The development of unconventional hydrocarbons has become a significant resource, leading to growth of worldwide oil and natural gas supplies. Hydraulic fracturing has been successfully employed for unconventional oil and gas recovery for decades. In recent years, the rapid progress of technology has led to reduced gas prices and a shift in focus to liquid extraction.
However, liquid flow, both in the wellbore and channels inside porous media or fractures, experiences more resistance compared to gas, resulting in significant pressure losses in the wellbore and fractures. Reservoir productivity also becomes more complex because of relative permeability effects. Forecasting production and estimating shale reserves is still not fully understood because of the limited knowledge of flow mechanics in ultralow-permeability rock.
Many analytical, semi-analytical, and numerical models have been developed to better understand flow in ultralow-permeability rocks and hydraulic fractures. Because analytical models only apply to mostly dry gas reservoirs, numerical reservoir simulation is generally believed to be the most rigorous and accurate method for liquid-rich formations. However, the drawbacks of using reservoir simulation are substantial. Some examples include the significant data requirements, level of expertise required to set up the model, and the demanding turnaround times for meeting the design, optimization, and decision-making cycle deadlines. Also, because each engineer is responsible for a large number of wells, full-scale three-dimensional (3D) reservoir modeling is impossible for a majority of wells.
Therefore, an approach is required that is less time-consuming than detailed reservoir simulation while still being sufficiently accurate to capture the physics of the process. It should be based on numerical modeling of multiphase flow in the interconnecting system of the wellbore and fractures, with the reservoir represented by a productivity index (PI) inflow model, as well as a physics-based pressure-volume-temperature (PVT) model for phase transition and phase equilibrium. The production decline and prediction should be analyzed based on reservoir depletion, relative permeabilities, and fracture conductivities.
This paper describes a numerical fracture production model (FPM) based on the previously mentioned physics that can be used to simulate production resulting from reservoir depletion and analyze historical production data. The outcome of the model focuses on a few primary input parameters that are dedicated to predicting future production and quickly analyzing the parametric effects and economic value of fracture-stimulated condensate reservoirs. The model is validated using two commercially available software programs, as well as historical production data of an Eagle Ford play. The outputs are then used for history matching, sensitivity analysis, parameter optimization, and future production prediction.
Microseismic monitoring of refracturing of depleted horizontal wells frequently shows a concentration of microseismic activity at the heel area when no mechanical isolation is used. This observation suggests that a considerable length of the well toward the toe does not benefit from refracturing and remains unstimulated. Different completion techniques, ranging from injecting diverters to using mechanical intervention methods, are usually used to avoid the localized stimulation and to enhance the treatment effectiveness. However, often overlooked is the effect of the reservoir rock's mechanical characteristics and how they contribute to the treatment results.
In this study we investigated the potential contributing factors to the observed microseismic response: i) fluid pressure drop along the lateral, ii) diverter ineffectiveness, and iii) stimulation of pre-existing fractures versus developing fresh fractures from new perforations. Estimation of pressure losses along the well for the common casing diameters and fracturing fluids indicates that a high pressure gradient develops along the well during refracturing. It results in significantly higher injection pressures at the heel than at the toe, leading to higher discharge rates at the heel. If the added diverters fail to seal off the perforations at the heel area, this condition persists throughout the treatment and causes the localized stimulation of the rock, as is usually observed by microseismic monitoring.
The numerical simulation of refracturing indicates that under a non-uniform treatment pressure profile and in the absence of effective diverters, the initiation and propagation of new hydraulic fractures is unlikely. The dominant stimulation mechanism is the shear failure of natural fractures, driven by the increase of fluid pressure by injection of fluid through the old perforations. This result is consistent with the observed long delay in microseismic response to refracturing and the increasing event counts as pumping continues.
