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Collaborating Authors
Results
Successful Analytical Modeling of a Complex Dry Gas Field to Identify Potential Infill Opportunities
Syed, Rafiah (United Energy Pakistan Limited) | Ejaz, Muhtashim (United Energy Pakistan Limited) | Azeem, Abdul (United Energy Pakistan Limited) | Mehmood, Saad (United Energy Pakistan Limited) | Amjad, Muhammad (Prime Pakistan Limited) | Sirati, Muhammad Attar (Pakistan Petroleum Limited) | Ashraf, Zaid (OGDCL) | Yousaf, Haleem (OGDCL)
Abstract The objective of the study is analytical modeling of a dry gas reservoir, with more than 30 drilled wells and 15+ years of production history, underlain by thick tight gas zone, that is highly compartmentalized (both structural and stratigraphic) and heterogenous (laterally and vertically). The multi tank material balance model is created to address the major uncertainties within the compartments such as Fault Transmissibility, Aquifer Strength, Early Water Influx, Tight Gas Support, and its quantification by the integration of all the geological, fluid, rock, pressure, and the production data. Some of the structurally up-dip wells are watered out however down-dip wells continue to produce gas at reasonable rates with complete stability in the reservoir pressure. The model has been history matched with multiple scenarios and showed that the pressure recharging observed in a certain compartment is from an additional GIIP feeding into the compartment through the underlying tighter zone rather than laterally from the other compartments. A weak aquifer encroachment in the same compartment is from an adjacent compartment having moderate water drive through fault breach. Compartments are history matched with adequate pressure and Water Gas Ratio (WGR) by manipulating productivity indices for individual wells, modifying aquifer strength, inter-compartment transmissibility, pseudo relative permeability curves and impact of tight gas recharging. The quantitative estimation of minimum connected GIIP is performed by balancing the support through encroaching aquifer and tight gas recharging. The scope included the estimation of the minimum connected Gas Initially in Place (GIIP), ascertain aquifer strength and direction as well as pressure recharging within the different compartments using pressure and production data. The study assisted in capturing the communication between the compartments and evaluation of remaining potential of the field. The results would then be used in subsequent numerical modelling with the possibility of increasing overall recovery from the field.
Dynamic Wettability Alteration at Pore-Scale Using Viscoelastic Surfactant/Chelating Agents Systems
Ahmed, M. Elmuzafar (Petroleum Engineering Department, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals, Dhahran, Saudi Arabia) | Sultan, Abdullah S. (Petroleum Engineering Department, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals, Dhahran, Saudi Arabia)
Abstract The role of wettability is crucial in the extraction of hydrocarbons as it determines how well the oil adheres to the rock surface, directly impacting the efficiency of the extraction process. Numerous studies have been conducted to modify the wettability of rocks to a favorable state. In this study, we delve into the microscopic level to observe the actual process of altering the contact angle during flooding using microfluidic technology within a glass micromodel. Initially, the micromodel is saturated with formation water and subsequently displaced by oil to establish the initial oil saturation. The microfluidic setup consists of a precise pump for flood control and a high-speed microscope to capture images for later analysis using image processing software to obtain the actual contact angle. The contact angle is measured at five arbitrary locations, and the average is calculated at specific time intervals based on image analysis. Three different fluid systems were utilized: pure Viscoelastic Surfactant (VES), VES with DTPA, and VES with GLDA. The concentration of these systems was selected based on optimal rheology and interfacial tension performance. The contact angle was measured at various injection stages to observe its dynamic change from the initial state to the final state and assess the resulting recovery from each fluid system. The pure VES system modified the wettability from slightly oil-wet to slightly water-wet and achieved a 48% recovery of the original oil in place (OOIP). On the other hand, the addition of DTPA altered the wettability from slightly oil-wet to extremely water-wet; however, this did not lead to higher recovery, and water breakthrough occurred, reducing the sweep efficiency with a 45% recovery. The GLDA VES system altered the wettability to moderately water-wet, which proved to be the most favorable wettability condition, resulting in a 56% ultimate recovery. This investigation successfully demonstrated the effectiveness of using VES-assisted chelating agents in altering rock wettability and increasing oil recovery at the pore scale.
