Monitoring and reevaluation of petrophysical attributes in a mature field under production for many decades is crucial for optimizing production and further development planning. In this case study, a multidisciplinary approach is deployed for formation evaluation and reservoir characterization using logging-while-drilling (LWD) sensors spanning formation volumetrics, fluid analysis, high-resolution image interpretation, and geomechanics to confirm remaining oil saturations and help identify recompletion intervals. LWD technologies were used in four wells in Sahmah field of Oman to provide an integrated petrophysical and geomechanical field study using a bottomhole assembly (BHA) including gamma ray, resistivity, formation bulk density, thermal neutron, acoustic, high-resolution imaging, and formation pressure testing sensors. A deterministic multimineral petrophysical model was used to derive formation volumetrics and fluid analysis. Geomechanical interpretation used high-resolution microresistivity imaging, acoustic slownesses, and formation pressure data to verify principal stress orientations and to quantify pore pressure and horizontal minimum and maximum stress magnitudes. These data were then correlated with historical data to evaluate sweep efficiency and residual fluid saturations. LWD sensors have proven to provide robust geological, petrophysical, and geomechanical data compared to previous traditional wireline data acquisition.
Mustafa, Ayyaz (King Fahd University of Petroleum and Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum and Minerals) | Abouelresh, Mohamed Ibrahim (King Fahd University of Petroleum and Minerals) | Sahin, Ali (King Fahd University of Petroleum and Minerals)
The lower Silurian Qusaiba Shale is one of the major source rocks for Paleozoic petroleum reservoirs in Saudi Arabia and is considered a potential shale gas resource. The study aims to evaluate the prospectivity and improve the production potential of Qusaiba shale by defining the lithofacies and mineralogy as controlling factors for brittleness and other mechanical parameters.
The continuous 30 feet subsurface cores and log data of Qusaiba Shale from Rub’ Al-Khali Basin were utilized for the study. Geological characteristics on the core were fully demonstrated in terms of size, mineralogy, color, primary structures and diagenetic features to identify lithofacies. In addition, 30 thin sections were used to study micro scale geological characteristics. The powder X-ray diffraction (XRD) was used to determined the mineralogical compositions. Surface morphology visualization and elemental analysis were performed using the scanning electron microscope supplemented with energy dispersive spectroscopy (SEM-EDS). Acoustic velocity measurements and compressive strength tests were performed on 15 core plugs (5 from each lithofacies).
Based on the above-mentioned analyses, three lithofacies were identified: (1) Micaceous laminated organic-rich mudstone facies (Lithofacies-I), (2) Laminated clay-rich mudstone facies (Lithofacies-II), and (3) Massive siliceous mudstone facies (Lithofacies-III). Mineralogical composition resulted in variable amounts of quartz ranging from 39 to 40, 45-55 and 60 to 78% for Lithofacies-I, II and III, respectively. Lithofacies-I having relatively lower quartz and higher clay percentage and total organic content (12% by volume) exhibited low stiffness. Mineralogy- and elastic parameters-based brittleness indices exhibited ductile behavior of this lithofacies. Lithofacies-II with relatively higher quartz (45 to 55%) and lower clay contents and TOC (3-5%) than Lithofacies-I resulted in relatively higher stiffness and brittleness. The brittleness index exhibited brittle behavior for silica rich Lithofacies-III (low TOC< 3%) as reflected by Young's modulus (average 32 GPa) and low Poisson's ratio (average 0.25). Hence, it is concluded that mineralogy and geological characteristics are the main controlling factors on mechanical properties and brittleness. The integration of three essential disciplines i.e. geology, mineralogy and geomechanics, plays the key role to better evaluate the production potential by highlighting the sweet spots within the heterogeneous shale gas reservoirs.
