Results
Petroleum Engineering, University of Houston, 2. Metarock Laboratories, 3. Department of Earth and Atmospheric Sciences, University of Houston) 16:00-16:30 Break and Walk to Bizzell Museum 16:30-17:30 Tour: History of Science Collections, Bizzell Memorial Library, The University of Oklahoma 17:30-19:00 Networking Reception: Thurman J. White Forum Building
- Research Report > New Finding (0.93)
- Overview (0.68)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral (0.72)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.68)
- (2 more...)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.93)
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)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- (6 more...)
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...)
Re-Inventing Pressure Retained Core Acquisition for Advanced Reservoir Property Determination
Wunsch, D (CORSYDE International, Berlin, Germany) | Rothenwänder, 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 ‘re-utilization’ 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...)
The Impact of Dynamic Wettability Alteration and Phase Behavior on the VES Flooding Recovery at the Pore-Scale
Ahmed, M. Elmuzafar (Petroleum Engineering Department, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals, Saudi Arabia) | Sultan, Abdullah S. (Petroleum Engineering Department, College of Petroleum Engineering & Geosciences, King Fahd University of Petroleum & Minerals, Saudi Arabia)
Abstract Wettability plays a crucial role in the recovery of hydrocarbons as it governs the adhesive forces between oil and rock samples, directly influencing the efficiency of the displacement process. Numerous research efforts have focused on modifying rock wettability to a more favorable state. Typically, the contact angle measurement with smoothed rock discs has been employed, but this experimental design has limitations in reflecting reality since the wettability effect occurs within the pores. The coverage area of a single drop is substantial, encompassing a wide range of pore and grain spaces, introducing uncertainties regarding the validity of the measurement. In this study, we delve into the pore-scale level to observe the actual process of contact angle alteration during flooding, utilizing microfluidic technology. Three different concentrations of Viscoelastic Surfactant (VES)—specifically, 0.5%, 0.75%, and 1.25% vol%, prepared using 57K ppm synthetic seawater—were employed. The microfluidic model initially underwent saturation with formation water and was subsequently displaced by oil to establish the initial oil saturation. The microfluidic setup encompassed a precise pump for flood control and a high-speed microscope to capture images, which would later be analyzed using image processing software to obtain the real contact angle. To ensure the reliability of our data, we divided the pore space into twenty divisions and measured the contact angle through image analysis. The contact angle was measured at various injection stages to observe the dynamic changes from the initial state to the final state and the resulting recovery from each fluid system. Additionally, we analyzed the in-situ generated emulsion to establish a link between phase behavior, wettability alteration, and recovery. The results demonstrated that using 0.5% VES altered the wettability from slightly oil-wet to slightly water-wet, resulting in a 55% recovery of the original oil in place (OOIP). Conversely, employing 1.25% VES did not significantly alter the wettability but yielded a recovery of 52% OOIP. The 0.75% VES altered the wettability from slightly oil-wet to extremely water-wet; however, this alteration did not translate into higher recovery. Instead, a water breakthrough was observed, which diminished the sweep efficiency, resulting in a recovery of 47%. This pore-scale investigation successfully demonstrated the effectiveness of utilizing VES solutions to modify rock wettability and enhance oil recovery.
- Europe (0.46)
- Asia > Middle East (0.28)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- (5 more...)
CRM-Aquifer-Fractional Flow Model to Characterize Oil Reservoirs with Natural Water Influx
Parra, José E. (Universidad Nacional Autónoma de México (UNAM) (Corresponding author)) | Samaniego-V., Fernando (Universidad Nacional Autónoma de México (UNAM)) | Lake, Larry W. (The University of Texas at Austin)
Summary This work presents a new flow model that uses production data to characterize conventional undersaturated oil reservoirs with natural water influx in primary production. The main application is to estimate the original oil in place (OOIP), but the model also calculates the productivity index (PI), water influx, and heterogeneity factor. Aquifers are common to many reservoirs and their diagnosis is relevant because they can serve as an important drive mechanism but can also affect well productivity. Discerning between the reservoir and aquifer volumes is also a major challenge in many oil fields. Reservoir-aquifer systems have been investigated with various dynamic characterization techniques such as the material balance equation (MBE), pressure transient analysis, and production/rate transient analysis. These methods have limitations, for example, requiring shut-in wells and/or very large production histories and high mobility and compressibility ratios to yield distinguishable responses in the diagnostic plots. The new flow model couples the producer-based capacitance resistance model (CRMP) with the Fetkovich aquifer model (CRMPA). It enables calculating the total instantaneous production flow rate from a well as a function of three mechanisms—reservoir depletion, changes in bottomhole pressure (BHP), and water influx. In addition, CRMPA is coupled with the Koval fractional flow model (capacitance resistance