A shallow, unconsolidated, sour heavy oil reservoir in North Kuwait is under primary production. Due to rapid decline in reservoir pressure, a development scenario was selected consisting of 10 years of water injection secondary recovery followed by enhanced oil recovery (EOR) polymer flood for which a pilot is being implemented. This pilot will provide vital information to establish feasibility for full-field implementation and in this paper, we describe the application of Interference Pressure Transient Test (IPTT) and stress testing. IPTT is utilized for proper understanding of the vertical permeability and permeability anisotropy (Kv/Kh) which are key for evaluating heavy oil sweep efficiency under injection. Stress testing will provide essential information about the cap rock integrity to monitor that water and polymer flooding is contained across the required reservoir. A combination of IPTT and stress testing utilizing the Wireline Formation Testing (WFT) tool and laboratory core analysis were the basis of a selected method for vertical permeability and permeability anisotropy determination. Laboratory measurement for permeability anisotropy has its own challenge due to unconsolidated nature of the formation. IPTT under such conditions can provide reliable and fast measurements, which can also help to calibrate the laboratory measurements later. Four EOR pilot vertical injectors wells were drilled in a symmetric 5-spot pattern, with a central vertical producer. Distance between the injectors is 60 meters, whereas each injector is at 50 meters spacing from the central producer. IPTT was carried out in all four EOR pilot wells, whereas this study involves only three of the injectors. Three-probe configuration along with advanced three-dimensional probe provided comprehensive evaluation for the sand and shaly reservoir intervals. It was observed that main sand body under consideration showed Kv/Kh ranging between 0.05 to 0.15. Some of the main shaly intervals were observed to be either fully isolating the sub-layers or have some vertical communication. It should be noted that downhole fluid analysis and sampling was conducted in one of the wells utilizing WFT. The obtained fluid properties were included in the IPTT analysis for more accurate results. The acquired data from three pilot wells were used to update the reservoir simulation models to have a more representative sweep efficiency evaluation utilizing polymer flooding for the planned EOR. It provides an efficient way to derive the vertical permeability and permeability anisotropy in the challenging unconsolidated formation. This paper adds to the literature of case studies where vertical permeability and permeability anisotropy have been obtained in the challenging environment of unconsolidated formation. It demonstrates how accurate planning combined with advanced technology and innovative workflow yielded the required input data for the dynamic reservoir simulation model.
ABSTRACT:The strength of subgrade soil or road foundation could influence the design of road pavement structures. Flood can be one of the causes of weakened subgrade and consequently road damages. Since the condition of subgrade layer is critical in the road pavement stability, a preliminary study was carried out to ascertain the use of polyurethane insertion as a stabilization mechanism in road subgrade. This study was conducted based on two types of soil that are usually used as soil embankment in road construction. California Bearing Ratio (CBR) test was conducted on the various categories of soaking days and repeated submerged conditions to determine the strength of subgrade soil with and without polyurethane layer. It can be concluded that polyurethane layer can be used to increase or maintain the strength of subgrade soil from the inundation effect.
The study involves a complex sandstone reservoir characterized by relatively thin stratified viscous oil-bearing net pays separated by localized shales and baffles in between. Some of the reservoir intricacies include mappable gas cap intervals overlying net pays at places, water-bearing intervals on top of oil, long transitional zones, and lateral as well as vertical variation in oil viscosity and API. Based on the stratigraphy and geological understanding derived from log interpretation of some initially drilled appraisal wells, the reservoir was divided into four oil-bearing layers: Upper-A, Upper-B, Lower-A, and Lower-B. Upper Sands are separated by Upper Shale Baffle and Lower Sands are similarly separated by Lower Shale Baffle; and Middle Shale acts as a regional barrier between Upper and Lower sand units. Initial reservoir description postulated that all the four oil-bearing layers are separate unconnected units, with no vertical communication. Several hundred wells have been drilled as of now; in many wells, it was found that Upper Shale is discontinuous, with Upper-A and Upper-B sands merging into a single net pay layer. The present study attempts to analyze and integrate various reservoir parameters to understand the realistic and credible "shaliness" of the Upper and Lower Shales. Analysis includes PVT and SCAL data from over 100 wells including viscosity, API gravity, compositional data, and volatiles. Steamflood experiments were conducted on plugs from Upper and Lower Shales. Many plugs were found to have appreciable permeability and porosity with limited oil saturation. All these data suggest that Upper and Lower Shales do not seem to be effective shale barriers and vertical fluid migration can occur. During cyclic steam stimulation in one of the pilot wells, steam was injected in Upper-B layer. Subsequent temperature survey suggests that steam has passed through Upper Shale and migrated into Upper-A Sand. This further corroborates that Upper shale is not acting as an effective barrier. It is thus concluded that to understand geological heterogeneities and to reduce reservoir uncertainty, integration of PVT, SCAL, and other reservoir information along with geology is required for optimum development of an unconventional reservoir. Introduction Proper understanding of a reservoir is very important for the success of an EOR process. It becomes crucial when a thermal process such as steam injection is used as an EOR process because cost per barrel by thermal methods is much higher than for other EOR processes. If a reservoir is complex then it is a must prior to application of any thermal method. The reservoir under consideration is a complex one. Its thickness is relatively less with baffles and shales in between. At places it is having gas cap which is mappable, some water is also found on top of oil. Laterally as well as vertically there is an appreciable variation in oil viscosity and API. After considering all the thermal EOR processes, steam injection has been finalised as the optimum method for the development strategy. Considering the cost of steam, it is always desirable that it should be applied thoughtfully in view of reservoir complexity. Therefore, proper understanding of the reservoir with an integrated approach is critical prior to steam injection in the field for commercial development strategy. Sometimes, only log response of some of the wells may not be enough to understand the reservoir. An integrated approach is needed to understand it completely. In the present work, an integrated approach was used to understand the exact nature of various shales and cemented rocks and interconnection between layers by considering all inputs such as geological, PVT, SCAL and log correlations. This would help in developing the reservoir in an efficient and disciplined manner.
