A flow simulation-driven time-lapse seismic feasibility study is performed for the Amberjack field that leverages existing multi-vintage 4D time-lapse seismic data. The focus is a field consisting of stacked shelf and deepwater reservoir sands situated in the Gulf of Mexico in Mississippi Canyon Block 109 in 1,030 ft of water. The solution leverages seismic interpretation, seismic inversion, earth modeling, and reservoir simulation [including embedded petro-elastic modeling (PEM) capabilities] to enable the reconciliation of data across multiple seismic vintages and forecast the optimal future seismic survey acquisition in a closed-loop. The overarching feasibility solution is integrated and simulation-driven involving multi-vintage seismic inversion, spatially constraining the petrophysical property model by seismic inversion, and performing reservoir simulation with the embedded PEM. The PEM is used to compute P-impedance and Vp/Vs dynamically, which enables tuning to both historical production and multi-vintage seismic data. The process considers a hybrid fine-scale 3D geocellular model in which the only upscaling of petrophysical properties occurs when the P-impedance from seismic inversion is blocked to the 3D geocellular grid. This process minimizes resampling errors and promotes direct tuning of the simulator response with registered seismic that has been blocked to a geocellular earth model grid. The results illustrate a three-part simulation-to-seismic calibration procedure that culminates with a prediction step which leads to a simulation-proposed time-lapse seismic acquisition timeline that is consistent with the calibrated reservoir simulation model. The first calibration tunes the model to historical production profiles. The second calibration reconciles the dynamic P-impedance estimate of the simulated shallow reservoir with that of the seismic inversion blocked to the 3D geocellular grid. The combination of these two steps outline a seismic-driven history matching process whereby the simulation model is not only consistent with production data but also the subsurface geologic and fluid saturation description. Large and short wavelength disparities in the P-impedance calibration existing between the simulator response and the time-lapse seismic data are attributed to resampling errors as a result of seismic inversion-derived P-impedance being blocked to the 3D geocelluar grid, as well as sparse well control in the earth model which leads to the obscuring of some asset-specific characteristics. The results of the third calibration step show how the time-lapse seismic feasibility solution accurately confirms prior seismic surveys undertaken in the asset. Given this confirmation, the solution achieves a suitable prediction of seismic-derived rock property response from the reservoir simulator as well as the optimal future time-lapse seismic acquisition time.
A useful first step in the characterization of any new coal area is to compare its characteristics with those of successful CBM projects. Table 2 summarizes the characteristics of several successful projects in the US and includes parameters related to reservoir properties, gas production, gas resources, and economics. The table shows that successful projects have many similarities, including high permeabilities and high gas resource concentration; however, the table does not include aspects such as government incentives or high-value markets, which could elevate a marginal project to commercial status.
The process of drilling and completing coalbed methane (CBM) wells is similar to wells in conventional reservoirs. Coring, however, can pose special challenges. The first step in creating a drilling program for a CBM well involves gathering information about existing wells in a given area. After these data are gathered and analyzed, a preliminary drilling and completion prognosis can be drafted with the input of field operations personnel. An important aspect in drilling frontier or appraisal wells is to keep the drilling procedures relatively simple.
Han, Heyleem (University of Oklahoma) | Dang, Son (University of Oklahoma) | Acosta, Juan C. (University of Oklahoma) | Fu, Jing (University of Oklahoma) | Sondergeld, Carl (University of Oklahoma) | Rai, Chandra (University of Oklahoma)
Developing tight shale formations, presents additional challenges due to their vertical and horizontal heterogeneities. Many real-time field decisions, such as lateral placement, are made with the understanding of sequence stratigraphy and a well's petrophysical profile. Handheld X-Ray fluorescence (XRF) has been commonly used as a rapid scanning tool for elemental analysis. Complementary to XRF, handheld Laser Induced Breakdown Spectroscopy (LIBS) has recently been developed, and quickly recognized as a useful tool. It captures the light elements, which XRF cannot, such as sodium, magnesium and more importantly carbon (both organic and inorganic), which are essential elements in understanding rich organic sedimentary rocks. LIBS spectra generally have lower emission signal intensities for dark organic rich samples; therefore, it is important to select optimal integration-delay times to capture better signal intensities for all emission lines ranging from the ultraviolet (180-400nm), through visible light (400-780nm) to infrared (780-960nm). Using a partial least square regression (PLS) and signal normalization, an inversion method was developed for rock slab characterization. The trained dataset includes 150 samples from different tight shale formations, such as Meramec, Woodford, Eagle Ford, Barnett, Bakken, Vaca Muerta and Wolfcamp. The inversion provides quantitative elemental concentrations with reasonable uncertainty. The results were validated with another group of 70 samples from different shale plays. XRF was obtained for the same samples and results showed a good correlation between LIBS and XRF for major elements (Al, Fe, Si, Mg, Si, Ca, K). Total carbon measured through LECO® without acidizing was used to verify LIBS total carbon readings. Mineralogy was inverted from the XRF elemental abundances.; this provided carbonate mineral concentration, which was used to calculate inorganic carbon. Total organic carbon (TOC) was later estimated as the difference between total carbon and inorganic carbon. In this study, we demonstrated the complete elemental analysis on 370-ft of core sampled at a 2-inch depth resolution using XRF and 0.5ft depth resolution using LIBS. Trace elements were used to understand formation chemostratigraphy, while major elements were used to invert for mineralogy, TOC, and to compute a brittleness index profile.