aquifer-fractional flow model, CRMPAF) to calculate the individual oil and water rates and to enhance the OOIP estimation for wells with two-phase production caused by water breakthrough from the aquifer. The capacitance resistance model (CRM) is a production analysis technique that uses rate and pressure data from typical field surveillance (no dedicated tests) to characterize reservoir properties. It has been widely used to study reservoirs under secondary and tertiary recovery. There are a few applications for primary recovery, and only one reference investigated natural water influx. There are important differences between the previously published and the new CRMPA formulations. The former estimated the individual water influx to each well in a multiwell reservoir associated with an aquifer. The calculations were performed assuming the reservoir pore volume (PV) was known, whereas the present approach simultaneously calculates the PV and the water influx. The former approach also required a priori knowledge of the average pressure, obtained from buildup tests, whereas the new method uses production data, (i.e., it does not require shut-in wells). In the new approach, CRMP (without aquifer) is first used to calculate the capacitance/resistance (CR) parameters of the equivalent (reservoir-aquifer) medium. It provides the correct OOIP for volumetric reservoirs; however, CRMPA is used when the PV significantly differs from volumetrics and water influx is detected. CRMPA calculates the reservoir CR parameters using simple relationships between the equivalent and composite mediums. For wells with two-phase production, the Koval factor is an additional parameter. The CRMPA/F solution is obtained by minimizing the errors between the calculated and measured rates over a time window. The new CRMPA/F approach is compared and validated with several models of single and multiwell synthetic reservoir-aquifer systems with different properties and geometries. It is also used to characterize a field case.
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- (2 more...)
The Mangala field has been regarded as an excellent chemical EOR candidate since its discovery in 2004. The main reservoir unit is divided into the Lower and Upper Fatehgarh formations. These units are subdivided into five reservoir units, FM1 to FM5 from top to bottom. Mangala contains waxy sweet crude oil with gravity ranging from 20 API near the oil/water contact to 28 API in the oil column.
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Barmer Hill Formation (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (0.66)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (0.46)
Time-Lapse Pulsed Neutron Logging Helps Maximize Recoveries from Mature Field - Case Study from Mangala Field of Rajasthan, India
Kumar, Alok (Cairn Oil & Gas, Vedanta Ltd.) | Sigtia, Shraddha (Cairn Oil & Gas, Vedanta Ltd.) | Das, Joyjit (Cairn Oil & Gas, Vedanta Ltd.) | Guha, Rupdip (Cairn Oil & Gas, Vedanta Ltd.) | Ahmed, Abaan (Cairn Oil & Gas, Vedanta Ltd.) | Shankar, Vivek (Cairn Oil & Gas, Vedanta Ltd.) | Kumar, Suresh (Cairn Oil & Gas, Vedanta Ltd.) | Chauhan, Nishi (HLS Asia Ltd) | Kumar, Ravinder (HLS Asia Ltd) | Ramakrishna, Sandeep (HLS Asia Ltd)
Abstract Mangala Oilfield of Rajasthan has produced over 36% of STOIIP and has been subjected to several innovative and new era technologies since it started producing in August’ 2009. Initially, field was under Water flood phase till April’2015 and then full field Polymer flood phase started to maximize recovery. Mangala field with medium-gravity viscous crude oil & formation water salinity of approximately 8000ppm has an excellent reservoir property of high porosity (24 to 26%), high permeability (200md- 20D) and very low irreducible saturation i.e., less than 5%. Thus, C/O logging in this field has been a very good choice to estimate the remaining oil saturation (ROS) and understand the sweep of oil due to injection which in turn has helped in maximizing recoveries from the field. Time-lapse PNL were run in several wells to monitor the efficacy of the water flood/polymer flood phase on oil recovery. The objective was two-fold; to estimate the change in saturation over time and to identify by-passed or marginally swept intervals. The process begins with recording the initial saturation in the wells before any production has occurred. Then time-lapse data are recorded to monitor the change in saturations. Secondly, saturation estimation from PNL data were used to plan the next course of action- workover operations, changing completion zones, abandoning certain zones or wells, and infill drillings. PNL data in combination with other reservoir surveillance techniques (MPLT) has proved to be a vital surveillance tool to maximize the recovery from this field. In this paper, we present the effectiveness of PNL tool specially RMT-I with production data over a period of 3 years (post Aug 2019). However, the results also include integration of other PNL dataset (RST & Raptor) acquired for reservoir surveillance activity and the challenges involved in interpreting the result of different PNL tool over time. In absence of RMT 3D tool, PNL is acquired as 1 Sigma up/down pass and 3 CO up passes at 1fpm-3fpm to address the uncertainty related to gas presence on C/O interpretation. Sigma measurement helped in identifying gas below packer or in the annulus behind pipe and helped in addressing the uncertainty related to gas presence on C/O interpretation. Secondly, RMT was planned in infill well post drill to determine the uncertainty between OH and Cased hole Oil saturation. The results agreed with production data and uncertainty in oil saturation estimation was minimized to 10-15% approximately. Several cases will be discussed in the paper to demonstrate the use of PNL logs for reservoir management.
