploration. Organic richness has been a key factor to determine the potential of shale as it is proportional to the amount of hydrocarbon likely to be generated and stored in available spaces within the shale. The other important factor in this context is shale brittleness as it indicates how fracable the potential shale is. Attempts are made here by strategically using standard wireline logs in order to evaluate potential of Eocene Vadaparru Shale in Krishna Godavari Basin, India qualitatively and quantitatively.
The technique used in this study involves identification of organic lean ‘clean shale’ interval and establishing a ‘clean shale’ relation of resistivity as a function of compressional sonic transit time in the study wells, as both the logs respond comparably to shale and its organic content. Using this relation a proxy ‘clean shale’ resistivity log is generated in shale and compared with measured wireline resistivity. A positive separation between calculated and measured resistivity is then assessed as proportionate shale organic richness, owing to the presence of relatively less dense (corresponding to longer sonic transit time) and more resistive organic content. Shale brittleness is predicted from Young's modulus and Poisson's ratio using compressional, shear and Stoneley wave velocities obtained from sonic measurements, assuming transversely isotropic nature of Vadaparru Shale.
The Eocene marine transgressive Vadaparru Shale is a dominant stratigraphy in KG basin as evident from seismics and drilling. Petrophysical analyses in study wells indicated appreciable brittleness within Vadaparru Shale. The organic richness i.e. amount of positive separation between calculated and measured resistivity combined with brittleness quantitatively indicate fair to excellent unconventional potential of Vadaparru Shale. Considerable thickness, Type-II, III kerogen content and geochemical measurements support the study and highlight it as a promising ‘shale reservoir’ destination. In the context of rapidly growing energy demand of India Vadaparru Shale can be considered as serious unconventional player.
Overall this study presents quick strategy for shale potential quantification, thus allowing operators to focus spatially in the quest of unconventional hydrocarbon resources.
Li, Jie (MOE Key Laboratory of Petroleum Engineering, China University of Petroleum) | Tu, Bin (MOE Key Laboratory of Petroleum Engineering, China University of Petroleum) | Li, Wei (Institute of CNOOC Shenzhen Branch, Shenzhen) | Li, Yunan (Energy Resources Engineeing, Stanford University)
Water-sensitivity damage is a significant problem for production of ultra-low permeability formation located in Yanchang oilfield, China. It is important to understand the water-sensitivity damage accurately and enhance the formation production. In this paper, we quantitatively evaluate the all water sensitivity damage on porous media, and obtain their negative influence to the production. Core flow experiments are designed to evaluate the water sensitivity damage degree. NMR(Nuclear Magnetic Resonance) method is introduced to compare images before and after the water fluids displacement through rock cores, and calculate the degree of permeability and porosity damage. QEMSCAN(Quantitative Evaluation of Minerals by Scanning electron microscope) technique is used to obtain the damage mechanisms by compare changes of pore diameter, mineral contents and distribution forms at inlet and outlet sides before and after water sensitivity damage. Numerical simulation method of ultra-low permeability is utilized to calculate the effect of water sensitivity on production. The results indicate that the clay swelling and migration are the main cause of water sensitivity for ultra-low permeability. That causes gradual increase of bound fluids and gradual porosity decreases from inlet to outlet. Porosity decreases by 1.61% on average. In the distribution of pore diameter, the pore size larger than 35μμm decreases and the pore size smaller than 35μμm micron increases. Further, result of QEMSCAN points out that Illite/montmorillonite and Chlorite/montmorillonite mixed-layer minerals bring out clay swelling, and illite and chlorite cause clay migration. At last, the result of numerical simulation method of ultra-low permeability shows that water sensitivity damage can result in reducing of oil production, decreasing of injection volume of water well, the smaller swept area of water injection, the lower displacement efficiency, the higher the pressure gradient, the greater pressure loss at the injection end, and the more difficult to inject and produce. From micro-mechanism to macro-production, our research fully and clearly reveals the damage of water sensitivity to ultra-low permeability reservoirs. Our research works have been successfully applied to ultra-low permeability reservoirs of Yanchang oilfield to reducing formation damage during development.
Carbonate rocks are complex in their structures and pore geometries and often exhibit a challenge in their classification and behavior. Many rock properties remain unexplained and uncertain because of improper characterization and lack of data QC. The main objective of this paper is to study flow behavior of relative permeability with different rock types in complex carbonate reservoirs.
