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.
Two places that illustrate the mounting challenges facing the shale business are the Bakken Shale in North Dakota, where the number of working rigs is one-third what it was a year ago, and the Fayetteville Shale in Arkansas, where there are no more working rigs. An analysis of thousands of fracturing treatments in major plays in the United States provides insights into how fracture designs have changed over time.
The Bakken and Niobrara operator will eliminate 254 jobs in an effort “to better align [its] business with the current operating environment.” Oilfield flares are a bright indicator of rapidly rising oil production that exceeds pipeline capacity. And it raises the question: Why are oil companies in such a hurry? How Close Is Too Close? The ideal well spacing is in the eye of the beholder.
Researchers from the Federal Reserve Bank of Dallas quantified the economic impact of the US shale revolution for the first half of this decade. Times are still financially tough for many shale operators: Sanchez Energy and Halcón Resources become the latest to file for Chapter 11 protection. Share prices have plunged for seemingly every major US shale producer, with Concho, Pioneer, and Continental among those receiving the worst of the market’s fury. Have investors completely lost faith in the industry? And are shale executives any more optimistic?
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.
The Devonian-Mississippian STACK/SCOOP Play of the Oklahoma Anadarko Basin is a complex assemblage of tight carbonate and siliciclastic strata and an important oil and gas province. In the last decade, prolific drilling has demonstrated significant heterogeneity in the composition of oils produced from STACK/SCOOP reservoirs. This study discusses possible geoscientific explanations for the heterogeneity observed in produced oils and describes how source, maturation, and migration affect their composition.
Geochemical data from 136 produced oils across 12 counties from 4 producing reservoirs is reviewed. Calculated thermal maturity (Rc%) from alkylated polyaromatic compounds shows excellent agreement with oil thermal maturity increasing with increased depth. Oils produced from overpressured reservoirs exhibit a strong relationship between Rc% and Gas-Oil Ratio (GOR), while normal- to underpressured reservoirs exhibit GORs up to an order of magnitude higher at similar Rc%. Light hydrocarbons show that paraffinicity varies starkly with producing reservoir, suggesting compositional fractionation from diffusive migration through tight and argillaceous strata. Conversely, aromaticity varies geographically by Play Region, indicative of changing depositional environments and organic input across the basin. Isoprenoid and sesquiterpane biomarkers indicate all oils are generated by Type II or Type II/III mixed organic matter, but Springer Group reservoirs are charged by a highly argillaceous, non-Woodford source.
The Anadarko Basin is the deepest sedimentary basin in the cratonic interior of the North America with as much as 40,000 feet of Paleozoic sediments (Johnson, 1989). The Anadarko is an asymmetric basin with the deepest sediments bound against the Amarillo-Wichita Uplift to the southwest. The basin is elongated along its west-northwest axis and bound by the Nemaha Ridge to the east and the Anadarko shelf to the west and north.
In the last decade, drilling of Devonian-Mississippian strata along the margins of the basin have delineated one the continent's most successful petroleum resource plays. These areas are colloquially referred to as the