Reservoir evaluation of source rock is still a challenge because the geochemical assessment of the kerogen content is complicated and time consuming. Existing traditional methods to characterize kerogen involves the removal of inorganic minerals which is a critical preliminary step. The incomplete isolation of kerogen may introduce some errors and uncertainties in kerogen content estimation. The alteration of kerogen microstructure during this process has also been documented. The current approach still requires input from geochemical measurement of total organic carbon (TOC) while the conversion of TOC to kerogen volume requires the precise value of a conversion factor and kerogen density. Overall, there is yet a standard lab or field scale approach to characterize kerogen content. These difficulties and uncertainties prompt the motivation to attempt a new methodology to quantify the kerogen content of unconventional shale from porosity measurements.
Porosity is the basic rock property that is related to the volumetric average of pore space. The distinction between the total and effective porosity is meaningless for shale and this characteristic property has enabled the preservation of its organic content. The recent popularity and growth of different measurement techniques is in part closely tied to the near zero porosity of shale. Two special cases of practical interest are NMR and density porosity measurements which can both be measured in the rock physics lab and well logs. NMR porosity is sensitive to 1H which is naturally enriched in kerogen whereas density porosity must be calibrated to the mineral matrix.
Based on porosity measurements, the emerging aproach is that the kerogen volume fraction is the contrast between NMR and density porosity. Although, the theoretical basis of this approach is not satisfactory, it is straightforward and far less complicated than the existing approaches to quantify kerogen content. We investigate this concept further based on laboratory measurement. We conducted laboratory measurements of NMR porosity, bulk density, grain density and TOC on Qusaiba shale to characterize its kerogen content. In our approach, we conducted the NMR experiment on the shale samples in the dry state without fluid saturation.
By International Petroleum Technology Conference (IPTC) Monday, 25 March 0900-1600 hours Instructors: Olivier Dubrule and Lukas Mosser, Imperial College London Deep Learning (DL) is already bringing game-changing applications to the petroleum industry, and this is certainly the beginning of an enduring trend. Many petroleum engineers and geoscientists are interested to know more about DL but are not sure where to start. This one-day course aims to provide this introduction. The first half of the course presents the formalism of Logistic Regression, Neural Networks and Convolutional Neural Networks and some of their applications. Much of the standard terminology used in DL applications is also presented. In the afternoon, the online environment associated with DL is discussed, from Python libraries to software repositories, including useful websites and big datasets. The last part of the course is spent discussing the most promising subsurface applications of DL.
Late Cretaceous plate collision and subsequent ophiolite emplacement at the eastern margin of the Arabian Plate led to compressional events, responsible for the formation of the structural traps of the giant fields onshore Abu Dhabi. In addition, the onset of this structuration during the Turonian caused the configuration of some hence-to-forth overlooked features (pinch-outs and siliciclastic sand deposits). The objective of the present work is to analyze the origin and distribution of these geometries and their potential to constitute stratigraphic traps.
To understand the genesis and the distribution of these geometries which formed during the Late Cretaceous, we used a combination of large scale regional stratigraphic well correlations and seismic lines interpretation, together with age dating, core description, and well data information. The methodology consisted in using this data for detailed mapping of relevant time stratigraphic intervals, placing the mapped architecture in the context of the global eustatic sea levels and major geodynamic events of the Arabian Plate.
The ensuing plate collision during the Turonian in eastern plate margin was felt hundreds of kilometers into the plate over Abu Dhabi area. Buckling and uplifting created paleo-relief which caused exposure and erosion of Wasia Group sediments in northern and eastern areas of Abu Dhabi Emirate. This led to the configuration of some overlooked stratigraphic features: eroded rims and lateral facies change against structural dip (Mishrif Formation); onlap pinch-outs onto flanks of major structures (Ruwaydhah Formations) and the deposition of siliciclastic sand deposits of the Tuwayil Formation. The features follow low relief areas along contemporaneous synclines in onshore Abu Dhabi and salt withdrawal synclines in offshore Abu Dhabi.
With further advance of the obducting ophiolites, a foredeep developed leading to drowning of the previously exposed structures. Shales and interbedded limestones of the Laffan Formation were unconformably deposited over the eroded Wasia Group during the Coniacian transgression associated with the generation of this foredeep. They are now forming an extensive regional seal for these deposits forming potentially stratigraphic traps.