Representative core samples were selected from two major hydrocarbon reservoirs in Abu Dhabi. Rock types were identified based on textural facies, PoroPerm characteristics and capillary pressure. Porosity ranged from 15% to 25%, while permeability varied from 1 mD to 50 mD. Primary drainage and imbibition water-oil relative permeability (Kr) curves were measured by the steady-state technique using live fluids at full reservoir conditions with in-situ saturation monitoring. High-rate bump floods were designed at the end of the flooding cycles to counter capillary end effects. Aging period of 4 weeks was incorporated at the end of the drainage cycle. Robust data QC was performed on the samples, and final validation of the relative permeability was conducted by numerical simulation of the raw data and measured capillary pressure.
The followed QC procedure was crucial to eliminate artefact in the relative permeability curves for proper data evaluation. The different rock types showed consistent variations in the relative permeability hysteresis and end points. Imbibition relative permeability curves showed large variations within the different rock types, where Corey exponent to oil ‘no’ increased with permeability from 3 to 5, whereas the Corey exponent to water ‘nw’ decreased with permeability and ranged from 3 to 1.5. The variations in the relative permeability curves are argued to be the result of different rock structures and pore geometries. Variations were also seen in the end-point data and showed consistent behavior with the rock types.
The different carbonate rock types were identified based on geological and petrophysical properties. Higher permeability samples were grain-dominated and more heterogeneous in comparison to the lower permeability samples, which were mud-dominated rock types. Imbibition Kr curves showed larger variations than the primary drainage data, which cannot be interpreted based on wettability considerations only. The relative permeability curves have been thoroughly evaluated and QC'd based on raw data of pressure and saturation by use of numerical simulation. Such RRT-based Kr data are not abundant in the literature, and hence should serve as an important piece of information in mixed-wet carbonate reservoirs.
Vahrenkamp, Volker (King Abdullah University of Science and Technology) | Khanna, Pankaj (King Abdullah University of Science and Technology) | Petrovic, Alexander (King Abdullah University of Science and Technology) | Ramdani, Ahmad (King Abdullah University of Science and Technology) | Putri, Indah (King Abdullah University of Science and Technology) | Sorrentino, Ranglys (King Abdullah University of Science and Technology)
The characterization and modelling of carbonate reservoirs can still be significantly improved to account for complex property and fracture network heterogeneities at scales difficult to resolve in the subsurface. The objective of this research is to develop and establish workflows for high fidelity geological modelling and characterization using modern and ancient carbonate outcrop analogues.
As a first step, we carefully selected high quality modern and ancient analogues to create comprehensive data sets on depositional heterogeneities. Advanced instrumentation and techniques were used such as 3D drone surveys, high-resolution surface geophysical surveys (50 MHz-100 MHz, and seismic), chirp sub- bottom profiler and high-resolution bathymetry mapping. These high-end techniques are paired with tried and tested standard geological techniques of measuring stratigraphic sections anchored by outcrop spectral gamma ray logs, analysis of sediment samples (texture, grain size, mineralogy, geochemistry) and fracture/fault surveys all integrated with full cores drilled in the outcrops. Using these, data models can be created for depositional and fracture heterogeneities at different scales and populated with ranges of property data like those found in actual reservoirs. The outcome will be a series of models for various carbonate reservoir settings and well location patterns with the goal of supporting drilling/exploration operations and reducing future development costs.
The project is based on two large-scale research projects of Jurassic carbonates outcropping in central KSA and a large modern carbonate platform in the Red Sea. Jurassic outcrops were analyzed using a unique dataset of measured sections including spectral gamma ray logs (300 vertical m), drone photogrammetry data (4x4 km2 overflight and several km's of vertical cliffs), seismic data (2 km), and GPR data (8 km). Data expose lateral heterogeneities, facies dimensions, and fracture networks at different scales. The modern carbonate outcrops are an ideal laboratory to investigate lateral facies heterogeneities and their relation to environmental factors influencing sediment distribution (prevailing winds versus storms, climate and nutrients). Around 800 km of hydroacoustic data, 50 sediment cores and 200 sea-floor samples were collected exposing significant and complex heterogeneities.
