Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Statistical Aggregation - A Simple Tool in the E&P Industry for Estimating the Economic Value of a Complex Project
Khan, I. (Pakistan Petroleum Limited, Karachi, Pakistan) | Aslam, M. A. (Pakistan Petroleum Limited, Karachi, Pakistan) | Hasan, A. (Pakistan Petroleum Limited, Karachi, Pakistan) | Palekar, A. H. (Pakistan Petroleum Limited, Karachi, Pakistan)
Economic evaluation is an important decision-making tool for drilling an exploratory well. The paper is focused on a well drilled in the Mesopotamian basin in Iraq. Before its drilling, it needs to be passed through the technical and commercial gates. The prospect contains multiple (five) reservoir targets. To properly evaluate its technical and commercial potential, it was prudent to give weightage to each reservoir. To assess the Expected Monetary Value (EMV) of the prospect, a total of 32 economic cases needed to be built in the decision tree which makes the working & decision complicated for the management. It may be noted that in Iraq most companies operate under Service Contracts which itself is not common in the industry to assess commerciality. To cater for the above, a statistical aggregation methodology was adopted in which hydrocarbon volumes (HCIIP) and the chance of success (CoS) of five individual reservoirs were transformed into one number. Accordingly, the economics was performed on this number and the corresponding prospect EMV is calculated. The results were presented to the technical and commercial gates and were accepted by the management and approval was granted. It may be noted that results from statistical aggregation were rechecked by performing the economics on 32 cases and both results were found comparable. Therefore, this technique was used to quickly assess the EMV of a complex project for decision making and the same technique can be helpful in commercial decision-making of any scale. The fit-for-purpose approach was utilized in view of the complexity of the project. This work will serve as a reference for statistical aggregation in the oil industry, to evaluate the commerciality of the project with multiple reservoirs. The findings can also be used to gauge the feasibility of any farm-in block where multiple leads and prospects are available, and a quick decision is required to ascertain its value.
Key Technologies and Solutions to Manage Risks and Overcome the Deepwater Challenges in an Integrated Services Project in the Gulf of Mexico
Davila, Andres Nunez (SLB, Houston, Texas, United States) | Lopez, Juan Ramon (SLB, Houston, Texas, United States) | Rossi, Lucas (SLB, Houston, Texas, United States) | Lin, Emily (SLB, Houston, Texas, United States) | Giam, David (SLB, Houston, Texas, United States) | Widhihabsari, Martha (SLB, Houston, Texas, United States) | Hill, Jesse (SLB, Houston, Texas, United States) | Jackson, Richard (SLB, Houston, Texas, United States) | Basso, Miguel (SLB, Houston, Texas, United States) | Jaimes, Juan Pablo (SLB, Houston, Texas, United States) | Bouguetta, Mario (SLB, Houston, Texas, United States)
Abstract The deepwater environment is traditionally characterized by high operating costs, making any operational savings extremely valuable when facilitating project development and execution. In a highly volatile oil price environment and while under a long-term commercial relationship, a new strategy was implemented to achieve performance optimization and time reduction. This strategy aimed to attain high efficiency and consistency through the application of an integrated services performance and reward model. The core objective of integrated services projects is to generate synergies for further project optimization, while the goal of a reward model is to promote the utilization of diverse technologies to manage risks and minimize the occurrence of undesirable events. In this paper we aim to describe how various technologies and digital solutions can be integrated to serve risk management endeavors, optimize performance, and meet project-specific needs. The integrated services performance and reward model was designed based on three components: project success criteria, historical nonproductive time (NPT), and key performance indicators (KPIs). Major technologies were evaluated and selected in accordance with the project requirements. Digital solutions were implemented to establish a performance baseline, assist in defining the planned time, and assess project-related risks. Critical tasks involved not only planning but also monitoring the results and comparing them to the KPIs, as well as identifying instances of invisible lost time. In the Gulf of Mexico, characterized by narrow operating windows and frequent lost circulation events, continuous monitoring and control of drilling fluid properties are mandatory, supported by the implementation of digital and automated solutions. In addition, key technologies were introduced for formation characterization and further area development.