Swami, Vivek (CGG) | Tavares, Julio (CGG) | Pandey, Vishnu (CGG) | Nekrasova, Tatyana (CGG) | Cook, Dan (Bravo Natural Resources) | Moncayo, Jose (Bravo Natural Resources) | Yale, David (Yale Geomechanics Consulting)
In this study, a state-of-the-art seismic driven 3D geological model was built and calibrated to a petrophysical and geomechanical analysis, 1D-MEM (Mechanical Earth Model), on chosen wells within the Arkoma Basin of Oklahoma. The well information utilized in this study included basic wireline logs and core analysis, including XRD (X-Ray diffraction) data. The traditional petrophysical analysis was augmented with advanced rock physics and statistical techniques to generate the necessary logs. Hydrostatic, overburden and pore pressures were calculated with a petrophysical evaluation model. The 1D-MEMs were based on the Eaton/Olson/Blanton approach with the HTI (Horizontal Transverse Anisotropy) assumption. The 1D-MEMs were calibrated to laboratory data (triaxial tests) and field observations (mud logs, wellbore failure, frac pressures). Therefore, a very good confidence was achieved on Biot's coefficient, tectonic components, anisotropy and dynamic to static conversion factors for Young's Modulus and Poisson's Ratio. Seismic inversions were performed in different time windows and merged to generate high resolution P- and S-Impedance attributes from surface down to the target interval after careful AVO compliant gather preconditioning. A density volume estimate was calibrated to well data, accounting for different geological formations, to decouple P- and S-Wave components as a 3D volume, as well as dynamic Young's modulus (E) and Poisson's ratio (PR). Dynamic E and PR were converted to static parameters using results from 1D-MEMs; and 3D models of Biot's coefficient (α) and tectonic components were built to compute 3D fracture pressure volumes calibrated to well data. The final products were seismic-driven 3D pore pressure and fracture pressure calibrated to 1D-MEMs. The correlation between measured/estimated well logs and corresponding seismic-derived pseudo logs was more than 80%, which indicates good quality of seismic inversion results and hence 3D-MEM. Also, stress barriers, anisotropy, and brittleness indices were calculated on well scale which would help to identify best zones to place hydraulic fractures. The 3D geological model will aid in identifying sweet-spots and optimizing hydraulic fractures.
Frac hits relates to the problem of newly created hydraulic fractures interacting with either primary and/or secondary fractures from offset wells. This fracture-driven interaction (FDI) represents a major concern for shale oil and gas producers given that infill wells experiencing frac hits typically underperform parent wells landed in the same zone. In addition, the sudden pressure communication established through frac hits between multi-fractured horizontal wells (MFHW) can result in damage to parent wells.
In this work, we introduce an analytical model to detect frac hits and assess the fraction of primary fractures connected between the infill and offset well. We assume that frac hits are due to overlapping primary fractures. Frac hits are modeled as a valve between MFHWs that allows certain degree of pressure communication. While the aperture of this valve is controlled by the number of frac hits, the leakage rate is governed by the bottomhole pressure (BHP) differential between wells.
The analytical solution to the fluid-flow model is derived in Laplace domain and is inverted numerically. We found that BHPs are coupled via the degree of interference coefficient δw, defined as the ratio of frac hits to the total number of primary fractures of the infill well. We utilize δw to history-match the analytical model with numerical data. As a result, history-matched δw delivers an estimate of the actual fraction of frac hits ((Equation)).