The outcome of these research projects significantly increases our understanding of property heterogeneity, facies distribution, fracture networks, and architecture of complex carbonate reservoirs. Resulting multi-scale modelling approaches and associated facies templates will improve the prediction of spatial heterogeneities of facies in subsurface reservoirs of similar settings. In addition, these datasets can be used as input for static analogue models and dynamic simulations to test sensitivities and determine optimum development scenarios for improving ultimate recovery.
Su, Qin (Research Institute of Petroleum Exploration & Development-Northwest, NWGI, PetroChina) | Zeng, Huahui (Research Institute of Petroleum Exploration & Development-Northwest, NWGI, PetroChina) | Zhang, Xiaomei (Research Institute of Petroleum Exploration & Development-Northwest, NWGI, PetroChina) | Lv, Lei (Research Institute of Petroleum Exploration & Development-Northwest, NWGI, PetroChina) | Qie, Shuhai (Research Institute of Petroleum Exploration & Development-Northwest, NWGI, PetroChina) | Meng, Huijie (Research Institute of Petroleum Exploration & Development-Northwest, NWGI, PetroChina)
With the continuous development of oil and gas exploration technology, the remaining exploration targets in the middle and shallow areas of the land are becoming less and less, and the deep complex targets have become an important replacement area for oil and gas growth. In order to enhance the deep tight gas exploration potential of the Songliao Basin in China, structural interpretation and reservoir prediction of deep volcanic rocks and glutenite lithologic gas reservoirs are carried out, while the basic requirements for seismic data acquisition in complex reservoir exploration in the middle-deep layers are: higher sampling density, even distribution of space, appropriate offset. In the face of particularly complex reservoirs, it is necessary to fully strengthen the acquisition parameters, ensure the reservoir prediction needs, and avoid the waste caused by the inability to solve the geological problems. However, due to the weak signal and strong interference, the conventional narrowazimuth three-dimensional observation system in the Songliao Basin is affected by factors such as low folds, large grid bin, and low reception of complex structural information, which affects the middledeep layers. The imaging effect has restricted the development of tight gas exploration in the middledeep layers. Therefore, the broadband, wide-azimuth and high-density (BWH) 3D seismic exploration technology has been developed. BWH refers to a wider excitation and reception frequency band, a wider reception orientation, and a higher sampling density. Generally, broadband acquisition requires signals with an octave of more than 5 times; wide-azimuth observation systems should have an aspect ratio greater than 0.5, where an aspect ratio greater than 0.85 is called an omnidirectional observation system; when using an explosive source, sampling densities greater than 500,000 channels/km
Noei, Emad Ghaleh (Dept. of Geomatics Engineering University of Calgary, Canada) | Dettmer, Jan (Dept. of Geoscience, University of Calgary, Canada) | Ali, Mohammed (Dept. of Earth Sciences, Khalifa University, UAE) | Lee, Gyoo Ho (Korea Gas Corporation, Korea) | Kim, Jeong Woo (Dept. of Geomatics Engineering University of Calgary, Canada)
This work investigates nonlinear inversion of gravity data to infer Infracambrian Hormuz salt structures offshore Abu Dhabi, UAE. A Bayesian approach with a trans-dimensional parametrization of the subsurface is applied that does not require regularization, resulting in more objective inversion results. The trans-dimensional parametrizations discretize the subsurface structure including the salt dome by an irregular grid of Voronoi cells. Both the number of cells and the cell coordinates are unknown parameters estimated from gravity data. The density contrast of the salt structures is assumed as known. The solution in Bayesian inversion is given by a large ensemble of parameter sets. Here, the trans-dimensional ensemble is obtained with the reversible-jump Markov chain Monte Carlo (rjMCMC) algorithm. Residual errors are parametrized by a full covariance matrix, which is estimated and updated as part of an iterative inversion scheme. Efficient rjMCMC sampling is achieved with parallel tempering. Inversion of airborne gravity anomalies illustrates well-defined Infracambrian Hormuz salt structures offshore Abu Dhabi, where the irregular grid spatially adapts to the data information and without the need to impose explicit regularization or fixed grids. Uncertainty estimates highlight salt dome extent. This study provides new insight into the existence and shape of oil reservoirs associated with the underlying salt structures.