Based on these findings, we developed an alternative refracturing method that aims at increasing the reservoir effective complexity and enhancing the conductivity of the pre-existing hydraulic fractures uniformly along the well. The proposed method consists of a prolonged low-pressure and low-rate pad stage to pressurize the reservoir, followed by a high-pressure injection stage to stimulate the pressurized natural fractures and to place proppant in the new fractures. Critical to the success of this method is to avoid a high pressure contrast along the well. This can be achieved by proper selection of injection pressure and fluid viscosity with respect to the reservoir stresses and pressure, and the well characteristics. Numerical simulations indicate that the proposed method can considerably enhance the efficiency of refracturing, at no additional cost compared to the common refracturing methods.
The Delaware Basin in western Texas and southeast New Mexico is one of North America's most prolific oil-producing regions. Recent activity in southeastern New Mexico has begun to examine the uppermost Wolfcamp Formation (Permian). This interval has been examined in a Devon proprietary core (Lea County, New Mexico) where it is composed of two prominent facies associations. The first is dominated by fine-grained carbonates and calcareous siltstones/mudstones, which are interbedded with organic-rich, non-calcareous mudstones. The second facies association is dominated by dolomitic siliciclastic siltstone/mudstone facies. Both facies associations have comparable porosities, but the carbonate facies have significantly less permeability. The facies are largely organized into fine-grained turbidites derived from different source areas. Each facies association is separated into its own basin floor fan complex with some interfingering between the two associations. The carbonate turbidites were derived from the east off the Central Basin Platform whereas the siliciclastic–dominated turbidites were derived from a source to the west-northwest. The latter strongly resembles the siliciclastic turbidite facies of the overlying Bone Spring Formation. The carbonate turbidites exhibit TOC values that can range from 0.6% to 3.5%, whereas the siliciclastic turbidites generally contain less than 1%. The non-calcareous mudstones that interfinger with the carbonate turbidites preserve as much as 8% TOC. A significant proportion of the TOC within the carbonate turbidites and the interfingering non-calcareous mudstones was derived from terrestrial organics as evidenced by well-preserved fern-like plants with fully articulated leaves (peltasperms). Their presence within the carbonate turbidites indicates that the Central Basin Platform was subaerially exposed during their deposition and indicates carbonate production during a falling to low-stand systems tract. Since these plants are found in both the upper parts of the carbonate turbidites and the non-calcareous mudstones that cap the turbidites, it suggests that the carbonate tubidites rheologically stratified as they flowed, evolving into a carbonate detritus-dominated head and body with a non-calcareous mud wake. Molecular composition, biomarker, and carbon isotope chemistry of oils produced from Wolfcamp reservoirs also indicate that these oils were derived from mostly marine type II with a contribution from type III kerogens.
The association of well-preserved terrestrial leaves (peltasperms) with carbonate turbidite and debris flow facies within the upper Wolfcamp section of the Permian basins of West Texas and New Mexico creates a bit of a dichotomy. Why are well-preserve leaves that are fully articulated to stems being transported into a deep marine system and out on to a basin floor within sediment gravity flows that were clearly sourced from marine deposits? This is particularly vexing when one considers that siliciclastic-dominated, fluvially sourced sediment gravity flows also exist within the Wolfcamp section, but the organics associated with these deposits are composed of finely ground plant debris.
Recent drilling results have highlighted the potential for the development of Jurassic source rocks of southern England as a shale oil play. Sustained natural oil flows have been reported by UKOG (2015) from the tight, Lower Kimmeridge limestones in the Horse Hill-1 well. According to the operator, this discovery is naturally fractured and can be produced without hydraulic fracture stimulation.
The occurrence of shale gas in the UK has been known of since the nineteenth century, but development of this resource attracted very little interest until recent years (Selley, 2012; Andrews, 2014). The first exploration well in the United Kingdom that was specifically drilled for shale gas was Preese Hall-1 in northwest England in 2010. This well was hydraulically fractured in the Bowland Shale, but operations were suspended following reports of repeated seismicity caused by the injection of fluid during hydraulic fracture treatment (Green et al., 2012). Assessments of the Carboniferous shale gas potential of northern England and Scotland and of the Jurassic shale oil potential of southern England have been published by the BGS/DECC (Andrews, 2013, 2014; Monaghan, 2014). These studies listed the various criteria for evaluation of shale plays and provided broad descriptions and resource estimates for the Carboniferous and Jurassic shale plays in the United Kingdom.