- Africa (0.68)
- South America > Brazil (0.46)
- Asia > Middle East (0.28)
Abstract This paper will discuss methods, best practices, and lessons learned to optimize a highly successful Saudi Aramco Upstream Professional Onboarding Program (UPOP), meeting the business needs to deliver the same program in a shorter time frame. The need to optimize the program emerged due to an influx of new hires in conjunction with a global pandemic that reduced the number of participants per class due to social distancing measures. UPOP was originally designed to walk newly hired Upstream professionals through the upstream lifecycle by using a project that demonstrates the upstream workflow. Participants in this program gain confidence by working on real projects and are expected to give presentations to senior employees explaining the key decisions at each stage of the upstream lifecycle. These activities enhance their skills in leadership, networking, presentation, and communication. This project-based onboarding program was originally designed by the Upstream Professional Development Center (UPDC) as an 8-week program. As the program has reached a mature stage with over forty (40) successful deliveries and multiple opportunities to apply participant feedback, it was recently optimized to five (5) weeks for in-class delivery without sacrificing quality. The global pandemic pushed the need for a 3-week Virtual Instructor Led Training (VILT) version. The development process involved updating and developing program content to remove scrap learning while enhancing key outcomes. The UPDC team of geoscience subject matter experts (SMEs), petroleum engineering SMEs, soft skills instructors, and learning technology professionals identified and removed course content that was planned to be covered in other courses planned in the young professionalsโ prescribed learning curriculum. The revised UPOP optimized participant in-class training to maximize participantsโ on-the-job performance by removing redundancies and providing new hires with an overview of the company's upstream lifecycle. Additionally, creating an optimized version of the onboarding program has made it possible to offer the program four times per year to meet the increasing demand for onboarding new hires. The current customized UPOP is designed to minimize the amount of time required for new hires to complete the program without sacrificing content for on-the-job tasks and objectives. The number of sessions per year has doubled, and the number of participants has increased by 75% since the program's inception in 2010.
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Management > Professionalism, Training, and Education > Personnel competence (1.00)
- (2 more...)
The accurate calculation of porosity at the wellbore is essential for an accurate calculation of original oil in place (OOIP) or original gas in place (OGIP) throughout the reservoir. The porosity and its distribution also need to be calculated as accurately as possible because they are almost always directly used in thewater saturation (Sw) andpermeability calculations and, possibly, in the net pay calculations. In most OOIP and OGIP studies, only the gross-rock-volume uncertainties have a greater influence on the result than porosity does. Occasionally, where porosity estimates are difficult, porosity is the leading uncertainty. Fractured and clay-mineral-rich reservoirs remain a challenge. For this discussion, it is assumed that the core data have been properly adjusted to reservoir conditions, that the data from various logs have been reviewed and validated as needed, and that all of the required depth-alignment work has been completed. There are a few preliminary steps in the use of routine core porosity data over the reservoir interval.
- North America > United States > Texas (0.28)
- Europe > United Kingdom > Irish Sea > East Irish Sea > Morecambe Bay (0.15)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.96)
- Geology > Mineral > Silicate > Phyllosilicate (0.96)
- Europe > United Kingdom > Irish Sea > East Irish Sea > Morecambe Bay > East Irish Sea Basin > Morecambe Bay > Block 110/8a > Morecambe Field > South Morecambe Field (0.99)
- Europe > United Kingdom > Irish Sea > East Irish Sea > Morecambe Bay > East Irish Sea Basin > Morecambe Bay > Block 110/7a > Morecambe Field > South Morecambe Field (0.99)
- Europe > United Kingdom > Irish Sea > East Irish Sea > Morecambe Bay > East Irish Sea Basin > Morecambe Bay > Block 110/3a > Morecambe Field > South Morecambe Field (0.99)
- Europe > United Kingdom > Irish Sea > East Irish Sea > Morecambe Bay > East Irish Sea Basin > Morecambe Bay > Block 110/2a > Morecambe Field > South Morecambe Field (0.99)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract Estimated Ultimate Recovery (EUR) of oil and gas projects is an important quantity to track over the project life to help understand and mitigate any deviations in project performance. In general, the range of uncertainty narrows over time as more data is available to constrain the estimates. However, this is not always the case. This paper presents three examples covering both gas and oil fields at different stages of their lives, which show how EUR and the corresponding range of EUR uncertainty varies over the life of each field. The lesson from these examples is that the range of uncertainty tends to be too narrow, both in the appraisal phase, as well as in the production phase. EUR estimates may be too narrow in the appraisal phase due to the lack of available datapoints to constrain the volumetric based assumptions. In the production phase where forecasts are often based on simulation models, a limited number of geological realizations will naturally constrain the range of results from simulation, even when many realizations of lesser parameters are conducted. In one of the examples, there was a sudden increase in the range of EUR, and the paper discusses the reasons for this, which are mostly attributed to additional data. The paper further notes the possibility of an anchoring bias underlying the results and provides multiple reasons on why EUR and Reserve estimates may be affected by this bias, such as continuity of the project team, as well as internal/external pressures. It is thus important for technical personal, management, investors and lenders to keep an open mind, and not be pigeonholed into overly narrow ranges of uncertainty. Be brave to challenge the estimator to justify apparently narrow ranges of EUR uncertainty, as well as any suspected anchor bias in the ever-evolving EUR estimates.