- Geology > Geological Subdiscipline > Stratigraphy (0.48)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- Geology > Sedimentary Geology (0.46)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation > NB-1 Well (0.98)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation > NB-1 Well (0.98)
- (2 more...)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (3 more...)
Integrated model-based substantiation for operation mode of wells producing high-viscous oil from water-oil contact zones (Russian)
Veliev, M. M. (Vietsovpetro JV) | Ivanov, A. N. (Vietsovpetro JV) | Veliev, E. M. (Oktyabrsky Branch of Ufa State Petroleum Technological University) | Mukhametshin, V. V. (Oktyabrsky Branch of Ufa State Petroleum Technological University) | Udalova, E. A. (Ufa State Petroleum Technological University)
In Russian Federation, including Urals-Volga region, significant volumes of original oil in place are located in water-oil zones. Geological structure analysis of major platform-type oil fields has shown that the area of initial water-oil zones covers from 31 to 80.3 % of the total oil-bearing area. Based on the analysis and comprehensive experience it is determined that water-oil zones reserves recovery is 1.5-2 times slower comparing to purely oil areas. Water-oil zone tend to have faster water breakthrough into the producing wells. Oil-water ratio is 2-3 times higher than in the pure oil areas. The article describes the results of modelling the operation modes well in water-oil contact zones of high-viscous oil fields. Particularly, considered the field with the specific operation, i.e. limited capability of oil-loading unit resulting in constraints to daily water production related to the necessity of transporting and disposing the associated water. The integrated model calculations has shown that shutting down watered wells in the water-oil contact zone (having water-cut below maximal) is not effective for reducing water production. These wells produce significant volume of oil and, therefore, recommended for conversion to another operation mode, which applies a bottomhole pump with the possibility to adjust fluid production rate in wide ranges. The reduction of existing water-cut is observed on these wells. It is established, that reducing the water production from the water-oil contact zone stimulates water inflow into the purely oil area and increases the reservoir pressure, which is favourable for local wells operation, especially when there is no reservoir pressure maintenance system. The reduction of operation costs for the transport and disposal of the associated water compensates economic losses related to the adjustment of well operation and corresponding decrease of oil recovery. Therefore, the options with constraining and adjusting the producing wells operation are economically comparable to the option, which reflects the field’s potential.
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (0.75)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (0.68)
A Dynamic Workflow of Well Health Issue Prediction – Gas Leakage
Haq, Bashirul (Department of Petroleum Engineering, King Fahd University of Petroleum & Minerals, Saudi Arabia) | Al Shehri, Dhafer (Department of Petroleum Engineering, King Fahd University of Petroleum & Minerals, Saudi Arabia) | Hassan, Zahid (FMC Technologies Australia Ltd) | Ahmed, Iftekhar (Edith Cowan University, Joondalup, Western Australia, Australia.) | Isah, Abubakar (Department of Petroleum Engineering, King Fahd University of Petroleum & Minerals, Saudi Arabia) | Afagwul, Clement (Department of Petroleum Engineering, King Fahd University of Petroleum & Minerals, Saudi Arabia) | Sofian, Mohamed (Department of Petroleum Engineering, King Fahd University of Petroleum & Minerals, Saudi Arabia) | Mohammed, Nasiru S. (Department of Petroleum Engineering, King Fahd University of Petroleum & Minerals, Saudi Arabia)
Abstract Due to the corrosive nature of sour natural gas, productions through tubing and casing are susceptible to corrosion, resulting in gas leaking. This issue causes massive production loss. Subsequently, well health monitoring and early detection of existing and developing gas leakage are essential for profitable gas production. Dynamic material balance technique estimates gas initial in place (GIIP) using wellhead or bottom hole pressures and gas rates data at flowing conditions during the production. This method is commonly utilized for estimating GIIP but does not apply to predict gas leakage issues. This work aims to add a leak factor term by modifying the dynamic material balance equation and build a mathematical platform to detect and validate the problem by applying the modified equation. The new platform produces expected well behaviour using the revised equation and curve-fitting tool in MATLAB and then compares with the actual behaviour and detect gas leakage. The deviation from the expected and actual behaviour determines the issue. Each component of the model is validated using know values. After that, the total system is tested with known leakage data. Finally, the platform is applied in the active gas well, and the leak detection of the platform is reasonably well. The new workflow can notify the production engineers so they can take corrective measures about the issue.
- North America > United States (1.00)
- Asia (1.00)
- North America > Canada > Alberta (0.28)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (2 more...)