This paper presents the results of an integrated petrophysical and geological assessment of the Jurassic sequence in the south of England. The study area stretched from the Weald and Vale of Pewsey Basins in the north to the onshore parts of the Portland–Isle of Wight Basin on the Dorset coast in the south (Figure 1). The evaluation focused on the Kimmeridge Clay Formation, the Oxford Clay Formation, the Downcliff Clay Member, Charmouth Mudstone Formation and the Blue Lias Formation.
The stratigraphic framework used for the study is based on the extrapolation of the well-known outcrop stratigraphy on the Dorset Coast to the study wells. Wireline log data and new sedimentological core description results were used to constrain facies mapping. Detailed sedimentological core description was carried out on three of the twelve study wells. From the trends observed in the wireline log data, the lithofacies and level of oxygenation, 14 initial facies associations were assigned over the cored intervals ranging from restricted shallow marine through shoreface to shelfal environments. These facies associations were grouped into seven combined facies associations which were used as input for the electrofacies analysis and facilitated the extrapolation of facies to intervals that lacked core data Additionally this workflow provided a useful template for estimating Total Organic Carbon TOC from logs using the CARBOLOG® equation and this resulted in a significant improvement in the correlation between the laboratory measured TOC values and the log-based TOC estimates. Results from the mineralogical analysis of core and cutting samples were utilised to calibrate and improve the petrophysical interpretations and to assess the elastic properties of the rocks in the intervals of interest. The petrophysical data, elastic properties and the facies interpretations were used to evaluate and map the development potential of the Jurassic source rock intervals as unconventional reservoirs.
An extensive geochemical database was combined with new analyses to characterise the source rocks. This data was integrated into 1-D basin models to identify and map effective source kitchen areas. The organic matter in the analysed interval is dominated by Type II kerogen, with significant input of Type III kerogen towards the London-Brabant Massif. The Upper Jurassic Kimmeridge Clay and the Oxford Clay are within the early oil window, while the Lower Jurassic Downcliff Clay Member, Charmouth Mudstone Formation and the Blue Lias Formation have reached peak oil maturity in the deeper parts of the Weald Basin. The source richness and kerogen types were combined with the maturity maps to create generation risk maps.
The risk for ground water contamination from hydraulic fracturing was also evaluated. These results were combined with the reservoir and generation risk maps to produce common risk segment maps in order to identify the sweet spots in the study area.
Despite the recent dip in oil prices, the inertia of the shale gas boom will continue to move forward and as prices normalize and industry adjusts, the production of shale reservoirs will continue. One of the keys to understanding these reservoirs and maximizing their output is a better measurement of the natural fractures in the rock and how these factures affect porosity.
Porosity is the single most important petrophysical property. For shale reservoirs it is also critical to understand the natural fractures in the rock. A key indication of the quantity of the natural fractures can be obtained by measuring the amount of porosity contained in the fracture network. Shales have very small pores and therefore very short NMR T2 relaxation times. The fractures are typically larger than the pores and therefore have longer T2 relaxation times.
In this work, we describe and demonstrate techniques using NMR that can obtain not only the total and effective porosity of shale samples but can also quantify the fracture porosity. Simple NMR measurements of the T2 relaxation time were performed at different confining pressures to quantify the porosity loss as confining stress increases. This loss in porosity is interpreted as closing of the natural fractures in the rock as shale is not typically compressible at these pressures.
The type and quantity of the fluid present in the shale is also of great importance. Bitumen (if present) can impact fracturing plans and production models. The relaxation times T1 and T2 are known to be affected by the viscosity of the fluid . We can therefore quantify bitumen present by measuring T1-T2 maps at different temperatures, as the bitumen viscosity will change with temperature. T1-T2 maps can also be used to quantify the amount of water present, as T1 and T2 are similar for water in shale. The results of this T1-T2 mapping from different shale samples at different temperatures will also be presented and discussed.