Maximizing Gas Resources and Monetization Through Gas Cap Blow Down - A Late Field Life Strategy for Sustainable Gas Supply in Peninsular Malaysia
Azman, Mohd Fairuz (Petronas Carigali Sdn. Bhd.) | Mohamad Ruzlan, Nur Syaffiqa (Petronas Carigali Sdn. Bhd.) | Basri, A Hakim (Petronas Carigali Sdn. Bhd.) | Kumar, Sanjeev (Petronas Carigali Sdn. Bhd.) | Tunku Kamaruddin, Tunku Ahmad Farhan (Petronas Carigali Sdn. Bhd.) | Kosnon, Nur Khairina (Petronas Carigali Sdn. Bhd.) | Salleh, Khiril Shahreza (Petronas Carigali Sdn. Bhd.)
Abstract Field A is producing from natural depletion drive oil reservoirs with large gas cap. The field was under production curtailment, governed by gas-oil-ratio (GOR) limit to preserve the reservoir gas cap size. As the field continues to produce, the oil rate has declined while GOR increased exponentially. The reservoirs were at risked of being idle when the existing producers were forced to be shut-in due to GOR limit. This paper provides an insight of a late field life strategy in turning reservoir management constraints into business opportunity for more sustainable and economical domestic gas supply in Peninsular Malaysia. Firstly, a temporary GOR relaxation was obtained with an objective driven data acquisitions were in place to monitor the reservoir performance. Concurrently, a Recovery Factor (RF) benchmarking study has also been conducted to identify for any infill oil development potential. A network model comprises reservoir, well and surface facilities constraints was developed, validated and history matched using the latest production and reservoir pressure data obtained. Subsequently, production sensitivities analysis was conducted at various GOR limit including gas cap blow down (GCBD) option, evaluated at different abandonment pressure to determine the best integrated field optimization opportunity. Reservoir performance analysis during the temporary GOR relaxation confirms the oil production was not significantly impacted, the water cut remains stable, and the pressure depletion was minimal. The field RF has also exceeded the benchmark from other reservoirs with similar complexity and drive mechanism within the region. Hydrocarbon in-place validation suggests that neither oil infill development nor behind casing opportunity presence as the reservoirs has reached its optimum recoverable volume. Producing the field without GOR limit increases the RF of gas by 10% and continues oil monetization by another 2%, without risked the reservoir from being idle. In view of reservoir performance and critical high gas demand in Peninsular Malaysia, a decision was made to revise the production strategy to GCBD mode. A prudent reservoir management demands a continuous, integrated, and dynamic process to maximize value from a reservoir over time. Production strategy should be revised upon new data becomes available from reservoir surveillance. The findings are critical in making timely recommendations on subsurface exploitation to deliver business needs for maximum value creation.
- Asia > Malaysia (0.92)
- North America > United States > Texas (0.28)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Friendswood Field > Frio Formation (0.99)
- Asia > Indonesia > Sumatra > South Sumatra > South Sumatra Basin > Gunung Kembang Field (0.99)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- (5 more...)
ABSTRACT: Tunnelling and underground mine development in high-stress conditions are exposed to potential rockburst hazards. Rockburst risk management may include multiple hazard control and/or exposure management strategies. Rockmass preconditioning, such as destress blasting, is a tactical approach to hazard control by introducing blast-induced fractures to the rockmass. Introducing fractures softens the rockmass and reduces potential stored strain energy. This paper explores a case study where a large-magnitude rockburst occurred in the floor of a mine tunnel located approximately 2km below the surface, in a strong, massive rockmass. Subsequently, destress blasting was implemented in all active development headings for risk mitigation. This paper presents a geotechnical study to optimize the utilization of destress blasting. A detailed numerical modeling investigation with implicit representation of blast damage is done using a calibrated FLAC3D model. The influence of destress blast design on rock burst hazard potential is numerically studied and discussed. INTRODUCTION Preconditioning of rock mass using destress blasting is a tactical approach to alleviate strain burst potential in a rock mass by introducing new fractures which in turn leads to lowering the stiffness of the rock mass and thus dissipating the excessive stored strain energy in the immediate excavation periphery (OโDonnell, 1999). The destressing fractured zone, sheds stress concentration away from development heading. A deep gold mine complex experienced a 1.0Mw seismic event in an advancing tunnel located in fairly strong and massive basalt, resulting in approximately 20 tonnes of material displaced from floor. Several non-damaging macro events (>0.2Mw) were also experienced leading up to the floor burst event during advance of this particular mine tunnel. Following the occurrence of the floor burst event, destress blasting was implemented in all active development headings as a means of hazard management. This introduced significant operational challenges and slowed advance rates.
