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Historically, understanding and selecting a successful landing point candidate for horizontal drilling and fracturing was mostly performed based on a single-domain perspective or purely based on geoscience data sets. On the other hand, this paper proposes an unconventional multi-domain integration for shale oil and shale gas development for successful drilling and completions. In heterogeneous formations where organic-rich rocks are the source and reservoir, the geology and petrophysics along with engineering integration is a must for short- and long-term production and optimization. In this unconventional approach, petrophysical and 1D mechanical earth models were developed using triple combo (TCOM) and sonic by integrating in-situ core measurements to narrow down the uncertainty in the flow and mechanical properties. In the standard approach, landing points are mostly selected by looking for good petrophysical reservoir units with good porosity, good organics and low water saturation. However, these good petrophysical-rich rocks could be geomechanically highly stressed (both total and effective) and less brittle. Completion engineers mostly prefer to drill and frac low stress and brittle facies. This is because brittle rocks with proppant in the fractures can keep the fracs open for a longer time without getting into the embedment issues as a result of production. If embedment becomes an issue as a result of depletion in the highly stressed landed horizontal wells, then there is a possibility for significant drop in production sharply in short time. In this paper a few potential reservoir units are selected as landing points for horizontal drilling based on petrophysical derivatives followed by the geomechanical attributes of good brittle and low stress of the reservoir sections within the Najmah (NJW) and Sargelu (SRW) formations. For each landing point, frac modeling was performed to obtain height and length. Geometries from each landing point are different due to vertical geomechanical heterogeneity. These vertical stacking patterns for facies and properties combined with a certain completion design will determine the fracture propagation and pinch points vs. barriers. Generated frac heights from each landing point will be compared with petrophysics to understand the thickness of organic-rich intervals vs. water content. Based on the initial geometries from each landing point, completion optimization was performed by altering the rate vs. volume pumped to understand the variations in fracture height and length. This is to illustrate the completion vs. production cost economics based on single well modeling. Since Najmah (NJW) - Sargelu (SRW) organic-rich source reservoirs in Kuwait are in early appraisal phase, the data set lacks pressure and production history. Hence the validation of frac geometries is not discussed.

Minimum horizontal stress (Sh) is the controlling parameter when hydraulic fracture stimulating tight oil formations but is next to impossible to measure quantitatively, especially in the far field and away from the wellbore. In-situ stress differences between bedding planes control fracture containment, which defines the complexity of fracture propagation and fracture geometry including orientation, height growth, width, and length. Geomechanical rock properties define elastic behavior, influencing how the subsurface will deform under induced stress. These properties include dynamic and static Young's modulus, Poisson's ratio, and Biot's coefficient. When combined with pore pressure and overburden stress, the elastic rock properties describe the mechanical earth model (MEM), which characterizes the geomechanical behavior of the subsurface. The MEM also defines key inputs for calculating Sh using the Ben Eaton stress equation, which has been commonly used by geoscientists for decades. However, calculated Sh from this simple model historically produces uncertain results when compared to field-measured stress due to an assumed homogeneous and isotropic subsurface. This is particularly contrary to tight oil formations that represent shale (or mudrock) reservoirs that are highly laminated and therefore anisotropic. Optimal parameterization of fracture geometry models for well spacing and engineered treatment design requires an anisotropic far-field in-situ stress measurement that accurately captures vertical and lateral variability of geomechanical properties in 3D space. A method is proposed herein that achieves this by using a modified version of the anisotropic Ben Eaton stress model. The method calculates minimum Sh by substitution of inverted 3D seismic volumes directly into the stress equation, replacing the bound Poisson's ratio term with an equivalent anisotropic corrected closure stress scalar (CSS) term. The CSS seismic volume is corrected for anisotropy using static triaxial core and is calibrated to multidomain data types including petrophysics, rock physics, geomechanics, and completion and reservoir engineering field measurements.

