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Collaborating Authors
Gas-condensate reservoirs
Upon completing this assignment, the participant should be able to identify primary reservoir drive mechanisms (solution gas drive, water drive, gas cap drive) by observing production and pressure trends, estimate original hydrocarbons in place, using both volumetric and material balance methods, develop a range of estimates for technical recovery factors and reserves, and identify and interpret production mechanisms to predict the behavior of oil, gas and gas condensate reservoirs.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (0.78)
- Reservoir Description and Dynamics > Reservoir Simulation (0.47)
Application of Oil Fingerprinting and Biomarker Analysis for Reservoir Compartmentalization Studies and Genetic Typing of Oils from North Ustuyrt Oil and Gas Region
Seitkhaziyev, Y. Sh. (Atyrau branch of KMG Engineering, Atyrau, Kazakhstan) | Sarsenbekov, N. D. (Atyrau branch of KMG Engineering, Atyrau, Kazakhstan) | Uteyev, R. N. (Atyrau branch of KMG Engineering, Atyrau, Kazakhstan)
The North Ustyurt Oil and Gas Region (OGR) in terms of territory is located within the borders of two countries. The majority of it is situated within the territory of Western Kazakhstan, while a smaller part (to the east) is in Western Uzbekistan. Geographically, the North Ustyurt OGR is bounded to the north by the Caspian Lowland, to the east by the Aral Sea, and to the west by the North-Buzashin Oil and Gas Zone. From a tectonic perspective, its northern-northwestern boundary is marked by the North Ustyurt fault system, separating the North Ustyurt from the Caspian Depression with Upper Paleozoic complexes. The southern-southwestern boundary is formed by the Central Ustyurt dislocations and the Tokubay-Tuakyr thrust-and-fold system, while the eastern boundary is defined by the Aral-Kyzylkum uplift zone. In comparison to neighboring oil and gas regions, the hydrocarbon potential of the North Ustyurt Oil and Gas Region (OGR) is indeed less pronounced, but recent discoveries in the Tepke area suggest that it is not fully explored. In the Kazakhstani part of the region, approximately 10 fields have been found in the Jurassic, Cretaceous, and Paleogene fields, while in the Karakalpakstan part of Uzbekistan, there are 17 fields in Mesozoic and Paleozoic deposits. For this region, structural and tectonic control over hydrocarbon presence is evident. All identified fields are associated with steps, uplift zones, and monoclines located on the periphery of major flexure systems. Additionally, there are broad patterns in the distribution of fields based on the phase state of hydrocarbons, albeit at a relatively coarse scale: western areas are characterized by oil, north-eastern areas contain dry methane gas, and eastern-southeastern areas, bordering Uzbekistan, have gas condensate fields. The volumetric distribution of oil and gas fields clearly corresponds to three hypsometrically uplifted segments of flexures: the Arystanov Step, Akkulka Fold, and Shagyrly-Shomyshtinsky Prominence (Figure 1). It is important to note that all of these segments are bounded by significant faults, which does not exclude the possibility of hydrocarbon recharge from deep hydrocarbon generation centers [1].
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.96)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.96)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Geochemical characterization (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (0.90)
Abstract The success of production from unconventionals in North America, encourage Kuwait to focus on Najmah Kerogen and unconventional resources that have value of significant hydrocarbon resource potential in North Kuwait Jurassic Area. Kuwait Oil Company has embarked on a journey to unlock these unconventional resources by screening the subsurface targets in the reservoirs which have potential to contribute to the gas production ambitions of the country. Unconventional field development team has evaluated these difficult reservoirs through an End To End (E2E) hydrocarbon maturation (HCM) framework, with a clear roadmap to appraise and develop these resources to sustain the required plateau of the unique Gas Asset in Kuwait. The reservoirs of focus are a mix of naturally fractured carbonates with conventional "Middle Marat (MM)" reservoirs and tight unconventional reservoirs ("Najmah/Sargelu"&"Kerogen") at a depth of 15000+ ft in a HPHT setting. The E2E-HCM Modules have been used as key building blocks for the economic evaluations. The modules can be flexibly combined as needed to model the economic potential of each of the Common Value Areas (CVAs), where a CVA is defined as an area that has been demonstrated to have common economic metrics based on Play-Based Exploration (PBE), infrastructure, and field development characteristics. Aggregating modelling tools (eg Proviso), using decline curves of 23 conventional volatile oil and gas condensate reservoirs (3D simulation) and five unconventional reservoirs have been used. Long term production forecast is generated by combining these simulation results and flowing through 8 production facilities. An optimized drilling sequence of 500+ wells is worked-out to achieve this production forecast. This exercise also facilitated in screening potential targets for further drilling for meeting and sustaining the promised gas production plateau. In this paper, the methodology and workflow used for unlocking the potential of conventional and unconventional resources of north Kuwait Jurassic reservoirs is highlighted.
