Carbonate reservoirs dominate 70% of oil and 90% of gas reserves in Middle East region, and imbibition is the main mechanism for fracturing fluid up-take during hydraulic fracturing stimulation process. Due to highly heterogeneous nature of tight carbonate source rocks, it is crucial to understand effects of the imbibed fluid on the mechanical, morphological and flow properties of the carbonate rocks. While the influence of imbibed fluids on the wettability of carbonate reservoir has been studied intensively, the research on effects of imbibed fluids on the texture and mineralogy of the carbonate rocks is very limited. This paper aims to provide a conceptual approach and workflow to characterize and quantify microstructure and mineralogy changes resulting from the imbibed fluids. A thin-section of low permeability organic-rich carbonate rock sample with a dimension of 7mm × 7mm × 0.3mm (length × width × thickness) was used in the study. The sample was submerged into 2% KCl (pH = 7.1) fluid from one end to simulate the spontaneous imbibition process. Scanning Electron Microscope (SEM) was used to capture the sample’s morphological change before and after spontaneous imbibition. Energy Dispersive Spectroscopy (EDS) mapping was used to study mineralogy changes (dissolution and precipitation) before and after fluid treatment. Inductively coupled plasma (ICP) equipped with optical emission spectrometer (OES) detector has been used to quantify dissolved ion concentrations in the treatment fluid. Permeability and porosity were measured using core plugs (1" in diameter × 1.5" in length) before and after imbibition process with half-length of the sample submerged into the treatment fluid. The SEM images for the thin-section sample show three zones with distinct fluid up-take characters. In Zone I, which was submerged into the testing fluid, considerable mineral dissolution has been observed. In Zone III, which was above the testing fluid level, considerable mineral precipitation was detected. While in the transition zone (Zone II, which was between the above two zones around the water-air level), minor amount of mineral dissolution was observed. The mineralogy changes resulting from the dissolution and precipitation have been identified by EDS analysis in all three zones. Gypsum and calcite were found to be dissolved in the imbibed fluids, while gypsum was found to be deposited on the rock surface in zones above fluid level. The observed gypsum deposition might result from the dissolution of the gypsum and calcite and re-precipitaion later from the imbibition experiment due to water evaporation and/or from sample drying process. Absolute permeability and porosity measurements for core plug samples show that both increased after the imbibition process.

This paper focuses on a tight carbonate reservoir in a giant field in Abu Dhabi by identifying shortcomings in conventional modeling strategies for geomechanics and demonstrating the benefits of continuous core data to build more reliable 1-D Mechanical Earth Models (MEM). A 1-D MEM was built from the sonic wireline log, which shows significant difference with a profile of ultrasonic P-wave velocity (Vp) measured on cores. However, results of rock mechanical tests (RMT) on plug samples (including ultrasonic Vp measurements at different stress conditions, and stress-strain curves from triaxial tests) are consistent with the core-based Vp profile. We investigate the impact of stresses, resolution and fluid saturation on sonic velocities to reveal the possible shortcomings of sonic wireline logs as an input for geomechanical models and the greater relevance of using core based ultrasonic velocities measured on dry cores for the upscaling of static elastic moduli. Finally we propose an empirical relation to correct sonic wireline logs for geomechanical modeling in offset wells. The following conclusions can be drawn from this study: The core based Vp profile, which is highly consistent with the RMT results, ultimately leads to opposed trends in the in-situ horizontal stresses predictions compared to those of a 1-D MEM based on the non-calibrated wireline sonic log. Only unrealistic reservoir stress conditions could reconcile ultrasonic Vp measured on plugs at different stress states with wireline sonic velocities; Using a low resolution Vp profile at reservoir stress conditions (combining Vp from plug samples and core based continuous Vp profile), we show that differences in stress only partially explain the discrepancy between velocities measured on plugs and wireline sonic velocities. Although a conventional Gassman fluid correction could explain the remaining differences between core measurements and the wireline sonic, its practical application would require the detailed knowledge of the rock mineralogy and of the saturation along the well. Conversely, a profile of the bulk modulus of the rock mineral fraction can be derived from the sonic log and the ultrasonic P-wave velocities measured on dry cores corrected for stresses effects. Evidences in the drilling data suggest that the discrepancies between the core based sonic velocities and the wireline sonic could be due to natural fractures in the borehole vicinity. An empirical relationship involving wireline logs only was established to correct the sonic wireline log to enhance the reliability of geomechanical models for offset wells. These findings have important implications for the practical applications of 1-D MEM, such as the design of hydraulic fractures. Quality control of the sonic logs with extensive data acquired on dry cores reduces the uncertainty when upscaling static elastic properties. Continuous velocity profiles acquired on dry cores are therefore highly valuable to calibrate empirical corrections of sonic logs for geomechanical modeling in offset wells.

