Understanding rock properties and how they react under various types of stress is important to development of a geomechanical model before drilling. Some major geomechanical rock properties are described below. To first order, most rocks obey the laws of linear elasticity. In other words, the stress required to cause a given strain, or normalized length change (Δlk /ll), is linearly related to the magnitude of the deformation and proportional to the stiffnesses (or moduli), Mijkl. Furthermore, the strain response occurs instantaneously as soon as the stress is applied, and it is reversible--that is, after removal of a load, the material will be in the same state as it was before the load was applied.
Actually, the definition of a tight gas reservoir is a function of many factors, each relating to Darcy's law. The main problem with tight gas reservoirs is that they do not produce at economic flow rates unless they are stimulated--normally by a large hydraulic fracture treatment. Eq. 7.1 illustrates the main factors controlling flow rate.
Any reservoir simulator consists of n m equations for each of N active gridblocks comprising the reservoir. These equations represent conservation of mass of each of n components in each gridblock over a timestep Δt from tn to tn 1. The first n (primary) equations simply express conservation of mass for each of n components such as oil, gas, methane, CO2, and water, denoted by subscript I 1,2,…, n. In the thermal case, one of the "components" is energy and its equation expresses conservation of energy. An additional m (secondary or constraint) equations express constraints such as equal fugacities of each component in all phases where it is present, and the volume balance Sw So Sg Ssolid 1.0, where S solid represents any immobile phase such as precipitated solid salt or coke. There must be n m variables (unknowns) corresponding to these n m equations. There are m 2n 1 constraint equations consisting of the volume balance and the 2n equations expressing equal fugacities of each ...
Steam generation for the purposes of thermal recovery includes facilities to treat the water (produced water or fresh water), generate the steam, and transport it to the injection wells. A steamflood uses high-quality steam injected into an oil reservoir. The quality of steam is defined as the weight percent of steam in the vapor phase to the total weight of steam. The higher the steam quality, the more heat is carried by this steam. High-quality steam provides heat to reduce oil viscosity, which mobilizes and sweeps the crude to the producing wells.
The difficulty in obtaining a continuous rock elastic properties (REP) profile from triaxial test makes calibration of geomechanical characterization models subjective. The impulse hammer method however provides reliable, reproducible, and continuous proxy for REP dataset, allowing for rock profiling. The relationship between the REP from these two techniques is not well understood, this study employed multivariate data reduction analysis and modeling to extract relevant correlations between Impulse Hammer and Triaxial derived REP. We derived a Young's modulus proxy called reduced Young's modulus (E*) from core plug samples. The E* was acquired from each sample systematically with respect to rock heterogeneity, grain size, and macropore size. The E* was taken as an average of nine impulse hammer runs per sample on equally spaced gridded location on each sample surface. Dynamic Young's modulus (Ed) and static Young's modulus (Es) were derived from the conventional triaxial test. The geochemical analyses were carried out to capture the mineralogical variations in the selected samples. We used statistical analysis and modeling to establish empirical relationship between Impulse Hammer and Triaxial derived RMP.
The results showed that, E* reliably captures the variables within the rock elastic properties. A strong correlation between the Ed, Es, and E* were observed in the samples. We also observed that E*, reveals details of several geomechanical heterogeneity and anisotropy which are not possible with traditional triaxial method. The results show that the empirical relationship between E and E* can be established to generate a continuous REP profile.
Sample availability, representativeness, time, and cost are common challenges in traditional triaxial test. The Impulse Hammer method is a non-destructive technique that significantly saves time, and has a promising cost efficient workflow, which provides reliable, reproducible and continuous rock mechanical properties profile. A robust geomechanical characterization and model calibration can be performed by combining the outputs obtained from these two methods.
Objectives/Scope: Understanding that capillary forces will act to limit petroleum fluid saturations in water-wet fine-grained rocks, including organic rich source rocks, dates back at least to Hubbert (1953). Likewise, Philippi (1965) noted relationships identifying sorption in/on organic matter as a significant storage mechanism in organic-rich rocks. Contrast these early insights with current unconventional reservoir evaluation, where we observe a disconnect between in situ (core exhumed to surface) measured total water saturations vs. the produced cumulative water volumes from a given stimulated rock volume. Water-free production in gas shales, from gas-wet organic matrix pores, created an early impression that unconventional plays don't produce water. So, in more liquid-rich plays, water cuts were initially under-appreciated: e.g. >80% in the Wolfcamp (stock-tank basis). If measured Sw is so low (core-based calibration), where is the water coming from; or is there an alternative method to more accurately relate in situ to produced water and petroleum production?