- Geology > Rock Type > Sedimentary Rock (0.97)
- Geology > Geological Subdiscipline (0.68)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.46)
- Asia > Azerbaijan > Caspian Sea > Apsheron-Pribalkhan Ridge > South Caspian Basin > Azeri-Chirag-Guneshli Field > Azeri Field (0.99)
- Africa > Nigeria > Gulf of Guinea > Niger Delta > Niger Delta Basin > OML 118 > Bonga Field (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
Integrated Asset Modelling and Field Development of a Gas Condensate Field
Farooq, U. (Weatherford) | Ashraf, Z. (Oil & Gas Development Company Limited, Pakistan) | Yousaf, H. (Oil & Gas Development Company Limited, Pakistan) | Ahmad, S. (Oil & Gas Development Company Limited, Pakistan) | Saqib, C. M. (Weatherford) | Ali, M. (Weatherford)
Abstract Optimized production from gas reservoirs comes with many challenges, especially in a case where there are several fields present around the main target reservoir, sharing common surface facilities. This study is aimed at integrated asset modelling of a gas field with over 1 Tscf of gas initially in place. The objective is to couple a layered reservoir, wells with comingled production and surface facilities, and to recognize the full potential as well as bottlenecks for creating a development plan for prolonging the field life. The field consists of a main central reservoir, which is surrounded by compartmentalized satellite regions with production potential. The study begins with geophysical interpretation, followed by petrophysical and static modelling. The static model is used to initialize the dynamic model and a simulated realization of the main central reservoir is created. The satellite fields are modelled using material balance modelling. The reservoirs are then coupled together with the surface facilities network using the vertical lift profiles of all wells. Forecasts are run along with economic modelling to propose an optimized development scheme considering workovers, infill wells as well as surface compression. The main challenge is to create an optimized history matched integrated network model incorporating all available data, compared to a standalone simulation model with no consideration of surface constraints. Another challenge is to create coupled subsurface realization using both simulation model for central reservoir and tank models of more than 10 satellite compartments. The goal of the study is meeting the sales requirements for as long as possible and maximizing the return on investment. Based on the integrated model, workovers and infill wells have been proposed that increase the plateau production period. Wells with underestimated flow potential are realized and choke optimization has been proposed for prolonging the plateau before bringing surface compression online. The water production constraints of the fields have been incorporated and realized in the modelling process. The surface compression has been proposed in three stages over the life cycle of the field, along with the timeline and location of compressors, to produce the fields until wellhead pressures approach atmospheric. The unique aspect of this study is the ability to model complex multilayered reservoirs systems with multiple compartments and combine them with the well and surface models to create a comprehensive and robust tool for reservoir management and decision making. A tool that can be updated down the road with minimum effort, to keep up with the field behavior. Such integrated asset models serve as testing grounds to see expected outcomes and gain a level of confidence before any development strategy can be applied.
- Asia > Pakistan (0.95)
- North America > United States > Texas (0.29)
- Asia > Pakistan > Sindh > Lower Indus Basin > Goru Formation (0.99)
- Asia > Pakistan > Lower Indus Basin (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Management > Asset and Portfolio Management > Integrated asset modeling (1.00)
- Management > Asset and Portfolio Management > Field development optimization and planning (1.00)
Optimizing Well Placement and Recovery in Mature Gas Condensate Reservoirs Through the Utilization of Pseudo Pressure Approach
Iqbal, Muneez (United Energy Pakistan Limited, Karachi, Pakistan) | Mehmood, Saad (United Energy Pakistan Limited, Karachi, Pakistan) | Azeem, Abdul (United Energy Pakistan Limited, Karachi, Pakistan) | Hussain, Sadam (United Energy Pakistan Limited, Karachi, Pakistan) | Zakir, Mufaddal Murtaza (United Energy Pakistan Limited, Karachi, Pakistan) | Younas, Muhammad Avais (Orient Petroleum Inc., Islamabad, Pakistan) | Tanveer, Atif (Government Holdings Private Limited, Islamabad, Pakistan)
Abstract This paper overcomes the challenge of reliable prediction by capturing condensate banking effects in the numerical simulation models, and to identify remaining sweet spots for infill drilling. In the rich gas condensate, the heavier components in the gas phase drop out below saturation pressure, it causes: (1) Decline in gas production, (2) Loss of valuable condensate components, both of which manifest in the form of expanding condensate bank incorporated in this study. The case study is of a rich gas condensate field located in the Middle Indus Basin of Pakistan. A detailed compositional simulation model including matched PVT has been developed using commercial simulator to study the effects of condensate banking and its impact in the history matching and forecast. Local grid refinements (LGR) and Generalized pseudo pressure (GPP) approaches have been utilizing and compared in this case study for the improvement of history match along with the reliable predictions. An applied workflow has been developed to locate sweet spots in order to target future development well opportunities in the field. A comparative analysis has been performed in this case study using LGR and GPP approach to study the impact of condensate drop-out on wells productivity. As sector model was developed for the comparison between the techniques and later on the results applied on the full field simulation. GPP approach was much faster with better history matched results as compared to LGR. The forecast generated using GPP technique when later compared with actual field performance was much realistic. As a result, the model was then utilized to identify infill development opportunities in the field. The developed workflows resulted in evaluating two infill wells with incremental recovery of 10-12% of the field. The work is computationally intensive with time & resource constraints challenges. Availability of advanced workflow generation rendered the overall execution in an efficient and timely manner.