We postulate that the rejuvenation of the Shilaif intrashelf basin during the Late Turonian and the deposition of the (Ruwaydhah Formation) was aborted at its early stages by periods of uplift, erosion and their successive erosional unconformities, features that are confirmed on the crest of several eastern area structures. This provided the context for the generation of pinch-out geometries that constitute potential stratigraphic traps downdip of major structures in Abu Dhabi.
Very little has been published about the outline and architecture of these stratigraphic traps in Abu Dhabi and the detailed circumstances that led to their genesis, topics that are comprehensively analyzed in the present work.
The task of reliable characterization of complex reservoirs is tightly coupled to studying their microstructure at a variety of scales, which requires a departure from traditional petrophysical approaches and delving into the world of nanoscale. A promising method of representatively retaining a large volume of a rock sample while achieving nanoscale resolution is based on multiscale digital rock technology. The smallest scale of this approach is often realized in the form of working with several 3D focused-ion-beam–scanning-electron-microscopy (FIB-SEM) models, registration of these models to a greater volume of rock sample, and estimation and scaling up of model local properties to the volume of the entire sample. However, a justified and automated selection of representative regions for building FIB-SEM models poses a big challenge to a researcher. In this work, our objective was to integrate modern SEM and mineral-mapping technologies to drive a justified decision on location of representative zones for FIB-SEM analysis of a rock sample. The procedure is based on two experimental methods. The first method is automated mapping of sample surface area with the use of backscattered electrons (BSEs) and secondary electrons (SEs); this method has resolution down to nanometers and spatial coverage up to centimeters, also referred to as large-area high-resolution SEM imaging. The second method is automated quantitative mineralogy and petrography scanning that allows covering sample’s cross section with a mineral map, with resolution down to 1 µm/pixel. Data gathered with both methods on millimeter-sized cross sections of rock samples were registered and integrated in the paradigm of joint-data interpretation, augmented with computer-based image-processing techniques, to provide a reliable classification of nanoscale and microscale features on sample cross sections. The superimposed SEM and mineral-map images were combined with physics-based selection criteria for reasonable selection of FIB-SEM candidates out of a great number of potential sites. In the result, a semiautomated work flow was developed and tested. Demonstration of the work flow is made on one of Russia’s most promising tight gas formations, where the characteristic dimension of void-space objects spans from a single nanometer to millimeters. An example of an optimized site selection for FIB-SEM operations is discussed.
This paper focuses on a tight carbonate reservoir in a giant field in Abu Dhabi by identifying shortcomings in conventional modeling strategies for geomechanics and demonstrating the benefits of continuous core data to build more reliable 1-D Mechanical Earth Models (MEM). A 1-D MEM was built from the sonic wireline log, which shows significant difference with a profile of ultrasonic P-wave velocity (Vp) measured on cores. However, results of rock mechanical tests (RMT) on plug samples (including ultrasonic Vp measurements at different stress conditions, and stress-strain curves from triaxial tests) are consistent with the core-based Vp profile. We investigate the impact of stresses, resolution and fluid saturation on sonic velocities to reveal the possible shortcomings of sonic wireline logs as an input for geomechanical models and the greater relevance of using core based ultrasonic velocities measured on dry cores for the upscaling of static elastic moduli. Finally we propose an empirical relation to correct sonic wireline logs for geomechanical modeling in offset wells. The following conclusions can be drawn from this study: 1. The core based Vp profile, which is highly consistent with the RMT results, ultimately leads to opposed trends in the in-situ horizontal stresses predictions compared to those of a 1-D MEM based on the non-calibrated wireline sonic log. 2. Only unrealistic reservoir stress conditions could reconcile ultrasonic Vp measured on plugs at different stress states with wireline sonic velocities; 3. Using a low resolution Vp profile at reservoir stress conditions (combining Vp from plug samples and core based continuous Vp profile), we show that differences in stress only partially explain the discrepancy between velocities measured on plugs and wireline sonic velocities.