Abstract Carbon Capture and Storage (CCS) has gained recognition as a mitigation strategy for reducing the accumulation of atmospheric CO2. However, the injection of CO2 into storage reservoirs can lead to increased pore pressure, which in turn induces stress changes in and around the injection site. These stress changes may give rise to several geomechanical hazards, including caprock failure, ground surface uplifting, and induced seismic activity. To address this concern, we have developed a novel optimization approach aimed at maintaining the caprock integrity during the storage of CO2 in geologic formations under geological uncertainty. The developed workflow integrates advanced numerical optimization algorithms with coupled multiphase flow-geomechanics-fracturing models for simulating the response of the storage reservoir to CO2 injection. Using the geomechanical response of the simulation, we define and quantify the potential caprock failure and CO2 leakage risks. An optimization formulation is used to minimize the risk of caprock fracturing and CO2 leakage by finding the optimal distribution of dynamically changing CO2 injection rates across several wells throughout the injection period. The results are extended to incorporate the uncertainty in the simulation model through ensemble-based optimization. The proposed optimization approach identifies the well injection schedule (flow rate vs. time profile) to minimize the risk of caprock fracturing by distributing the pressure increase in the heterogeneous reservoir. The optimization process is designed to continually enhance the injection strategy, aiming to minimize the potential for caprock fracturing by maximizing the stress differences between the minimum effective stress and the fracture opening stress. The paper highlights the importance of employing coupled flow and geomechanics, along with fracture mechanics, in accurately modeling and predicting the potential CO2 leakage. This approach enables the development of injection strategies that prioritize caprock integrity, effectively addressing the challenges associated with optimizing CO2 storage while minimizing the risk of caprock failure.
- Geology > Petroleum Play Type (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
Multizone Open Hole Gravel Pack Completion with Selective Production Capability in ACG Field โ Azerbaijan
Susilo, Yoliandri (BP, Sunbury, UK) | Dharmadhikari, Khsitij (BP, Baku, Azerbaijan) | Taha, Sherif (BP, Baku, Azerbaijan) | Ismayilova, Ayisha (BP, Baku, Azerbaijan) | Guliyev, Ilkin (BP, Baku, Azerbaijan) | Jafarli, Zaur (BP, Baku, Azerbaijan) | Kerimov, Natig (BP, Baku, Azerbaijan) | Kerimova, Ravana (BP, Baku, Azerbaijan) | Mammadov, Elvin (BP, Baku, Azerbaijan) | Veliyev, Samir (BP, Baku, Azerbaijan) | Wallace, Alex (BP, Baku, Azerbaijan) | Whaley, Kevin (BP, Houston, USA) | Foster, Mike (BP, Houston, USA)
Abstract Azeri-Chirag-Gunashli (ACG) is a giant field located in the Azerbaijan sector of the Caspian Sea. The major reservoir zones are multi layers sandstone formations and weakly consolidated where Open Hole Gravel Pack (OHGP) completions have become the standard design for production wells. To date more than 170 high rate OHGPs have been completed that are producing comingled from multi-layered sandstone formation. As the field matures, problems such as premature water and gas breakthrough are becoming increasingly common requiring the completion system to be inherently flexible to address such issues. The Multi Zone OHGP concept design has been developed to manage this increasing reservoir management complexity. Zonal isolation and selective production capability are achieved by installing combination of multiple Screen PBR and/or open hole packer in combination with seals unit and mechanical sliding sleeve in the inner string at the intermediate completion, and Inflow Control Valve (ICV) at the upper completion. To date, two Multizone OHGP wells have been completed successfully. The Screen PBR system has proved to provide effective zonal isolation or baffling. This system allows flexibility to deal with unexpected reservoir surprise (wet/gas zone) that requires zonal isolation on day-1 without major changes in completion design, thus reducing rig time & operational cost. This paper discusses design, execution, and result of the first two Multizone OHGP completions installed in the ACG Field. Installing multiple Screen PBR to provide baffling against crossflow is a novel concept. This technique does not compromise gravel pack quality or sand control integrity. The success seen with this technique makes a compelling case to further develop the concept on a larger scale in ACG and maximize field recovery.