NMR has proven to be a valuable tool in conventional and unconventional oil and gas reservoir characterization. It is used in both logging and core analysis applications. Unconventional reservoir development in recent years has instigated an increase in NMR applications as conventional methods often fall short for proper characterization of unconventional reservoirs.
Liang, Baosheng (Chevron North America E&P) | Khan, Shahzad (Chevron North America E&P) | Puspita, Sinchia Dewi (Chevron North America E&P) | Tran, Tan (Chevron North America E&P) | Du, Song (Chevron North America E&P) | Blair, Erika (Chevron North America E&P) | Rives, Stephen (Chevron North America E&P)
In a low oil-price environment it is definitely challenging to conduct much data collection, particularly along horizontal section which in most cases only gamma ray log is acquired. As horizontal drilling activities have grown the areal heterogeneity in the unconventional play is revealed to be far more complex than what was initially thought. In order to address this complexity a 3D model is necessary to guide landing the horizontal well, designing the completion and determining the appropriate well spacing. Fortunately, 3D models can be built from the thousands of commingled vertical wells that exist in many development areas in the Permian Basin that provide valuable information, ranging from cores and logs, to pressure and production. In some areas, 3D seismic data exists to provide inter-well information. In this paper, we present an integrated workflow which utilizes multi-scale data from multiple sources that has been successfully applied to our unconventional reservoir factory-model development in the Permian Basin.
The proposed workflow adapts a top-down concept and fits factory-model batch development: progressing the model from a big 3D model to pad-scale and single well models. A fine-grid field-scale earth model covering tens of square miles including structure, reservoir properties and geomechanical properties is built based on existing vertical wells, newly drilled horizontal wells and seismic interpretation if available. A pad-scale model can be modified from the field model based on local information and used to evaluate multi-well interference, landing strategy and well spacing. A single well model with the smallest scale can be cut from the pad-scale model for landing and completion design. Hydraulic fracture with a discrete naturally fractured network is modeled subsequently and directly converted to unstructured reservoir simulation grid fitting reservoir simulator. The workflow forms an iterative process to update field-, pad- and well-models, as existing wells deplete and new wells are put on production through time. A case using more than 1,000 vertical wells from the Midland Basin will be presented, clearly demonstrating an approach to effectively leveraging all existing data and improving factory-model deployment.
In-house uncertainty analysis package is linked to both hydraulic fracture modeling and reservoir simulation. The package handles a variety of key parameters for hydraulic fracturing and flow performance, such as completions design, discrete fracture network (DFN) characterization and generation, unpropped hydraulic fracture properties, fracture compaction, and matrix permeability. The uncertainty analysis helps understand the relative impacts of different parameters and drive specific data collection.
Ning, Yang (University of Houston) | He, Shuai (University of Houston) | Liu, Honglin (Research Institute of Petroleum Exploration) | Wang, Hongyan (Research Institute of Petroleum Exploration) | Qin, Guan (University of Houston)
Accurate prediction of shale matrix permeability using numerical tools requires understanding of transport mechanisms in nano-scale, and upscaling from nano-scale to larger scale simulations. In this paper, the transport property of shale matrix is estimated by coupling the molecular dynamics (MD) simulation with the lattice Boltzmann method (LBM) on multiple-scale digital rocks. Digital rocks of shale samples at different scales from the Longmaxi formation are reconstructed. Pore structures of kerogen are reconstructed based on Focused Ion Beam-Scanning Electron Microscope (FIB-SEM), and the distribution of kerogen and different minerals is generated based on the Nano-Computed Topography (CT) scanning. The FIB-SEM digital rock exhibits many isolated macro-pores (>20nm), which makes the pore connectivity very poor. However, micro-pores exist abundantly in kerogen solids, and they significantly enhance the pore connectivity and the gas storage capacity. Therefore, we have built kerogen structures with pore size smaller than 5nm based on Type II kerogen molecules to represent kerogen solids. In addition, structures of clay minerals are built upon their chemical formulas.