Methods/Procedures/Process: Adapting organic sorption models from the 80's, we can split total hydrocarbon volatiles into sorbed and, by difference, non-sorbed (fluid phase) yields. Converting to volumes and adding back dissolved gas using a formation volume factor (FVF) we can estimate the bulk volume fluid phase. This new approach then yields observations regarding remaining water-filled pore volume versus sorbed and non-sorbed hydrocarbon volume explaining the high water cuts in the Permian Basin stratigraphy; and additionally may indicate sweet spots in pore systems in different parts of the rock compared to alternatively derived saturations.
Results/Observations/Conclusions: The final piece of the puzzle comes from basin modeling of petroleum charging in the 90's. Some scientists applied conventional reservoir relative permeability to fine-grained rocks, but new research predicted that progressively finer grained rocks with higher irreducible water should be able to flow oil at progressively higher Sw: at 100nD, both oil and water should flow at Sw > 80%. Lower petroleum phase saturations and adjusted relative permeability curves may better explain observed production behaviors and profoundly alter our view of recovery factor and stimulated rock volume.
Applications/Significance/Novelty: The method offers an alternate and independent method to Dean-Stark-based core / SWC saturation analysis and its pitfalls. Saturation patterns after removal of immobile sorbed oil are different to those derived using the Dean-Stark based method, implying sweet spots / landing zones can be further optimized even in maturing shale plays. Lower oil-in-place – representing only the potentially mobile fluid phase petroleum – means that fracture stimulation has a higher recovery factor than previously thought, with profound effects on the infill volumes / opportunities for future field developments and therefore ultimately for US – and global – oil supply projections.
Interdisciplinary Components: Cross-over technology from organic geochemistry to petrophysics to reservoir engineering.
The Jurassic age Hanifa and Tuwaiq Mountain Formations are regionally established source rocks that charged majority of the oil fields in the region. These formations are comprised of dark carbonate mudrocks with high organic richness and dominantly calcite mineralogy. Several studies were conducted regionally to evaluate the potential of these Jurassic intervals as an unconventional play.
In April 2018, The Kingdom of Bahrain announced the discovery of a major unconventional resource in Khalij Al Bahrain basin following the production of light oil from Tuwaiq Mountain Formation. These results confirmed the viability of the Jurassic source intervals as an Unconventional asset. However, the nature and the location of the resource present a number of operational challenges in a region where development of unconventional resources is at its infancy. This instigates the need to address and tackle these challenges through innovative approaches to enable the effective appraisal and subsequently development of the asset.
This publication introduces the emerging unconventional play in Khalij Al Bahrain basin and discusses the adopted strategies to appraise and develop the asset. The areas for optimization considered include well design, drilling and completion, facilities and shallow offshore/onshore logistics.
The Hanifa and Tuwaiq Mountain formations are Jurassic in age (Figure 1) and consist of a mixed section of dark organic rich limestone beds. These formations are regionally established as the principle source rock that charged majority of the overlying Jurassic reservoirs in the region, and in Bahrain, the cretaceous reservoirs as well. These source rocks are the main targets of the recently discovered Khalij Al Bahrain (KAB) basin in Bahrain with initial resource estimates indicating potentially up to 80 billion barrels of unconventional oil and 14 trillion cubic feet of gas in place.
Location and Geological Settings
KAB basin is located in the eastern part of the Arabian basin straddling the area towards the east of Saudi Arabia, west of Qatar Arch and south of the Zagros fold belts. Majority of the basin today falls within the land bound shallow waters around the main island of Bahrain. Major fields in the area include Awali, Dukhan and Abu Safah which are likely to have been sourced from these Jurassic source rocks (Figure 2). KAB basin also lies in close proximity to the Jafurah basin which is a significant Jurassic unconventional play in Saudi Arabia targeting the same formations .
Resin coated proppant is used in hydraulic fracturing applications to stimulate oil/gas wells for production enhancement. The objective of this study was to perform a rock mechanical study to evaluate long term stability of RCP combined with various additives currently being used in screenless propped hydraulic fracturing completions in the sandstone formations to provide a tool for the industry to know exactly the duration of the shut-in time before putting well back in production. A new experimental method was developed to monitor the curing process of resin-coated proppant as temperature increases. The velocity of both shear and compressional waves were being monitored as a function of temperature. The tested resin of coated proppant sample has been housed in a pressurized vessel. The pressurized vessel was subjected to varying temperature profiles to mimic the recovery of reservoir temperature following propped hydraulic fracturing treatment. The placed proppant should attain an optimum consolidation to minimize proppant flow back.