- Materials > Metals & Mining (1.00)
- Energy > Oil & Gas > Upstream (0.96)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (0.90)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (0.61)
Estimation of the Stimulated Reservoir Volume by Rate Transient Analysis for Marcellus Shale Horizontal Wells
Parrish, Amanda (West Virginia University, Morgantown, West Virginia, U.S.A) | Sattari, Arya (West Virginia University, Morgantown, West Virginia, U.S.A) | Aminian, Kashy (West Virginia University, Morgantown, West Virginia, U.S.A) | El Sgher, Mohammed (West Virginia University, Morgantown, West Virginia, U.S.A) | Ameri, Samuel (West Virginia University, Morgantown, West Virginia, U.S.A)
Abstract Shale reservoirs are most commonly developed by horizontal wells coupled with multi-stage hydraulic fracturing to create a stimulated volume around the well. The interference among the hydraulic fracture stages in a horizontal well leads to an early boundary-dominated flow (BDF) period within the stimulated reservoir volume (SRV). The application of the rate transient analysis to the production and flowing pressure data from this period can provide an estimate of the gas in place in SRV. A realistic model for a horizontal Marcellus shale well, with multiple fracture stages, was utilized in this study to simulate gas production and the flowing pressure data. The simulated data by the model were then analyzed by rate transient analysis (RTA) techniques to identify the early BDF period and to estimate the gas in place in SRV. To investigate the impact of the adsorbed gas, shale compaction, and hydraulic fracture spacing on the estimated gas in place in SRV, several sets of the production and flowing pressure data were then simulated and analyzed. The analysis of the data from the early BDF period provided reliable estimates of the gas in place in SRV. These estimates are impacted by the shale compaction but not significantly by the adsorbed gas and fracture stage spacing. When the fractures are stages are closely spaced, the early BDF period established early and last for a relatively short time. Consequently, the identification of the early BDF becomes difficult leading to uncertainty in the estimated of the gas in place in SRV. However, when the fracture stages are spaced widely, the early BDF may last for a longer time and can be identified more readily.
- North America > United States > Pennsylvania (0.95)
- North America > United States > West Virginia (0.89)
- North America > United States > Virginia (0.75)
- (3 more...)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation > Marcellus Shale Well (0.99)
- (3 more...)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Re-Inventing Pressure Retained Core Acquisition for Advanced Reservoir Property Determination
Wunsch, D (CORSYDE International, Berlin, Germany) | Rothenwรคnder, T. (CORSYDE International, Berlin, Germany) | Anders, Erik (CORSYDE International, Berlin, Germany) | Deutrich, T. (CORSYDE International, Berlin, Germany) | Brown, D. (Core Laboratories, Houston, United States of America) | Ramoin, J. (Core Laboratories, Houston, United States of America) | Verret, C. (Core Laboratories, Houston, United States of America) | Mukherjee, P. (MEOFS Middle East Oilfield Services, Kuwait City, Kuwait)
Abstract Innovation has always played a key role in past industry transition periods and helped to unlock the true potential of new technologies. For this reason, it is crucial to utilize and adapt these past experiences to effectively approach and tackle the challenges any operator is currently facing. The challenges range from understanding production behavior of reservoirs at any point of their lifecycle as well as CCS scenarios. Whenever injection is considered at any stage throughout secondary-, tertiary recovery stage or the general โre-utilizationโ of the reservoir for storage respectively a thorough assessment is required. This increases the demand for sufficient data acquisition methods or workflows to overcome numerous shortcomings. With full bore core data being one of the key elements for ground truthing any data set used for reservoir modelling and project decision making (Saucier et al. 2022), the conventional methods utilized to acquire these core samples have a variety of weaknesses. While these standard methods are well established, more advanced coring methods are required to provide more comprehensive datasets for reservoir description. The method discussed in this paper aims to address these demands by delivering a high-quality in-situ core sample which is then processed on-site and introduced to best-fit lab workflow. Different special methods in the field of core acquisition are compared and strengths and weaknesses provide the context for potential need for a large diameter pressure coring technology. How this technology directly helps operators to better understand their reservoirs in any of the above-mentioned reservoir scenarios will be explained by describing different exemplary fields of application. These descriptions range from more accurate saturation determination of ROZs in depleted formations to acquiring in-situ PVT data for recombination of fluid volumes in conventional reservoirs to actual OGIP and GOR measurements in unconventional reservoirs. With the ongoing shift in the oil-&gas industry, pressure coring technology also has a high potential to become an important tool in storage efficiency assessments in CO2 injection wells for CCS applications. The study outlines how pressure retained core samples can contribute to reduce uncertainties and improved datasets which are needed in cases where the design of reservoir models require comprehensive knowledge of the entire spectrum of reservoir data. The proposed best practices are backed up by findings from recent achievements as well description of field activities in different applications. The study aims for giving an overview on how pressure coring technology enhances the available toolbox for downhole data acquisition and how the technology brings added value to the industry in an environment when more stringent economics rely on more accurate data validation of any asset.