The Permian Basin in North American has been the driving force behind global energy growth, resulting from the exploitation of unconventional resources. The combination of high quality stacked resources, horizontal drilling, completion tools, and hydraulic fracturing innovations has accelerated the learning curve in this basin over the past few years: which was the impetus of this study. This paper utilizes an integrated model approach to understand reservoir performance on a pad with four wells completed across multiple horizons in the Midland Basin. Rich multi-domain data sets were utilized that included seismic, wireline triple-combo, compressional and shear log suites, core (rock mechanics testing, geochemical analysis (XRF and XRD) and routine core analysis), completion data (fracture treatments with pre-and post-job shut-in pressures), and production data including 1,500 days of production history with bottom-hole pressure gauge data. 3-D surface seismic, high tier logs, and core data were used initially to create a facies model. Properties were distributed into a geo-model using the existing vertical well-control and seismic as constraints. A sector model was then built that enabled modeling of 4 development wells that consisted of parent well, followed by 3 child-wells. The history matching of fracture treatments and production data with bottom-hole pressure data resulted in significant understanding of key parameters driving subsurface performance. A workflow, representing the seamless integration of said models, is presented that enables an improved understanding of what impact sequence and timing of operations has on the subsurface contact area as well as the implied change in well performance if an optimal strategy is executed. Geomechanical facies that drive vertical connectivity and fracture geometry, as well as reservoir parameters that impact fracture contact with the reservoir, were identified.

The complex Spraberry trend extending 150 mi long and 75 miles wide covering the entire Midland Basin, and bounded on the west by the Central Basin Platform and on the east by the Eastern Shelf is characterized by its varying degrees of laminated layers of sandstones, siltstones, organic shale and carbonate mudstones. The rock fabric variability is a critical factor in understanding varying hydraulic fracturing responses in horizontal well completions. Optimized consistent fracturing design schedules were pumped bearing significantly differing outcomes in treatment pressure response, fracture parameters, proppant pack conductivity and ultimately well performance. The core of this paper discusses the impact of enhancing fracturing treatment design when integrated with well landing and placement, formation geological, petrophysical and geomechanical physiognomies recommending predictive measures that can significantly improve operational practices and results. 8 wells with 145 stage pressure responses were analyzed showing potential near well bore screenouts on numerous occasions during proppant laden steps. When this occurs, a wellbore volume of clean fluid (sweep) is injected to prevent the imminent screen out. These sweeps cause increased job times and require extra fluid which decreases the overall operational efficiency. The analysis developed improves the predictability of fracturing operations using drilling measurements and geomechanical attributes. A wellbore profiling method was developed utilizing geological, petrophysical and geomechanical attributes where rock types are identified along the lateral and are associated with a specific fracturing pressure response. Seven rock types were determined based on a combination of geological and petrophysical analysis. Geomechanical attributes were then used to further subdivide the groups to predict fracturing pressure responses. The latter was integrated with an engineered model to calculate dynamic perforation efficiency based on the change in effective flow area during the treatment stage. Observed pressure responses were history matched and the varying impact on fracture geometry was compared across stages pumped as per design and stages where screenouts had to be prevented using pre-mature or necessary sweeps. The developed wellbore profile accurately predicted expected pressure responses across all 8 wells. Rock types that provide the best combination of drilling, completions, and production enhancements can be successfully identified to make recommendations for lateral landing depths and completions design optimizations. Additionally, expected operational challenges can be predicted and accounted for in advance. The developed method reduces operational uncertainty and risk to a minimal level. Fracturing treatment pressure responses can thus be accurately predicted and accordingly required operational changes could successfully be planned to manage challenging sections of the wellbore. Planning for operational anomalies is critical to ensure successful fracturing treatments pumped as designed that which has a vital impact on created fracture geometry, ultimately affecting well production performance.