- Asia > Azerbaijan > Caspian Sea > Apsheron-Pribalkhan Ridge > South Caspian Basin > Azeri-Chirag-Guneshli Field > Azeri Field (0.99)
- Asia > Azerbaijan > Caspian Sea > Apsheron-Pribalkhan Ridge > South Caspian Basin > Azeri-Chirag-Guneshli Field > Guneshli Field > Sabunchi Formation (0.93)
- Asia > Azerbaijan > Caspian Sea > Apsheron-Pribalkhan Ridge > South Caspian Basin > Azeri-Chirag-Guneshli Field > Guneshli Field > Podkirmaku (PK) Formation (0.93)
- (5 more...)
Performance Analysis of Autonomous Inflow Control Valve in a Heterogenous Reservoir Using CO2 Enhanced Oil Recovery
Taghavi, Soheila (Department of Process, Energy and Environmental Technology, University of South-Eastern Norway, Porsgrunn, Norway / InflowControl AS, Porsgrunn, Norway) | Tahami, Seyed Amin (Department of Process, Energy and Environmental Technology, University of South-Eastern Norway, Porsgrunn, Norway) | Aakre, Haavard (InflowControl AS, Porsgrunn, Norway) | Furuvik, Nora C.I. (Department of Process, Energy and Environmental Technology, University of South-Eastern Norway, Porsgrunn, Norway) | Moldestad, Britt M.E. (Department of Process, Energy and Environmental Technology, University of South-Eastern Norway, Porsgrunn, Norway)
Abstract CO2 flooding is a proven method to mobilize the immobile oil in the reservoirs for enhanced oil recovery (EOR). Using CO2 for EOR has been commercially used for several decades in onshore and offshore oil fields in North America, Canada, and Brazil. The injection of CO2 will both improve oil recovery and contribute significantly to reduction of greenhouse gas emissions. Breakthrough and direct reproduction of CO2, and production of corrosive carbonated water are among the challenges with CO2 EOR projects. Breakthrough of CO2 leads to poor distribution of CO2 in the reservoir and low CO2 storage. Carbonated water production results in corrosion of process equipment on the platform. Autonomous inflow control valve (AICV) is capable of autonomously restricting the reproduction of CO2 from the zones with CO2 breakthrough, and at the same time produce oil from the other zones with high oil saturation. In addition, AICV can reduce the production of carbonated water.
- North America > United States > Texas (0.46)
- Europe > Norway > North Sea (0.46)
- South America > Colombia > Putumayo Department > Putumayo Basin > Acordionero Field (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Sognefjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Heather Formation (0.99)
- (65 more...)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Flow control equipment (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Electrical Treatment to Revive Dead Gas Wells due to Water Blockage
Aljuhani, G. (Saudi Aramco, Dhahran, Saudi Arabia) | Almuaibid, A. (Saudi Aramco, Dhahran, Saudi Arabia) | Ayirala, S. (Saudi Aramco, Dhahran, Saudi Arabia) | Qasim, A. (Saudi Aramco, Dhahran, Saudi Arabia) | Yousef, A. (Saudi Aramco, Dhahran, Saudi Arabia)
Abstract The occurrence of water blockage is a major concern for gas wells, which severely impacts the productivity. This phenomenon is due to the prolonged contact of surrounding region around wellbore with water thereby increasing the water saturation relative to gas saturation. Consequently, the pore spaces are completely occupied with water, blocking the flow of gas and thus reducing the gas production. In this paper, we propose electrical treatment as a potential solution to reverse the unforeseen water blocking process and revive dead gas wells to produce desired gas. Electrical treatment involves the placement of two electrodes in between two spaced wells or within the same well, one acting as source and the other as a sink. One of these electrodes acts as a cathode, while the other as an anode to cover a reservoir region of around 2-3 km. After current is applied from power supply to well head, the charge will propagate through metallic casing along the well until pay zone delivering electric current to the reservoir. The electrical induced effects in the reservoir may vary according to the variation of the current density and voltage applied. The tight and small pore throats will be enlarged by the application of electrical current. This results in an increase of pore throat radius due to motion of water molecules, cations and anions thereby releasing some of the water from blocked pore throats. Thus, permeability and subsequently relative permeability to water is increased. The local energy pulses will also cause partial electrolysis forming gas droplets besides enhancing the coalescence of released water droplets to form larger water ganglia. These larger water ganglia will sequentially grow to form a continuous film of water phase to minimize surface energy and ease the movement of water. The electrical treatment operation can take up to 30 hours with a long-lasting effect from 6 months up to 2-3 years. The electrical treatment method described in this paper to revive dead gas wells is a sustainable and eco-friendly solution for easy practice in the field. This cost-effective approach can prolong the life of gas wells to increase the productivity.
