Uncertainty Quantification for a Hydraulic Fracture Geometry: Application to Woodford Shale Data

Hydraulic fracturing enhances hydrocarbon production from low permeability reservoirs. Laboratory tests and direct field measurements do a decent job of predicting the response of the system but are expensive and not easily accessible, thus increasing the need for robust deterministic and numerical solutions. The reliability of these mathematical models hinges on the uncertainties in the input parameters because uncertainty propagates to the output solution resulting in incorrect interpretations. Here, I build a framework for uncertainty quantification for a 1D fracture geometry using Woodford shale data. The proposed framework uses Monte-Carlo-based statistical methods and is comprised of two parts: sensitivity analysis and the probability density functions. Results reveal the transient nature of the sensitivity analysis, showing that Young’s modulus controls the initial pore pressure, which after 1 hour depends on the hydraulic conductivity. Results also show that the leak-off is most sensitive to permeability and thermal expansion coefficient of the rock and that temperature evolution primarily depends on thermal conductivity and the overall heat capacity. Furthermore, the model shows that Young’s modulus controls the initial fracture width, which after 1 hour of injection depends on the thermal expansion coefficient. Finally, the probability density curve of the transient fracture width displays the range of possible fracture aperture and adequate proppant size. The good agreement between the statistical model and field observations shows that the probability density curve can provide a reliable insight into the optimal proppant size.

Diagenesis of Hunton Group Carbonates (Silurian) West Carney Field, Logan and Lincoln Counties, Oklahoma, U.S.A.

The West Carney Hunton Field (WCHF) is an important oil field in central Oklahoma. Deposited during a series of sea-level rises and falls on a shallow shelf, the Cochrane and Clarita Formations (Hunton Group) have undergone a complex series of diagenetic events. The Hunton section of the WCHF comprises dolomitized crinoidal packstones, brachiopod “reefs” and grainstones, thin intervals of fine-grained crinoidal wackestones, and infrequent mudstones that were diagenetically affected by repeated sea-level change. Widespread karst is evidenced by multiple generations of solution-enlarged fractures, vugs, and breccias, which extend through the entire thickness of the Hunton. Karst development likely occurred during sea-level lowstands. Partial to complete dolomitization of Hunton limestones is interpreted to have occurred as a result of convective circulation of normal seawater during sea-level highstands. Open-space-filling calcite cements postdate dolomitization and predate deposition of the overlying siliciclastic section, which comprises the Misener Sandstone and Woodford Shale. Petrographic evaluation and carbon and oxygen isotope values of the calcite cements suggest precipitation by Silurian seawater and mixed seawater and meteoric water. Carbon and oxygen isotopic signatures of dolomite may have been partially reset by dedolomitization that was concurrent with calcite cementation. Fluid inclusions in late diagenetic celestite crystals observed in the Clarita Formation indicate that the WCHF was invaded by saline basinal fluids and petroleum after burial, during later stages of diagenesis. The timing of late diagenetic fluid flow and petroleum generation likely was during the Ouachita orogeny, which was occurring to the south. There is no evidence that late diagenetic fluids significantly altered the dolomite reservoir that formed earlier. The WCHF provides an ancient example of early diagenetic dolomitization by seawater that remains relatively unaltered by later diagenetic events.

Predicting Lithology-Controlled Stress Variations in the Woodford Shale from Well Log Data via Viscoplastic Relaxation

Summary We report here a study of lithology-controlled stress variations observed in the Woodford shale (WDFD) in north-central Oklahoma. In a previous study, we showed that the magnitude of the minimum horizontal stress Shmin systematically varied with the abundance of clay plus kerogen in three distinct WDFD lithofacies. In this study, we demonstrate that it is possible to quantitatively estimate the observed stress variations using elastic properties determined from well logs as proxies for laboratory-inferred parameters via a relatively simple viscoplastic constitutive relationship. The modeled variations of Shmin along the two horizontal wells that encounter the three lithofacies along their respective well trajectory are in good agreement with measured values obtained from multistage hydraulic fracturing (HF). We believe that the application of the workflow described here in the context of viscoplastic stress relaxation can facilitate the understanding of layer-to-layer stress variations with lithology and thus contribute to improved HF effectiveness.

Numerical Study on the Effects of Imbibition on Gas Production and Shut-In Time Optimization in Woodford Shale Formation

In shale gas formations, imbibition is significant since the tight pore structure causes a strong capillary suction pressure. After hydraulic fracturing, imbibition during the period of shut-in affects the water recovery of flowback. Although there have been many studies investigating imbibition in shale formations, few papers have studied the relationship between gas production and shut-in time under the influence of imbibition. This paper developed a numerical model to investigate the effect of imbibition on gas production to optimize the shut-in time after hydraulic fracturing. This numerical model is a 2-D two-phase (gas and water) imbibition model for simulating an imbibed fluid flow and its effect on permeability, flowback, and water recovery. The experimental and field data from the Woodford shale formation were matched by the model to properly configure and calibrate the model parameters. The experimental data consisted of the relationship between the imbibed fluid volume and permeability change, the relative permeability, and the capillary pressure for the Woodford shale samples. The Woodford field data included the gas production and flowback volume. The modeling results indicate that imbibition can be a beneficial factor for gas production, since it can increase rock permeability. However, the gas production would be reduced when excessive fluid is imbibed by the shale matrix. Therefore, the shut-in time after hydraulic fracturing, when the imbibition happens in shale, could be optimized to maximize the gas production.

RETRACTED ARTICLE: Light hydrocarbon geochemistry: insight into oils/condensates families and inferred source rocks of the Woodford–Mississippian tight oil play in North-Central Oklahoma, USA

The Woodford–Mississippian “Commingled Production” is a prolific unconventional hydrocarbon play in Oklahoma, USA. The tight reservoirs feature variations in produced fluid chemistry usually explained by different possible source rocks. Such chemical variations are regularly obtained from bulk, molecular, and isotopic characteristics. In this study, we present a new geochemical investigation of gasoline range hydrocarbons, biomarkers, and diamondoids in oils from Mississippian carbonate and Woodford Shale. A set of oil/condensate samples were examined using high-performance gas chromatography and mass spectrometry. The result of the condensates from the Anadarko Basin shows a distinct geochemical fingerprint reflected in light hydrocarbon characterized by heptane star diagrams, convinced by biomarker characteristics and diamantane isomeric distributions. Two possible source rocks were identified, the Woodford Shale and Mississippian mudrocks, with a variable degree of mixing. Thermal maturity based on light hydrocarbon parameters indicates that condensates from the Anadarko Basin are of the highest maturity, followed by “Old” Woodford-sourced oils and central Oklahoma tight oils. These geochemical parameters shed light on petroleum migration within Devonian–Mississippian petroleum systems and mitigate geological risk in exploring and developing petroleum reservoirs.