The North American unconventional resources energy growth driven by the combination of horizontal drilling, completion tools and hydraulic fracturing innovations has revitalized some conventional plays across the globe that were considered marginal prior to the unconventional boom. This paper presents the workflows utilized to implement unconventional technologies that have resulted in incremental hydrocarbon resources being unlocked. A multi-domain approach is utilized to understand the results from the application of horizontal drilling, completion tools and hydraulic fracturing innovations to the Turner play. High tier log and core data is used initially to create petrophysical and geomechanical models. Numerous petrophysical and geomechanical models are generated based on the uncertainty in model building. Appropriate models are selected based on fracture pressure matching and production history matching techniques. These models are then used to drive the design and optimization process of future offset wells. Characterization of the reservoir (permeability range, pressure and fluid saturations) has led to the understanding that completion techniques used in unconventional plays (slickwater fluid system with tight cluster spacing) cannot be blindly applied. An understanding of fracture geometry and reservoir quality enables changes to be implemented on lateral landing, stage count and job size resulting in incremental production. The importance of reservoir characterization and forward modeling of the application of horizontal technologies is crucial to ensuring efficient allocation of resources to maximize production. This paper showcases the application and evolution of unconventional technologies and workflows to conventional plays to gain incremental production results.

This paper covers the methodology to derive all geomechanical properties (Young's modulus, Poisson's ratio and vertical/horizontal variable Biot constants as a function of rock type) for 13 different stress models. Minimum horizontal stress (Sh) is a key parameter controlling fracture height growth during hydraulic fracturing simulation. Assuming a homogeneous formation (rock property Horizontal:Vertical = 1.0) or poorly derived inputs for the anisotropy model can lead to incorrect fracture geometry. A major assumption made using the various stress models is the Biot poro-elastic constant. Many default models assume a Biot poro-elastic constant of one, which is valid for coarse grained conventional reservoirs where porosity is greater than 20%. Most of the reservoirs stimulated with hydraulic fracturing today do not fall in that porosity range, therefore an alternative derivation for the Biot poro-elasticity and its variability requires additional discussion. Models derived and compared with their associated uncertainties in this paper include: Ben Eaton – isotropic, anisotropic, dynamic and modified with correction factor; default from auto log calibration; Vernik, Jaeger & Cook; Hubbert & Willis; Thiercelin – MC envelope and stiffness tensors (Cij); Segall & Penebaker. The geomechanical properties from the different stress models noted above were inserted into a gridded fracturing simulator. The outputs were compared to actual job and calibration data for; minimum horizontal stress, end of job net pressure and fracture geometry for each of the models. When comparing fracture geometries from each stress model against calibration data it is apparent that the chosen stress model will have a substantial influence on the result. This illustrates the importance of choosing the correct stress model for fracture simulations.

Until 2015, North America’s unconventional resource market was known to be home to the largest oil shale deposits of economic value. Although the recent commodity price fluctuations have exposed the role of geo-politics, world economies and commodity trading on the life cycle of assets, few field development studies have consider the impact of commodity cycles on the development of in-fill wells. Papers have been presented to demonstrate the impact of vertical fracture connectivity and fracture asymmetry on in-fill well performance (due to delayed in-fill drilling), but little has been done on validation and coupling the impact of depletion, due to production, and hydraulic fracturing (due to in-fill efficiency fracture operations). This paper presents results from the analysis of in-fill drilling on well performance. Production data, fracture treatment data, completion and production timing are analyzed using pressure/production history matching techniques and compared with results predicted by data driven models (developed to match well performance) with the aim of proposing in-fill development strategies. Analysis of the field production data indicates that timing of in-fill wells (following the parent well) can influence the in-fill production depending on the level of depletion (cumulative fluid produced) and the size/type of fracture treatments pumped. Analysis of raw production data, modeling results from multi-domain model based coupled simulations and high resolution monitoring data also indicates that the order of the in-fill operations (East-West, Zipper, etc.) also has a significant impact on performance. This paper presents a simplistic approach to understand the impact of the quest for operational efficiencies and economic cycles on development strategies.