- Asia > Middle East > Saudi Arabia (0.46)
- North America > United States > Texas (0.29)
- North America > Canada > Alberta (0.29)
- North America > United States > California (0.28)
- North America > United States > California > San Joaquin Basin > Cal Canal Field (0.99)
- Asia > Indonesia > Sumatra > Aceh > North Sumatra Basin > B Block > Arun Field (0.99)
- North America > Canada (0.89)
- Europe > Russia > Northwestern Federal District > Komi Republic > Timan-Pechora Basin > Pechora-Kolva Basin > Usa Field (0.89)
Understanding Subsurface Uncertainty for Carbon Storage in Saline Aquifers: PVT, SCAL, and Grid-Size Sensitivity
Likanapaisal, P. (ExxonMobil Technology and Engineering Co., Spring, Texas, USA) | Lun, L. (ExxonMobil Technology and Engineering Co., Spring, Texas, USA) | Krishnamurthy, P. (ExxonMobil Technology and Engineering Co., Spring, Texas, USA) | Kohli, K. (ExxonMobil Upstream Integrated Services Co., Bangalore, India)
Abstract Subsurface uncertainty has a great deal of impact on the development of oil and gas reservoirs, as demonstrated through decades of industry experience. Understanding uncertainty to facilitate robust business decisions across potential scenarios is the cornerstone of successful field development. Although carbon storage is also subject to subsurface uncertainty, the phenomena that impact storage efficiency may not be the same as those influencing oil and gas production. The objectives of this study are to utilize reservoir simulation to Investigate how rock and fluid properties affect CO2 plume size, migration, and trapping mechanisms during- and post-injection, Perform grid size sensitivity to define resolution requirements, and Quantify the impacts of coarse simulation grid and the requirements of monitoring resolution. We present how reservoir conditions (i.e., temperature, pressure, and salinity) affect fluid properties and carbon storage performance. Reservoir temperature and pressure are considered both independently and together along geothermal gradients. A similar investigation also provides the sensitivity result based on varying SCAL (i.e., relative permeability and capillary pressure) parameters. For the grid size sensitivity, the findings demonstrate that an accurate plume size requires a fine vertical grid resolution, while the areal grid resolution impacts the dissolution rate. We make gridding scheme recommendations for reliable predictions based on these findings. We also analyze the result to quantify the error due to coarser grid size and the requirements for appropriate monitoring resolutions. The results from the sensitivity study can help categorize storage site potential. The grid size study provides crucial information to develop reservoir simulation best practices in evaluating carbon storage candidates. Another aspect of a carbon storage operation is the monitoring plan to ensure the containment of the injected CO2. Since the geometry of the plume continues to evolve post-injection, the simulated predictions can guide the selection of monitoring technology with appropriate resolution necessary to capture the CO2 plume at various timeframes.