In this work, we have developed an effective upscaling approach by coupling MD simulation with LBM, which can be summarized as: (1) Effective diffusivity coefficients of kerogen solids with pores smaller than 5nm are calculated using the non-equilibrium MD simulations, and so are clay structures with aperture of 2nm. (2) Effective permeability of the FIB-SEM digital rock with the macro-pore distribution is calculated using the generalized LBM model in porous media, in which the transport property of kerogen solids is given by MD simulations, and the transport property of macro-pores is assigned to the analytical solution of the Stokes flow. (3) Transport properties of clay structures by MD simulations and kerogen digital rock by LBM simulations are mapped stochastically on the corresponding types of voxels of the Nano-CT digital rock. The micrometer-scale permeability of Nano-CT digital rocks is then calculated using the generalized LBM model.
Al Duhailan, Mohammed (Saudi Aramco) | Boudjatit, Mohammed (Saudi Aramco) | Yeh, Nai-Shyong (Saudi Aramco) | Kurison, Ivan Leyva Clay (Saudi Aramco) | Alvarez, Angelica Rios (Saudi Aramco) | Ghamdi, Yasser (Saudi Aramco) | Shehri, Saad (Saudi Aramco)
An integrated analysis of abnormal pressures was conducted on organic-rich Jurassic mud rocks in Saudi Arabia. The integrated analysis included a combination of geochemical, petrophysical, geomechanical, and pressure transient analyses for the following objectives: 1) emphasize the importance of the kerogen transformation ratio (TR) as a key factor governing abnormal pressures in source rocks, 2) provide a regional understanding of the subsurface pressure environment that typifies the existence of unconventional resources in the Jurassic source rocks in Saudi Arabia, and 3) predict abnormal pressures to support the optimization of horizontal drilling and multi-stage hydraulic fracturing completion designs for maximizing estimated ultimate recovery (EUR), reducing cost and increasing efficiency.
Abnormally high pressures in source rocks are caused by the diffusion restriction of petroleum-generation pressures. Upon thermal maturation of organic matter, volume expansion, including organic- and inorganic-porosity development (i.e., petroleum-expulsion fracture porosity), is governed by the TR of the higher-density organic matter into lower-density petroleum fluids. The petroleum-generation pressure diffusion was simulated considering one-dimensional models of different sets of rock properties surrounding an actively petroleum-generating source rock with increasing the TR. Results indicate that at a high TR, there is inadequate elastic deformation (porosity dilation) of pre-existing organic and inorganic pore space to offer storage for all of the expelled petroleum. This imbalance between the rate of organic matter transformation and porosity dilation causes pressure to increase and fracture porosity to develop with 40% to 70% diffusion restriction for pressures. This restriction can maintain pressures above the regional normal hydrostatic pressure resulting in prolific, abnormally pressured hydrocarbon reservoirs.
A new integrated approach is introduced in this study for generating three-dimensional models for pore pressures in source rocks as follows: 1) estimate the TR through rock-evaluation data analysis, 2) apply total organic content (TOC) normalization and TR corrections to sonic log data, 3) use a modified TR-derived method for pore pressure prediction, and 4) build a three-dimensional property model for pore pressure.
Pressures were also estimated from the analysis of dynamic data (extended flow and pressure buildup data). The standard analysis method is enhanced to take into account the uniqueness of unconventional resources. A consistent estimate of abnormal pressures is obtained from this integrated analysis.
Field examples are also included to demonstrate the implications of this integrated methodology for the optimization of horizontal drilling and multi-stage hydraulic fracturing designs. Such integration can have a significant positive impact on productivity, cost reduction, and execution efficiency in developing unconventional resources.