- North America > United States (0.95)
- Asia > Pakistan > Arabian Sea (0.24)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Effect of Pressure and Temperature Variation on Wax Precipitation in the Wellbore of Ultradeep Gas Condensate Reservoirs
Zhang, Chao (Key Laboratory of Unconventional Oil & Gas Development (China University of Petroleum (East China)), Ministry of Education / School of Petroleum Engineering, China University of Petroleum (East China) (Corresponding author)) | Gu, Zihan (Key Laboratory of Unconventional Oil & Gas Development (China University of Petroleum (East China)), Ministry of Education / School of Petroleum Engineering, China University of Petroleum (East China)) | Cao, Lihu (Key Laboratory of Unconventional Oil & Gas Development (China University of Petroleum (East China)), Ministry of Education / School of Petroleum Engineering, China University of Petroleum (East China) / PetroChina Tarim Oilfield Company) | Wu, Hongjun (PetroChina Tarim Oilfield Company) | Liu, Jiquan (PetroChina Tarim Oilfield Company) | Li, Pengfei (Key Laboratory of Unconventional Oil & Gas Development (China University of Petroleum (East China)), Ministry of Education / School of Petroleum Engineering, China University of Petroleum (East China)) | Zhang, Dexin (Key Laboratory of Unconventional Oil & Gas Development (China University of Petroleum (East China)), Ministry of Education / School of Petroleum Engineering, China University of Petroleum (East China)) | Li, Zhaomin (Key Laboratory of Unconventional Oil & Gas Development (China University of Petroleum (East China)), Ministry of Education / School of Petroleum Engineering, China University of Petroleum (East China))
PetroChina Tarim Oilfield Company Summary To investigate the wax precipitation mechanism of condensate in a wellbore during the ultradeep gas condensate reservoir development, condensate samples were prepared in this work. Changes in the temperature and pressure of fluid flow in the wellbore are simulated by a high-temperature and high-pressure pressure/volume/temperature (PVT) system. This simulation explores their influences on the wax precipitation of the condensate produced from the target reservoir. The results show that the temperature decrease weakens the wax molecular movement activity and promotes the precipitation of wax, resulting in the expansion of the pressure range in which wax precipitation occurs in the system. Meanwhile, decreasing the pressure promotes wax aggregation by increasing van der Waals forces between wax molecules, thereby increasing the wax precipitation rate. At different temperatures, the wax precipitate amount first increases and then decreases with decreasing pressure, which is determined by the wax solubility and remaining content in the system. Since the solubility of a low carbon number component is more sensitive to temperature and pressure changes than that of a high carbon number component, in the early stages of experimental temperature and pressure decreases, the precipitation of coarse crystalline wax with carbon numbers ranging from C16 to C30 is more active than that of microcrystalline wax with carbon numbers exceeding C30. The remaining amount of the former component in the system decreases rapidly, and its precipitation capacity weakens, thus increasing the amount of the latter component in the precipitated wax during the later stage of experiments; this trend corresponds to the shift of the curve peak of the wax carbon number distribution to an abscissa interval with the relatively high carbon numbers. This work can provide reference data for the prediction of the well depth at which the wax precipitation occurs and the wax composition, aiming to promote the implementation of wellbore wax blockage prevention programs. Introduction Condensate production occupies an important position in the global petroleum industry. Unlike conventional oil, condensate can undergo a complex transition from a supercritical state to a mixed gas-liquid state due to changes in temperature and pressure during wellbore pipe flow.
- Research Report > New Finding (0.66)
- Research Report > Experimental Study (0.66)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > China Government (0.48)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (14 more...)