Characterizing heavy oil viscosity by nuclear magnetic resonance (NMR) relaxation time (T 1 and T 2 ) measurements is much more challenging than characterizing light oil viscosities. Crude oils contain a wide range of hydrocarbons, resulting in broad T 1 and T 2 distributions that vary with the oil composition. Most often, a single geometric mean value T 1;gm or T 2;gm is correlated with the crude oil viscosity, which cannot accurately account for the inherent complexity of the oil constituent information. Furthermore, as the viscosity increases, some of the protons in the oil relax too quickly to be observable by logging or laboratory NMR instruments. This results in deficiencies of relaxation time and signal amplitude that give rise to apparent T 1 and T 2 distributions (T 1;app and T 2;app ) and apparent hydrogen index (HI app ). Using T 1;app and T 2;app distributions in NMR viscosity models could produce erroneous heavy oil viscosity estimations. Several attempts have been made to overcome these challenges by taking into account HI app at a fixed interecho time (TE), or a TE-dependent HI app . We have developed a new radial-basis-function-based heavy oil viscosity model using the entire T 2;app distribution, rather than T 2;gm , with an option of including the NMR-derived HI app . Because both of these quantities are TE dependent, it is desirable to include multiple TE data to develop the model. In addition, the principal component analysis (PCA) method was applied to extract major variations of features embedded in the T 2;app distributions, while discarding distribution features that are derived from random noise. The coefficients of the RBFs were derived using laboratory NMR T 2 measurements at ambient and elevated temperatures between 23.5°C and 39.5°C and corresponding viscosity measurements on 50 oil samples. These oil samples were collected from different parts of a shallow viscous oil reservoir in Kuwait. It was observed that the use of this newly developed RBF method showed significant improvement in terms of the reliability of the viscosity prediction compared to some recently published heavy oil viscosity correlations.
An unconsolidated clastic reservoir of Middle Miocene age is under full field development plan in the State of Kuwait. Underlying the shale cap rock, main hydrocarbon bearing reservoir consists of two sand bodies separated by predominantly shale interval present throughout the field. To determine the role of facies and depositional environment in controlling the orientation and quality of the reservoir, an integrated analysis of borehole images, open hole logs and core data from wells spread across the field was successfully attempted. Fifteen identified generic image facies principally based on lithology and reservoir quality with core data validation were grouped into six genetically related associations. Facies recognition used criteria of image textural variations, dip patterns, direct recognition of features and relationships of cementation, bioturbation and sediment deformation. Statistical analysis of the identified sandy facies of upper reservoir unit indicated high abundance ratio and preferred distribution trend while no significant distribution trend observed for the lower reservoir unit. Observations from the image and core data helped to define depositional environment and sub-environments. Results indicate that depositional setting was created by succession of several depositional environments such as shore face, coastal plain of fluvial & distributary channels and lagoon. The high angle cross-bed features distinctly noticed are interpreted to be deposited in confined depositional environment of channel sand bodies, suggesting a major paleo sediment transport orientation. The marine shale deposited during a major flooding event on top part of the hydrocarbon bearing reservoir acts as cap rock. Tight carbonate cemented sandstone intervals also identified at various levels within the reservoir. In general, the formations exhibit distinct episodes of regression and transgression events marked by erosive and flooding surfaces. The identified rock facies relationship and depositional environment provided significant lead in formulation of full field geological model.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.