While the active Lower Cotton Valley horizontal play in north Louisiana is receiving press and industry attention, individual horizontal wells, which are often close together, have demonstrated widely varying production results. The column of stacked pay sands can present targeting and fracture planning challenges because of varying pay quality and stress conditions. Typically two, or even three, individual target intervals can be present at any location, and accurate formation evaluation is crucial in deciding which zones to pursue and what fracture completion strategies to employ. This paper describes a custom vertical well evaluation workflow to address these challenges as a particular case study.
An enhanced logging suite using neutron capture mineralogy, magnetic resonance imaging, oriented acoustic dipole imaging, and electrical borehole imaging was deployed to address specific reservoir quality and stress conditions present in the primary Middle and Lower Poole sand pay zones and the Gray sand interval, a deeper secondary pay. Accurate mineralogy was used to quantify effective porosity and any clay reactivity issues with completion fluids. Magnetic resonance was used to quantify both permeability and free gas in the pay analysis. Oriented dipole data were used to quantify anisotropic stress conditions for accurate fracture modeling. Finally, borehole imaging was employed to identify natural fractures and possible faults, structural dips, and primary stress orientation for optimized horizontal placement.
Using the additional logs within the workflow, a larger picture of fracture stimulated reservoir deliverability was developed. Individual target zones were quantified by cumulative permeability-height (kH), analysis, and similar effective closure stress. This was used with a three-dimensional (3D) fracture simulator to achieve maximum fracture height design to contact the greatest volume of kH. This methodology was performed on the case study well, resulting in an actual Gray sand vertical production test and a recommendation of a Middle Poole sand as the primary horizontal target. The case study well results are discussed in depth and compared to predicted results.
This evaluation workflow is unique because it predicts fracture stimulated flow performance for each zone before actual completion. It can be used to make vertical pipe set or horizontal landing decisions soon after the openhole logging is completed to optimize individual well performance following stimulation operations.
Studies have shown that proppant injected into fractures during hydraulic stimulation rapidly increases in packing density as fluids leak off into surrounding rock. Stresses are amplified at proppant grain contacts elevating the potential for stress-corrosion cracking and chemical potential at the contacts. Together, these effects promote immediate mechanical compaction and drive chemical compaction throughout engineering time scales (Lee et al, 2010). Draining the reservoir further enhances stresses leaving the reservoir critically-stressed as fractures close. Injection of fluid induces microseismicity that generally propagates away from injection ports as fluid induces fractures at rates that can be modeled using a pressure-diffusion model (Shapiro, 2009). When the front encounters a depleted reservoir on offset wells, pressures accelerate through the fluid-filled pore network inducing shear failure causing microseisms with observed apparent propagation velocities much higher than typical fracture propagation rates and can be used to delineate depleted fractures (Dohmen, 2013) forming a snapshot of production in time.
Microseismic data were collected during the treatment of a four-well pad in the Williston Basin. After five months of producing hydrocarbons from the first pad, a second pad was also treated and monitored proximal to the first. Microseismic events recorded during the second pad treatment extended toward and accelerated across the first pad, with the majority of offset activity occurring on the well closest to the second pad. By combining hypocenter locations, seismic moments, focal mechanisms, fluid leakoff, treatment volumes, and rock properties, we created a calibrated proppant-filled Discrete Fracture Network (DFN) model for each pad. To further condition the model for the second pad, we extended the methods of Shapiro and Dohmen to define multiple pressure-diffusion fronts to classify events associated with injected fluid, the offset pad, and depleted portions of the reservoir and utilized only fluid related events.
Microseismic event locations monitored during the second pad coincide with the modeled proppant-filled fractures derived from the treatment of the first pad. Furthermore, events consistent with Dohmen's depletion zone coincide with distal producing wells over 6000 ft. away from injection ports. Results suggest that offset well microseismicity is associated with the more conductive offset proppant-pack and can be used to quantify the actual proppant distribution, validate the propped DFN model and identify compacted portions of the depleted reservoir.