DNO has made a significant gas condensate discovery at its Norma prospect in the Norwegian North Sea license PL984. Preliminary evaluation of the discovery indicates gross recoverable resources in the range of 25–130 million BOE on a P90-P10 basis, with a mean of 70 million BOE, in a Jurassic reservoir zone with high‑quality sandstones. Located 20 km northwest of the Balder hub and 30 km south of the Alvheim hub, Norma is situated in an area with extensive infrastructure in the central part of the North Sea, with tieback options offering potential routes to commercialization. At 4650 m, the discovery well encountered a 16-m hydrocarbon column in a 20-m gross reservoir section in Jurassic sandstones. DNO is calling the discovery a play-opener for the deep turbiditic sands in this area given the exceptionally good reservoir quality encountered.
- Europe > Norway > North Sea (1.00)
- Europe > United Kingdom > North Sea (0.88)
- Europe > North Sea (0.88)
- (2 more...)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
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)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Estimating Fractal Dimension as a Spatially Correlated Pore Structure Heterogeneity Measure from Rate-Controlled Capillary Pressure Curves
Daniels, Jeffrey K. (Department of Petroleum Engineering, University of Houston, Houston, TX, USA) | Myers, Michael T. (Department of Petroleum Engineering, University of Houston, Houston, TX, USA) | Hathon, Lori A. (Department of Petroleum Engineering, University of Houston, Houston, TX, USA)
Abstract Pore structure heterogeneity is present in reservoir rocks at multiple length scales. This makes it a challenge to optimally assess and integrate into digital rock and pore-scale models, especially for complex reservoir rocks. Their fractal nature causes variation in their physical properties over multiple length scales. The fractal dimension governs the power law scaling of fractals and has been estimated from experimental measurements and rock images of the pore space, to quantify pore structure heterogeneity. Each experimental technique and imaging modality has limitations in the level of pore structure detail it can provide. This necessitates combining them for comprehensive pore structure characterization. However, challenges persist in correlating spatial variations in pore structure at multiple length scales. An Apparatus for Pore Examination (APEX), with the highest known reported resolution (1.3E-10 cc and 5E-6 psi), is proposed to make high resolution rate-controlled capillary pressure measurements, which reflect comprehensive pore structure and fractal characteristics of the rock. The fractal dimension is estimated to quantitatively describe the spatial correlation in pore structure heterogeneity. The rock samples analyzed are the Berea sandstone and Indiana limestone which have simple and complex pore systems respectively. An amplitude spectrum of their APEX capillary pressure curves revealed they are "1/f" scaling signals with β ≈1, indicative of their fractal properties and power law correlated statistics. Fractal dimension estimates from the APEX capillary pressure curves and thin section images of the pore structure of both rock samples, using the proposed methods were compared relatively and observed to have relative differences lesser than 10%. The fractal dimension estimates in this study were within 10 % tolerance of reported estimates published in literature for the Berea sandstone and Indiana limestone, from SEM images and thin section images. Detrended fluctuation analysis (DFA) of the APEX capillary pressure curves showed that the Berea sandstone had a single pore system with short-range power law correlated pore structure statistics, indicated by one fractal dimension (D = 2.533) while the Indiana Limestone had two pore systems with short-range power law correlated pore structure statistics indicated by two fractal dimensions ( D = 2.735 and D = 2.919). The results presented in this study show that high resolution APEX capillary pressure measurements reflect the fractal characteristics of a reservoir rock's pore structure. In this context, fractal dimensions can be estimated from high resolution APEX capillary pressure measurements to quantitatively describe spatial correlation in pore structure heterogeneity. The estimated fractal dimensions indicate the Indiana limestone had a poorly connected pore space and a greater degree of pore structure heterogeneity than the Berea sandstone, which had a relatively well-connected pore space with mild pore structure heterogeneity at the pore scale. The proposed methodology can be used to integrate spatially correlated pore structure heterogeneity at the pore and core scales in computational rock models to enhance their predictive capabilities of petrophysical properties. It can also be used to complement techniques of quantifying heterogeneity in reservoir properties with significant pore structure dependencies, which do not account for their spatial correlation.
- North America > United States > Kentucky (0.99)
- North America > United States > West Virginia (0.90)
- North America > United States > Pennsylvania (0.90)
- (2 more...)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.90)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.89)
- North America > United States > West Virginia > Appalachian Basin > Berea Sandstone Formation (0.89)
- North America > United States > Pennsylvania > Appalachian Basin > Berea Sandstone Formation (0.89)
- North America > United States > Ohio > Appalachian Basin > Berea Sandstone Formation (0.89)
- (2 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.71)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.69)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (0.67)
- (2 more...)