Agnihotri, Praveen (ADNOC Onshore) | Pandey, Vikram (ADNOC Onshore) | Thakur, Parmanand (ADNOC Onshore) | Al Mansoori, Maisoon (ADNOC Onshore) | Rebelle, Michel (Total SA) | Smith, Steve (Baker Hughes, a GE Company) | Bhatt, Pranjal (Baker Hughes, a GE Company) | Zhunussova, Gulzira (Baker Hughes, a GE Company) | Hassan, Syed (Baker Hughes, a GE Company)
Holistic assessment of project economics and subsurface characterization provides a framework to handle challenging reservoirs. Capturing ranked uncertainties based on their impact on the project and meticulous working towards de-risking the project is key for the success of the entire project. Committing increased production from the field is dependent on proper evaluation of the reservoir.
This paper reviews characterization of a tight reservoir deposited in the intra-shelf Bab basin during lower Aptian time. Initial stage reservoir characterization is critical in formulating reservoir development plan and estimating a realistic assessment of rates and volumes for the field.
The target formation is a low-permeability (average permeability 0.5 mD) heterogeneous carbonate reservoir sitting directly above and adjacent to a producing carbonate reservoir. It is essential to understand communication between the zones. The pilot well is drilled with 225 ft of conventional core and quad-combo logs. Advanced logs such as resistivity image, cross-dipole acoustic, nuclear magnetic resonance, vertical interference test (VIT), formation pressure (including pressure transient data), and fluid samples were acquired. The main objectives of the evaluation program were to determine the formation pressure, collect representative oil sample(s), conduct vertical interference tests between the sub-zones and collect appropriate data for geomechanical and rock-physics characterization.
Thorough pre-job planning and cross-discipline cooperation during the operation provided high fidelity log data and interpretation of the data into a coherent result. This included integration of image data with vertical interference tests from the wireline formation tester (WFT) where barriers were confirmed. In addition, NMR permeability was matched and calibrated using pretest mobility measurements and formation pressure data was combined with full waveform advanced acoustic processing to explain the communication between the upper target zone and the lower producing reservoir. Advanced acoustic analysis helped to fully characterize the target formations with stoneley permeability, azimuthal anisotropy, and presence of fractures.
This paper demonstrates the importance of multi-disciplinary team effort in characterization of challenging reservoirs. It highlights the importance of holistic planning before the execution phase, and keeping a focus on the larger goal while executing individual aspect of a complicated project.
Formation evaluation measurements have evolved over decades and occasionally it benefits the industry to provide a review of how the latest logging measurements fit together in an integrated manner, for successful evaluation of a challenging reservoir.
Exploration in the Middle East can benefit from the creation of sequence stratigraphy-based, scalable, 3D models of the subsurface that are, in effect, a subsurface digital twin that extends from the plate to pore. Stratigraphic and structural organization are integrated into this model to provide a predictive geological framework for analysis of reservoir- and regional-scale geology. This framework enables testing of novel geologic concepts on the Arabian Plate.
The first step of model design is to temporally constrain data within a sequence stratigraphic framework. Publically available data were used in the entire construction of this model. This framework enables the generation of plate-wide chronostratigraphic charts and gross depositional environment (GDE) maps that help to define major changes in the regional geological context. The integration of a geodynamic plate model also provides deeper insight into these spatial and temporal changes in geology. The subsurface model also adopts the principles of Earth systems science to provide insight into the nature of paleoclimate and its potential effect on enhancing the predictive capabilities of the subsurface model. A set of plate-scale regional depth frameworks can be constructed. These, when integrated with GDE maps and other stratigraphic data, facilitate basin screening and play risking.
This plate to play methodology has yielded value through the development of new play concepts and ideas across the Arabian Plate. Exploration has historically relied on the identification of large structures. However, the majority of these are now being exploited. Underexplored stratigraphic traps, and unconventional resources are new concepts that can be better evaluated by using a digital twin of the subsurface. The integration of seismic data and sequence-stratigraphy-calibrated wireline log data can be used to identify the subcrop pattern beneath an unconformity, as well as regions where potential reservoir rocks are in juxtaposition with seals. Intrashelf basins are a key feature of the Arabian Plate. They lead to stratigraphic complexity, yet are key factors for both source rock and reservoir development. From an unconventional perspective, novel, tight plays that exist within or above prominent source rock intervals can also be established.