We study several sensitivity analyses to examine the impact of variation in MFHW properties on the accuracy of the estimation of (Equation) via δw. In general, our model gives an accurate estimation (Equation) for most of the cases evaluated in this work; however, we see that the analytical model may introduce significant error in the estimation of frac hits when SRV and matrix permeability are the same order magnitude. Type-curves for rate-normalized data as well as (Equation) vs δw tables are discussed herein. The computational script used for the analytical calculations in this work proved to be efficient and straightforward to implement.
Diagenesis encompasses many processes after deposition that are responsible for the dynamic evolution of the pore system. Understanding the role of diagenetic events on the connectivity and distribution of pores and migration pathways is vital for proper characterization of the rock. In this study, we critically examine diagenetic signatures in the Woodford Shale focusing on rock-fluid interactions that cause precipitation and dissolution and assess their impact on reservoir quality via multi-physics models.
Evidence of diagenesis in shales have been extensively investigated by some of the authors in active and previous research. In this study, we focused on capturing the distribution of diagenetic features in the Woodford Shale using multiphysics models. Our methodology establishes a multi-disciplinary framework to incorporate multi-scale multi-physics data from various sources to investigate the impact of diagenesis on the alteration of petrophysical properties. Data incorporated include thin sections, scanning electron microscopy, and mineralogy. We first analyze and quantify the diagenetic signatures in the Woodford Shale. Examining the depositional history of the basin, mineralogy, the different pore types and the associated minerals. We then construct representative 3D pore-scale models and employ multi-component coupled fluid-flow and reactive-transport models to critically investigate these processes. Numerically, this entails concurrent solution of fluid-flow equations for pressures and fluxes, changes in fluid and mineral composition and conservation of solute mass for each component in the pore-network. We analyze porosity occlusion and the changes in migration pathways.
This framework allowed us to determine the influence of chemical diagenesis (precipitation and dissolution) processes on the pore structure, connectivity, and fluid flow, in order to quantify the reservoir quality. Our initial pore-scale simulation effort yields promising results and is able to reproduce major diagenetic features. Future research efforts will include incorporating complex reactive kinetics and geomechanical stress-strain modules in the pore scale simulator that will enable us to examine more complex scenarios.
The thermal maturity of organic-rich mudstones is one of the main parameters to evaluate, when appraising a new area in an unconventional shale play project, to decide on the best field development strategy and to define the landing zones. Conventionally, thermal maturity is derived from optical vitrinite reflectance measurements, but this technique has some limitations in marine sediments with lack of terrestrial material. Other techniques, such as Rock-Eval pyrolysis, are destructive and the results can be biased if oil-based mud is used to drill the well. In this contribution, a fast, easy and non-destructive method known as Raman spectroscopy is proposed to estimate the maturity of mudstone samples from the Argentinian Vaca Muerta formation, collected from a wide range of maturities.
Raman spectroscopic measurements were executed on a variety of Vaca Muerta shale samples. A complete maturity depth profile was acquired for one well over the entire Vaca Muerta organic shale sequence. Additionally, samples from eight further wells, presenting a wide range in the expected maturity, were examined with the Raman technique. Using a correlation between the Raman spectroscopic signal and vitrinite reflectance, established earlier based on a set of reference samples, containing organic-rich mudstones from a variety of paleo-marine sedimentary basins in North America, thermal maturities were derived for the Argentinian shale samples. For certain samples kerogen was extracted and properties of the isolated kerogen were measured. The Raman results were not only compared to standard maturity indicators such as vitrinite reflectance or Rock-Eval pyrolysis, but also with other non-standard techniques like DRIFTS (Diffuse Reflectance Infrared Fourier Transform Spectroscopy) or results derived from the kerogen properties.
This case study in the Vaca Muerta shows a good correlation between the maturity values derived from the Raman measurements and maturities inferred from other methods. The depth profile shows a trend of increasing maturity with depth as expected for such a thick unconventional reservoir.
In contrast to other techniques that require isolation of kerogen, polishing of the sample surfaces, or even crushing of the samples in addition to excessive cleaning, the Raman technique utilized here was applied directly on core chips with minimal sample preparation. This non-destructive technique is fast and easy, while the accuracy is comparable to other techniques like infrared spectroscopy, kerogen skeletal density, or optical vitrinite reflectance measurements. The simplicity and accuracy of the Raman technique can provide critical information about vertical and lateral variability of thermal maturity at basin scale in a short period of time, helping to understand the burial history and its relationship with the variability of hydrocarbon properties.