The overall objective of the project is to develop a water shutoff chemical (Sealant), which can be used by Saudi Aramco to control excess water production in carbonate formations. Excessive water production from hydrocarbon-producing wells can adversely affect the economic life of the well. It was estimated that an average 2.8 barrels of water is produced for each barrel of oil worldwide. A new water shutoff polymer system was developed for carbonate formations. The developed system can bond to carbonate and shows great stability. The major challenge of water control in carbonate reservoirs are polymer bonding to the rock surface. Most of the commercial products are designed for sandstone formations. Most polymers will not strongly adsorb to carbonate reservoirs particularly under high fluid flow or high salinity. The polymer system developed is designed to overcome this and chemically bond the polymers to the surface of the carbonate. A well-defined polymer system with the ability to chemically bond to carbonate surfaces were also realized which represents the first example of an adsorption system for carbonate reservoirs and could have broad reaching applications. This represents a significant breakthrough as this can overcome one of the key obstacles of water control in carbonate formations. This paper demonstrates the laboratory work carried out to develop and investigate the efficiency of Smart Sealant, compared with Organically cross linked polymer (OCP), in both Supper-K and fractured rocks. Core flow testes indicate significant drop in water production for both fractured and Supper-K formation. When chemical treatments were applied, the polymer system was able to withstand the differential pressures and did not allow the flow of water in both high permeability cores and fractures. Coreflood results indicate that OCP was unstable with carbonate core sample and leached out after 4 pore volume of brine injection. ESEM and EDS analysis confirmed that the Smart Sealant treatment of the core plug resulted in some of the used polymer product blocking fractures and pores. This finding confirms adsorption and stability of Smart Sealant polymer on the rock surface, blocking fractures and reducing permeability of fractured core samples.

This paper is focused on the integration of two laboratory centimeter-resolution logs of mechanical properties (strength and compressional elastic-wave velocity Vp) into an enhanced core analysis workflow for the geomechanical characterization of unconventional reservoirs in a giant field in Abu Dhabi, where fracking is the cornerstone for producing the unconventional oil. The design and placement of hydraulic fratures rely strongly on the a-priori knowledge of the stress profile and brittleness index, which were estimated via a mechanical earth model constructed from wireline logs and correlations based on US shales analogues. With most of the stratigraphic column in the Abu Dhabi field composed of carbonates, the calibration of the mechanical earth models was found critical as the US shales based correlations would otherwise not have been suitable to the geomechanical characterization of these tight carbonate reservoirs. With this case study we illustrate: How the combination of the continuous profiles of rock strength UCS (Uniaxial compressive strength) and P-wave velocity measured directly on dry cores with the scratch tests contributes to the identification of different Geomechanical Facies, How the mapping of several Geomechanical Facies enables the building of a simple yet robust relationship between the UCS measured directly on cores and properties such as the total porosity and acoustic velocities of sonic waves, obtained from wireline logs, and How the centimeter-resolution profiles of strength and elastic wave velocities measured on dry cores enable the proper upscaling of geomechanical properties measured on plug samples to the entire cored section and the computation of a horizontal stress and brittleness profiles derived from unbiased geomechanical properties. From this case study follows a general discussion on the relevance of wireline sonic logs relative to centimetric resolution data (scratch profiles or plug measurement) acquired on dry cores for the geomechanical characterization of reservoirs. We conclude that measurements on dry cores enable the more robust calibration of mechanical earth model and in turn better description of the reservoir mechanical response. The upscaled profiles of horizontal stress and brittleness index derived from dry core measurements would ultimately lead to an alternative strategy for the design and placement of hydraulic fractures along producing wells.

Numerical computations from X-ray micro-computed tomography (MCT) images yield dynamic flow, petrophysical, and elastic properties which are conventionally obtained from subsurface logs or laboratory measurements on core plugs. These Digital Rock Property (DRP) determinations in most cases have significant advantages in accelerated turnaround time and lower cost, and in the non-destructive nature of the process. Despite these advantages, several limitations prevent this otherwise promising new field from replacing conventional laboratory measurements. Two primary ones are in the areas of gray scale image segmentation, and extrapolation of properties computed at small sample sizes to larger sizes at which laboratory measurements are made, These limitations are particularly severe for carbonate reservoirs, where pore types and pore networks have greater heterogeneity and complexity than exist in clastic rocks. This paper focuses on digital texture analysis and classification of MCT images not routinely exploited in conventional DRP applications. We demonstrate that such analysis provides valuable information that improves the quality of physical property computations made from MCT images. In particular, we investigated texture-based image processing techniques that address the known limitations of DRP technology, using multi-resolution MCT images of core plugs and micro-plugs from an early Cretaceous-age supergiant carbonate reservoir in the Middle East. These plugs represent a variety of carbonate facies: grainstones, packstones, and wackestones, with porosities in excess of 20%. We adopted an approach to gray scale segmentation that has a physical basis in separating pores from grains. Our segmentation process yielded computed porosities that are in reasonable agreement with laboratory measured values. To extrapolate rock properties measured at small sample scales to those at larger scales e.g. at which laboratory measurements are typically made, we use textural classification, with textural classes calibrated to measured or calculated rock properties. Textural classification has the added benefit of providing an objective basis for rock typing, in contrast to the subjective industry practice involving descriptions of thin sections. Rock typing is key to the extrapolation of core-derived rock properties in reservoir simulation models, and digital textural classification provides the capability for sensitivity studies during extrapolation. Several computational rock physics models used in the petroleum industry make simplifying assumptions regarding the pore systems in reservoir rocks. For example, the Gassmann equation used in elastic property modeling assumes homogenous grain and pore distribution, with connectivity of all pores. To better understand the complexity of the pore framework and network in our carbonate samples relative to such assumptions, we extracted from MCT images pore attributes that influence flow, petrophysical, and elastic properties. These include pore shape, size, orientation, throat size distribution, connectivity, tortuosity, and relative volumes of connected and isolated pores. These pore attributes enable the use of effective medium rock physics models that compute elastic moduli. We tested the Xu-Payne Differential Effective Medium Model using pore attributes derived from MCT images of our carbonate samples, and found agreement with the results of more sophisticated Finite Element Modeling, and with results from other theoretical modeling studies of carbonate rocks.