The in-situ stress state in a rock mass is widely recognized as being of major importance in unconventional field. The inherent variation of stress distribution associated with geological environments is widely recognized as being a key factor in an unconventional field; hence, the need to understand from the basin-scale phase is critical. The three main ingredients needed to formulate a model for the mechanics of the porous sediments, are the concepts of bulk stress, pore pressure and compaction. Most available rock-stress-based numerical engines uses default laboratory properties for the set of lithology's in their library. However, understanding the mechanical properties of the lithologies and applying such to the model makes the result more representative of the local geology.
This paper is an update on the previously published model (
Results reveal a dynamic representation of the three principal effective and total stresses within the studied formations. The maximum stress shows a NE-SW trend in the synclinal area and N-S trend on the anticlinal structures, the medium stress shows N-S trend on the synclinal structure with an E-W and NW-SE trend on Well A and Pseudo-well A wells respectively. The minimum stress reveals a NW-SE direction on the synclinal area and N-S trend on both flanks. The model also shows an improved pore pressure result ranging from 26.97 – 42.50 MPa (with 28.46 MPa average values within layers of interest) revealing ~ 1450 psi (10 MPa) difference when compared to the previous model where rock stress modeling was not performed.
With the shale gas (SG) and Light Tight Oil (LTO) development, the US has become gas independent and has halved oil dependency. This revolution was based on four pillars: knowledge of the subsurface, open and competitive market, full government support and favorable mining law.
Outside the US, SG and LTO development cannot rely on the same pillars. The purpose of this paper is to analyze the motivations and the possible blocking factors that could encourage five countries/regions to develop (or not) their unconventional resources.
Gas exporter until 2004, Argentina imports today gas from Bolivia and LNG from the Middle East in a subsidized local market. These imports could ultimately stifle Argentina's public finances. Consequently, the authorities want to quickly develop the huge potential of the Vaca Muerta, one of the best source rocks in the world. Nevertheless, the cost of imported equipment and products as well as the monetary stability of the local currency could be blocking factors.
Saudi Arabia, the world's second largest oil producer, consumes nearly 1 Mbopd to satisfy the increasing electricity demand. Unlike Iran or Qatar, Saudi Arabia has not sufficiently developed its gas potential. Therefore, it intends to extract its unconventional resources in the future, in particular the source rock of the Ghawar field. Water supply for hydraulic fracturing could be a blocking factor.
China is facing a double challenge: reducing its GHG emissions by displacing its power generation from coal to gas/renewable while keeping its energy dependence at an acceptable level. Therefore, China is looking forward to develop its unconventional potential which is expected to be comparable to that of North America. The resources are located in the Tarim Basin (North West) and the Sichuan Basin (South East). The depth, the complexity of geological structures, the remoteness and the aridity of the basins make the field operations difficult and expensive.
Russia is now 70% dependent on its oil and gas revenues. The potential of Russia's unconventional resources is mainly associated with the gigantic Bazhenov formation located in Western Siberia. The Russian authorities, who wish to offset their declining conventional fields, have launched a legislative process associated with tax incentives. Permafrost and subartic conditions can be blocking factors as drilling and fracturing are required all over the year.
In the last 30 years, competitiveness in Europe was weighed down by an oil and gas bill that represents 75% of its debt. Developing the local resources to avoid becoming 100% dependent on the suppliers is of strategic importance. However, the development costs, the regional urbanization and the societal opposition are potential blocking factors.
The development of reservoirs that are not in hydrostatic equilibrium or that have suffered deviations from primary drainage over geological time requires appropriate challenges to standard assumptions in order to optimize the field's full potential. Such circumstances are more frequent than usually acknowledged since the Earth is not static, structures get buried or change with tectonic activity and fluids rearrange themselves to achieve a state of minimum potential energy. The focus of this paper is three fold: a) highlight geological processes that may affect fluid distribution and pressure regime in a reservoir; b) provide a template workflow and diagnostic tools for identification of alternative fluid-fill cycle and equilibrium state scenarios; c) illustrate through actual field examples the relevance of recognising tectonic imprint on fluid distribution, in particular for reservoirs with low permeability, oil wettability or low porosity.