- Europe (1.00)
- Asia > Middle East > Kuwait (0.28)
- North America > United States > Texas (0.28)
- North America > United States > California (0.28)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Raudhatain Field > Upper Burgan Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Raudhatain Field > Mauddud Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Raudhatain Field > Lower Burgan Formation (0.99)
- (10 more...)
- Well Drilling > Drilling Operations > Coring, fishing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- (4 more...)
Maximizing Hydrocarbon Potential in Marginal Field Using Data Integration Techniques, A Case Study from the Saraswati Field, Barmer Basin, India
Kumari, B (Cairn Oil & Gas, Vedanta Ltd.) | Chatterjee, D. (Cairn Oil & Gas, Vedanta Ltd.) | Kumar Singh, S. (Cairn Oil & Gas, Vedanta Ltd.) | Gollapudi v s, K. (Cairn Oil & Gas, Vedanta Ltd.) | Somasundaram, S. (Cairn Oil & Gas, Vedanta Ltd.) | Chakraborty, S. (Cairn Oil & Gas, Vedanta Ltd.)
Abstract Saraswati Field, located in south-central part of hydrocarbon prolific Barmer Basin is a marginal field and has been developed with a cautious approach to address high degree of uncertainty. The paper summarizes the robust workflow considered for a complete phased re-development approach by leveraging state-of-the-art multi-disciplinary data integration techniques aiming to access the true potential through maximizing the productivity while mitigating uncertainties associated with reservoir characterization for minimizing risk. The stratigraphy of the Saraswati field can be divided into five different zones based on sedimentological analysis, Barmer Hill, Fatehgarh Zone-1, Fatehgarh Zone-2, Ghaggar Hakra Zone-1, and Ghaggar Hakra Zone-2. The primary focus of this paper is Fatehgarh Zone-1 reservoir, which is a mix of sandstones and shale deposited following a major hiatus / non-deposition of Late Cretaceous age. The upliftment and erosion lead to thinning of Fatehgarh towards northern part of the field. A conceptual geological model was prepared in the light of data integration technique including reprocessed seismic data, resulting in improved structural and stratigraphic control. Detailed core studies have provided a better understanding of lithofacies, leading to a substantial increase in net-to-gross. Additionally, production data revealed that the well is drawing oil from a larger volume, further supporting the geological model's assumptions. A customized seismic reprocessing flow helped in enhancing the frequency content with better temporal resolution and higher signal to noise ratio. Furthermore, the seismic attribute study of the Fatehgarh interval had established that the sand prone zones are characterized by low RMS amplitude, which was also confirmed by low instantaneous frequency and low amplitude in the Spectral Decomposition study. Core data analysis in Fatehgarh formation suggested presence of considerably more reservoir facies in the system compared to what is visible in wireline log. Drill cuttings data from wells across the field also indicated presence of higher proportion of sand and silt. Image Log data supports this fact indicating presence of thin bed pay which are beyond log scale resolution. Based on the production performance of Saraswati field, material balance model was worked upon considering production data and shut-in pressure for Saraswati wells for back calculating the in-place volume. The stabilized shut-in pressure in producer wells draining from Fatehgarh reservoir have indicated a three times upside in STOIIP for Fatehgarh reservoir. An updated static model was prepared capturing all the above- mentioned studies which results in nearly three times upside in the STOIIP estimation and opens opportunity for further development plan with more confidence on reservoir distribution. The project has successfully integrated multi-disciplinary information from Geology, Geophysics, Petrophysics and Reservoir Engineering, by creating a comprehensive framework for the associated uncertainties of the marginal field with limited well penetrations. Through this synchronization, the project has achieved critical inputs towards a full field development with implementation of newer concepts like planning near horizontal well with hydrofracking for thin bed reservoir to unlock the full potential.
- Geology > Sedimentary Geology (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.49)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.35)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (16 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)