Value and insight into previously underexplored play concepts, such as within the Silurian Qusaiba Member and the Cretaceous Shilaif Formation of Abu Dhabi, can thus be generated from the stratigraphic attribution of geoscience data. This data can enable better-informed predictions into "white space" away from data control.
The objective of this paper is to share the experience, approach and strategy to the technical forum involved in developing mid-size offshore gas fields from exploration, appraisal to field development and production, accordingly monetizing the produced gas by exploring various options in the international market.
Subsequent to exploration and appraisal of two adjacent blocks A-1 and A-3, three prospects were delineated- Shwe and Shwe Phyu in Block A-1 and Mya in Block A-3, Myanmar. These blocks are operated by M/s POSCO INTERNATIONAL and other consortium members are OVL, GAIL, KOGAS and Myanma Oil and Gas Enterprise (MOGE).
Shwe and Shwe fields were discovered in January 2004 and January 2005 respectively in Block-A-1. Subsequently, Mya field was discovered in March 2006 in Block A-3. Mya field is divided into two parts, i.e, Mya-Norh and Mya-South.
To develop these fields, Consortium conducted Pre-Front End Engineering Design (FEED) and FEED studies from two international contractors and selected the best option to develop these fields. Consortium is jointly developing the fields in a phase which is called SHWE Project. Drilling of 10 wells in Shwe Prospect (8 production, 1 disposal well & 1 abandoned) from a platform drilling rig and 4 subsea wells in Mya-North Prospect from drillship (MODU) completed in Phase-1 development. Phase-2 development will involve drilling of 4 subsea wells each in Shwe and Shwe Phyu prospects which will be drilled by MODU. Phase-3 development will consider installation of LP compressor platform if delivery pressure falls below the contract requirements. Currently, produced gas from Shwe and Mya-North Prospects are being processed at Shwe Common Processing Platform (CPP) and then it is brought upto Onshore Gas Terminal (OGT) through 32" × 110 km pipeline (105 km – offshore and 5 km onshore).
The SHWE project can be economically produced for about 24 years. The buildup production period was for one year and plateau period estimated for 13 years. The unitization of the fields and production & sales of produced gas involved the following milestones and future development plans: Installation of Integrated Drilling cum Processing Platform (IDPP) at Shwe prospect for Phase-1 development drilling of Shwe and bringing produced gas from Mya-North to Shwe CPP. The processed gas from the Shwe platform is transported to Sales Point through offshore subsea pipeline from Shwe CPP till landfall point and onshore pipeline from landfall point to Sales Point at OGT. Evaluated options to sale, burn or dispose the condensate produced with gas from all the fields and finally decided to dispose the condensate by drilling a condensate disposal well at Shwe prospect. Evaluated various options and routes to sale the produced gas to potential buyers in international market. Phase-2 development wells at Shwe and Shwe Phyu would be drilled and produced gas would be processed at Shwe CPP and installation of LP compressor would be a part of Phase-3 development plan.
Installation of Integrated Drilling cum Processing Platform (IDPP) at Shwe prospect for Phase-1 development drilling of Shwe and bringing produced gas from Mya-North to Shwe CPP.
The processed gas from the Shwe platform is transported to Sales Point through offshore subsea pipeline from Shwe CPP till landfall point and onshore pipeline from landfall point to Sales Point at OGT.
Evaluated options to sale, burn or dispose the condensate produced with gas from all the fields and finally decided to dispose the condensate by drilling a condensate disposal well at Shwe prospect.
Evaluated various options and routes to sale the produced gas to potential buyers in international market.
Phase-2 development wells at Shwe and Shwe Phyu would be drilled and produced gas would be processed at Shwe CPP and installation of LP compressor would be a part of Phase-3 development plan.
Offshore gas field development though is not a new concept, but developing two independent Blocks A-1 and A-3 in Myanmar by Shwe Consortium is a typical case study from exploration till development and production. The Shwe development is a result of nine year effort of the Shwe Consortium from exploration stage till development and production. This paper provides an overview of development and execution of the project introduces key challenges, achievements and learning's. It also emphasise the importance and integration between all disciplines required to successfully deliver any project.