A study was aiming to evaluate the remaining oil saturation (ROS) behind the flood front using Liquid Trapper technology and open hole logs. Four (4) wells were included in this study, two in the South and two in the North of the field. These wells were selected in areas highly flooded by peripheral water injection. The objective is to improve the description of ROS and better estimate the oil recovery efficiency from the field. The Liquid Trapper Coring technique is used to provide more accurate oil saturation data for the reservoir model. It was used in this project in particular to evaluate the remaining oil saturations in the flooded reservoir zones. The Liquid Trapper Coring is a technique to capture any oil that is expelled from the core (due to pressure change) by gas expansion as the core is raised to the surface. This volume of escaping oil can then be calculated over selected intervals and incorporated into the standard saturation analysis performed on the whole core sections. The oil saturation determination from core would give the expected remaining oil where as the oil captured in the trapper barrel would indicate any movable oil in the reservoir. The inner tube of the Liquid Trapper is made of stacked modules, 1m in length and each made up of closed ‘cells’. The cells allow capturing of the expelled fluids and segregation of oil, water and gas due to gravity difference. The fluids in the cells surrounding the core are collected to be added to the volume of oil saturation in the core. The volumes were measured in the laboratory by centrifuge and were added to the saturations measured using Dean Stark method. This case study presents the results and uncertainties of using Liquid Trapper Technology in ROS determinations behind flood front of water invaded carbonate reservoir zones. An assessment of this new technique, and its pitfalls in onshore reservoir applications is compared with conventional sponge core coring.

Abstract During a laboratory waterflood study, undertaken at reservoir conditions to provide representative displacement data for predictive reservoir simulation studies, an investigation into acquiring representative wettability showed preserved samples exhibited significantly more oil wet character than restored samples. Further investigations concluded that core retrieval and/or storage resulted in increased oil wet character. Preserved state samples were not therefore representative. Introduction Pressure support into this giant oil reservoir is currently being achieved by water injection. It was originally predicted that water breakthrough would occur around the turn of the century. However breakthrough was observed in a number of production wells significantly earlier than had originally been predicted. A study was initiated to improve the understanding of the underlying causes of this water breakthrough. It was concluded that one of the key uncertainties governing the ability to predict waterflood performance was the quality of water/oil relative permeability data. Although there was a large number of historic water/oil relative permeability data sets, there was also a large degree of scatter in these data. This scatter appeared to be due, in part, to the variety of experimental procedures used. It was therefore unlikely that historic displacement data would be valid for reservoir performance. A process study was therefore initiated to generate new data using more rigorous procedures, including ensuring that samples in the laboratory were at a wetting state which was representative of the reservoir. This representative wettability was investigated by comparing displacement characteristics using plug samples in two wetting states at full reservoir conditions using in-situ saturation monitoring techniques. Technical Approach The approach for ensuring that a reservoir representative wetting state was attained in the laboratory compared displacement characteristics on samples prepared in two different ways, preserved state and restored state. Preserved state samples are samples which have not been cleaned with any solvents. Removal of any mud filtrate and saturation with brine is achieved by flushing with simulated formation brine, prior to initial water saturations being acquired. The preserved sample is then aged at full reservoir conditions for three weeks. Restored samples are samples which have been previously cleaned to as water wet state as possible. Samples are saturated with simulated formation bring and then, once initial water saturations has been acquired, are aged at full reservoir conditions with live crude oil. Prior to any reservoir condition studies it is essential to ensure that initial water saturations are acquired which are distributed uniformly down the length of the plug samples. This is necessary to ensure: Representative wettability is achieved during restorating/ageing at reservoir conditions with live oil. Representative S or is obtained from the waterfloods because of the dependency on S or with S wi . Non uniform S wi does not result in an unstable waterflood and nonrepresentative S or . Trapped water (in strongly oil wet systems) does not cause an unstable flood and erroneous relative permeability data as well as suppressing initial oil permeabilities. As reservoir condition studies compare the displacement characteristics in preserved and restored samples, it is necessary to ensure that initial water saturations were successfully acquired in both preserved and cleaned samples.