When calculating the downhole stresses affecting a wellbore during depletion it has become a standard industry practice to assume only the pore pressure changes, and not the rock mechanical properties. This assumption has the potential to underestimate the total horizontal stress (Sh) causing unrealistic fracture containment. It will also overestimate the effective horizontal stress (Sh' = Sh - Biot * Pore Pressure) for open-hole wellbore failure. High effective horizontal stress assumption can potentially transform rock from brittle to ductile behavior and failure mechanics from shear to compaction and the model becomes overly conservative. Ductile and compaction failure can cause changes in well integrity, as well as changes in fracture geometry from offset infill wells. This paper will document changes in rock properties in the Bakken formation during variable depletion (10% to 65%) and recalculate rock properties (velocities, mechanical properties - Young's modulus, Poisson's ratio, and Biot's anisotropic compressibility constant) as a function of effective stress due to production in order to accurately calculate fracture geometry at an offset well and parent well bore integrity. Hydraulic fracturing simulations are performed to simulate well communication between the fractured well and the depleted parent well along with the potential to re-fracture the parent well using the pore pressure, linear, and non-linear models. Laboratory testing performed on rock samples is shown to validate the non-linear model.

Novel apparatuses have been developed to measure permeability using steady- and unsteady- state methods on nano-Darcy (nD) shale (source rock) using intact cylindrical samples returned to isostatic effective reservoir stress. The steady-state method uses a high pressure dual pump system using supercritical fluids. High pressure supercritical fluids have low viscosity and low compressibility. The effect of low viscosity fluid results in measureable flow rates and the effect of low compressibility fluid minimize unsteady-state transients thereby reducing the amount of time required to achieve steady-state equilibrium. Specially designed and configured pump systems, seals and sleeves reduce leak rates to allow Darcy flow and permeability determination below 1 nD. The unsteady-state method is based upon standard designs but is optimized for small pore volume. In this report we present a summary of over 200 such permeability measurements. Permeability is observed to be dependent on geologic parameters, such as, texture and composition. Stress dependence, with hysteresis, is observed for samples with and without fractures as is rate dependent skin (Forchheimer). An interpretation model where matrix storage feeds a progressively larger fracture network provides a logical basis for a dual-porosity reservoir simulation model. This dual-porosity model is used to understand the influence of reservoir production parameters, such as choke management. An additional observed effect is possibly related to pore collapse and disconnection. Pores associated with organic matter are softer than the surrounding mineral matrix. If these pores have a sufficiently small throat diameter, it is not hard to envision that they easily compact and close under increased effective stress as the result of reservoir depletion. Therefore, organic pore systems can become isolated unlike those of a sponge where fluids remain in pressure communication at all times. The implication of such pore isolation phenomena is that fluid material balance is not preserved during production and can contribute to large production decline rates.

In mid-2000, the North American energy renaissance began to take shape with a boom in unconventional oil and gas production. Within a decade, the combination of horizontal drilling, completion tools and hydraulic fracturing innovations unlocked a vast resource that was previously considered uneconomic. With a large focus of North American operations been around efficiency, a manufacturing model approach was deployed with significant capital efficiencies that further accelerated the learning curve. As these basins now mature and enter the infill development period, long term production results from these unconventional plays are starting to present valuable information in understanding the late time production performance and in-fill well performance (water cuts, production rates and changes due to interference).This paper presents results from the analysis of well performance by evaluating infill wells, in-fill lease-line wells and relating these interactions to the completion types and job types deployed. The order of the in-fill operations (East-West, Zipper, etc.) on performance is evaluated together with models to demonstrate the impact of fracturing operations and production operations on fracture asymmetry. Fracture models and production models, together with interference data, are utilized to enhance the understanding of the interactions and support hypothesis that demonstrate the importance of understanding operational timing.