- North America > United States > Texas (0.46)
- Europe > United Kingdom > England (0.28)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abatement of GHG Emissions by Simplifying Field Architecture with Multiphase Flowmeters in Onshore US Shale: A Field Case Study
Plagens, J. (Ensign Natural Resources, Houston, Texas, USA, now with Magnolia Oil & Gas) | Moncada, K. (SLB, Houston, Texas, USA) | Thompson, J. (SLB, Houston, Texas, USA) | Husoschi, L. (SLB, Houston, Texas, USA) | Theuveny, B. (SLB, Houston, Texas, USA) | Amin, A. (Belsim S.A., Sugar Land, Texas, USA)
Abstract Methane is a powerful greenhouse gas (GHG). Over 20 years, it is 80 times more potent at warming than carbon dioxide, with onshore conventional wellsite production facilities being the source of more than 50% of petroleum methane emission in the United States (US). An operator working in the gas condensate window of the Eagle Ford shale has been diligently looking for innovative transition technologies to help minimize methane emissions from wellsite sources. Other key sustainability attributes for the project were capex and opex savings while simplifying well-pad architecture. Leak detection and repair (LDAR) programs that identify unintended or fugitive emissions from equipment in an oil and gas facility are a traditional way to drive maintenance activities to reduce emissions. However, this is focused on detection rather than elimination. The operator typically configures well-pads with three to six wells with one test separator per well, resulting in multiple separators per well-pad. The switch from test separators to full gamma-spectroscopy/Venturi combination surface multiphase flowmeters (MPFM) was an ideal solution as it eliminates the need for so many test separators, thus eliminating valves, pneumatic devices, and connections responsible for most fugitive gas emissions on production well sites, while simultaneously delivering real-time monitoring, which provides repeatable and accurate fluid measurements. Over the course of a field trial, the MPFM performed within the uncertainty range specified by the operator and even helped identify bias errors with reference to a test separator to enable remediation. Additionally, the high-frequency data (up to 1 second) helped detect changes in flow behavior like slugging flow or slight changes in water cut. Financial incentive was a significant driver in assessing the MPFM as it provides a 50% reduction in capex per well by simplifying the equipment and pipeline infrastructure and the investment cost for ancillaries (space, power, manifolds, etc.). In addition, overall methane emissions were reduced by an estimated 67%, and the number of potential leak paths for fugitive methane was minimized. Using the field case study, the paper demonstrates how integrating the use of MPFM technology to reduce GHG emissions will bring more tangible results than leak detection and repair efforts. The study shows how emissions can be reduced by more than 72% in different scenarios, depending on the number of wells in a well-pad with one test separator. If the test separator is removed, the reduction can reach up to 92%. Simplifying well-pad architectures using MPFMs for well measurements while performing separation and liquid handling at centralized facilities minimizes the many connections and valves responsible for most methane fugitive emissions. New or retrofitted facilities can use this transforming technology as their cost has decreased significantly, and data are repeatable and accurate.
- Overview (0.46)
- Research Report > Experimental Study (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.50)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Downhole and wellsite flow metering (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- (2 more...)
A foundational principle in the safe development of mature fields is to understand pressure depletion across the different reservoirs. A proper estimate of pore pressure guides not only in-place volumes and expected recoverable, but also heavily impacts the design and safe drilling of wells. Methods to determine reservoir pressure vary, from offset-well extrapolation to numerical modeling, depending on the particulars of the field. In this work, we present a novel approach to estimate field wide pressure depletion from 4D seismic softening along OWC signals.
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (1.00)
- Geophysics > Seismic Surveying (0.90)
Automatic Integration of While Drilling Cutting Descriptions with Formation Evaluation Models
Alakeely, A. A. (Saudi Aramco, Dhahran, Saudi Arabia) | Torlov, V. S. (Saudi Aramco, Dhahran, Saudi Arabia) | Qubaisi, K. A. (Saudi Aramco, Dhahran, Saudi Arabia) | Kanfar, M. F. (Saudi Aramco, Dhahran, Saudi Arabia)
Abstract The procedure of analyzing and integrating text information from cutting descriptions collected during drilling process with formation evaluation models is a tedious task that is demanding in terms of time and human labor. The work describes a process to automate the task and use it to identify hydrocarbon zones in exploration wells. As the drill bit penetrates the formations in a well, the rock fragments are usually described across the associated depth of interest in a text format. These descriptions are valuable source of information that are usually compared to petrophysical models that uses wireline logs as input. In this work, textual cutting descriptions are utilized in identifying potential hydrocarbon zones using natural language processing and deep learning algorithms. The methodology uses natural language processing techniques to generate data set. The data set is used to train a deep learning algorithm to identify hydrocarbon zone from cutting descriptions automatically. The system has been used to identify hydrocarbon zones in a group of exploration wells. The trained model has been applied to blind test wells. The methodology reached hydrocarbon detection accuracy of 98% in challenging areas. For example, it allows hydrocarbon detection in low resistivity pay reservoirs where Archie's based saturation calculations present a water wet zone. The result was confirmed by formation tester and testing results suggesting the correctness of the technique. Moreover, the automation reduces the turnover time of such analysis and reduces human error. The enclosed process helps in integrating textual information into the petrophysical model to reduce uncertainty, human labor, and aid in identifying hydrocarbon zones. In addition, the method will reduce the need for unnecessary testing, resulting in cost saving in rig time operation.
- North America > United States > Texas (0.47)
- Asia > Middle East > Saudi Arabia (0.46)