Historically, sand production from poorly consolidated and unconsolidated sand formation, is a serious problem. These problems can lead to lost reservoir productivity, increased rates of required workover expenditure, fines plugging gravel packs, screens, perforations, tubulars and surface flow lines or separators. These problems hamper hydrocarbon production.
One of the major challenges, in comparing unconventional well performance during the appraisal phase, is the lack of long-term production data. In unconventional reservoirs, the main factor impacting well production is the generation of long effective fractures and large stimulated reservoir volumes (SRV). Different fracturing techniques are commonly tested during the appraisal phase, to find the best technique to maximize hydrocarbon recovery. Therefore a more robust methodology is required to analyze the production for a limited test period during the initial flow back.
This paper summarizes the application of the Rate Transient Analysis (RTA) to assist the selection of the best fracturing technique, through the estimation of the effective fracture length and a well potential index. The applied technique uses both the hydrocarbon and water production to characterize the initial fracture network performance. The implemented workflow factors in production data collection, flowing bottomhole pressure calculations, definition of fluid type at reservoir conditions and reservoir characteristics, and diagnostic plots generation. First, the methodology starts with calculating and plotting the rate normalized pseudo pressures vs. the square root of time for the total hydrocarbon rate and the equivalent plot for the water. If the wells were producing in a linear flow regime, the resultant slope of the straight line would provide the well potential index, which is a function of the product of the fracture half-length and the square root of the reservoir permeability. A calibrated permeability model from petrophysics was used as an input, to calculate the effective fracture half-length for each of the analyzed wells. These measured parameters allowed for the comparison of different fracturing techniques in a consistent framework.
The analysis was implemented in several wells where different frac techniques had been tested, among these were conventional crosslink, hybrid fracs, and slickwater. This methodology was successful on identifying which frac technique consistently provided the longest equivalent fracture half-lengths and SRV. It was found that the linear flow in the subject unconventional reservoir starts after a few hours of production, and extends up to the maximum produced time on the wells studied, which was 6 months. Results from pad well cases clearly confirmed the most effective stimulation strategy for the development scenario.
The workflow assists the completion optimization process during the appraisal phase for unconventional fields, where short production data is available. The proposed workflow helps production engineers in the decision-making process to select the best technique and perform initial flowback troubleshooting.
Gas production from shale formations is growing, especially in the USA. However, the origin of shale gases remains poorly understood. The objective of this study is to interpret the origin of shale gases from around the world using recently revised gas genetic diagrams. We collected a large dataset of gas samples recovered from shale formations around the world and interpreted the origin of shale gases using recently revised gas genetic diagrams. The dataset includes >2000 gas samples from the USA, China, Canada, Saudi Arabia, Australia, Sweden, Poland, Argentina, United Kingdom and France. Both free gases collected at wellheads and desorbed gases from cores are included in the dataset. Shale gas samples come from >34 sedimentary basins and >65 different shale formations (plays) ranging in age from Proterozoic (Kyalla and Velkerri Formations, Australia) to Miocene (Monterey Formation, USA). The original data were presented in >80 publications and reports. We plotted molecular and isotopic properties of shale gases on the revised genetic diagrams and determined the origin of shale gases. Based on the distribution of shale gases within the genetic diagram of δ13C of methane (C1) versus C1/(C2+C3), most shale gases appear to have thermogenic origin. The majority of these thermogenic gases are late-mature (e.g., Marcellus Formation, USA and Wufeng-Longmaxi Formation, China) and mid-mature (associated with oil generation, e.g., Eagle Ford Formation, USA). Importantly, shales may contain early-mature thermogenic gases rarely found in conventional accumulations (e.g., T⊘yen Formation, Sweden and Colorado Formation, Canada). Some shale gases have secondary microbial origin, i.e., they originated from anaerobic biodegradation of oils. For example, gases from New Albany Formation and Antrim Formation (USA) have secondary microbial origin. Relatively few shale gases have primary microbial origin, and they often have some minor admixture of thermogenic gas (e.g., Nicolet Formation, Canada and Alum Formation, Sweden). Two other revised gas genetic plots based on δ2H and δ13C of methane and δ13C of CO2 support and enhance the above interpretation. Although shales that contain secondary microbial gas can be productive (e.g., New Albany Formation, USA), the resource-rich, highly productive and commercially successful shale plays contain thermogenic gas. Plays with late-mature thermogenic gas (e.g., Marcellus Formation, USA and Wufeng-Longmaxi Formation, China) appear to be most productive.