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Integrated Analytical Approach Identifies Wolfcamp Targets Outside Defined Play Area

American Oil & Gas Reporter, September, 2017
Graham Spence | Adriana Perez | Paola Fonseca | Liz Roller | Austin Heape

DALLAS–The great land grab in the Midland Basin has resulted in an exponential increase in acreage prices, with buyers paying up to $60,000 an acre in some cases. In this competitive environment, oil and gas companies–particularly smaller independents–are starting to look for prospective areas away from the main basin activity where land leasing costs can be significantly lower, drilling targets can be shallower, and reservoirs (sourced from migration) have the potential to yield economic volumes of hydrocarbon reserves. To identify and evaluate these types of plays, and to reduce exploration and development risks, it is essential to combine and interpret data within one space to provide a succinct geological evaluation of the subsurface, and ultimately, the potential resource in place. TriGeo Energy sought to conduct an integrated geological evaluation of its Wolfcamp assets in Sterling County, Tx., to identify potential drilling targets in the Eastern Shelf bordering the Midland Basin. TriGeo Energy’s leasehold is outside the current industry-defined economic boundaries of the Wolfcamp play to the west and south. The objective was to better understand if a viable and economic Wolfcamp play could be extended onto the Eastern Shelf environment. Figure 1 highlights defined Midland Basin petroleum plays and TriGeo’s acreage position. It also shows the locations of two 3-D seismic survey volumes over the company’s Sterling County acreage. With the study area on the Eastern Shelf and outside the Wolfcamp play’s defined extent (dashed blue line), it was essential to investigate and define the presence of the main petroleum system play elements–namely source rock quality and potential, reservoir thickness and quality, and ultimately, the presence of contained hydrocarbons.

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Unlocking the tectonic history offshore Southern Gabon with high resolution seismic, gravity and magnetics

First Break, September, 2017
Marianne Parsons | Pedro Martinez Duran | Wolfgang Soyer | Gregor Duval
©2017 EAGE

A recent 3D Broadseis survey was performed in the southern offshore area of Gabon, showing a wealth of detailed information in the seismic data. Understanding how these structures relate to the tectonic evolution of this basin requires the integration of the concurrently acquired gravity and magnetic data. 3D gravity and magnetic models test key geological questions relating to the evolution of this basin, and aid in outlining the nature of the extension and the composition of the crust.

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Improved subsalt images with least-squares reverse time migration

Interpretation (SEG+AAPG), August, 2017
Ping Wang | Shouting Huang | And Ming Wang
©2017 SEG

Complex overburdens often distort reservoir images in terms of structural positioning, stratigraphic resolution, and amplitude fidelity. One prime example of a complex overburden is in the deepwater Gulf of Mexico, where thick and irregular layers of remobilized (i.e., allochthonous) salt are situated above prospective reservoir intervals. The highly variant salt layers create large lateral velocity variations that distort wave propagation and the illumination of deeper reservoir targets. The salt layers also induce large transmission losses that make the subsalt events weak in amplitude, and therefore easily overpowered by strong multiples from shallow multiple generators and other types of noise. In subsalt imaging, tools such as reflection tomography, full-waveform inversion and detailed salt interpretation are needed to derive a high-resolution velocity model that captures the lateral velocity variations. Once a velocity field is obtained, and after the best attempt at multiple suppression, reverse time migration (RTM) can be applied to restore structural positioning of events below and around the salt. However, RTM by nature is unable to fully recover the reflectivity for desired amplitudes and resolution, especially for deeper subsalt reservoir images. This shortcoming is well recognized by the imaging community, and it has propelled the emergence of least-squares RTM (LSRTM) in recent years. In simple terms, LSRTM inverts for the reflectivity that best fits the recorded data through modeling (i.e., demigration) and migration processes. LSRTM can be performed either by an iterative gradient-based local search, or, for better efficiency and applicability, by an approximate single-iteration approach. We investigated how current LSRTM methods perform on subsalt images. First, we compared the formulation of data-domain vs. image-domain least-squares migration (LSM), as well as methods using single-iteration approximation vs. iterative inversion. Next, we examined the resulting subsalt images of several LSRTM methods applied on both synthetic and field data. Among our tests, we found that image-domain single-iteration LSRTM methods, including an extension of Guitton’s (2004) method in the curvelet domain, not only compensated for amplitude loss due to poor illumination caused by complex salt bodies, but also produced subsalt images with fewer migration artifacts in the field data. By contrast, an iterative inversion method showed its potential for broadening the bandwidth in the subsalt, but was less effective in reducing migration artifacts and noise. Based on our understanding, we summarize the current state of LSRTM for subsalt imaging, particularly in terms of single-iteration and iterative LSRTM methods.

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From geology to production: a completion optimization case study from Cleveland Sand, Oklahoma

First Break, July, 2017
Vivek Swami | Graham Spence | Theophile Gentilhomme | Robert Bachman | Mark Letizia | Casey Lipp
©2016 EAGE

This study is based on work performed on horizontal wells in the Cleveland Sandstone Formation. Previous work describes the technique of using automated, quantitative mineralogy (RoqScan) to analyse drill cuttings and derive rock property and elastic pseudo-logs to customize completion designs. We expand on these findings to utilize the estimated elastic rock properties in a proprietary coupled reservoir-geomechanical simulator. The geometry of the individual cluster fractures can then be computed during pumping to investigate different treatment stage designs. The study supports the idea that optimized stage spacing will result in the development of a larger SRV and higher production.

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Accounting for bias and uncertainty in facies estimations from deterministic inversions

Geophysical Society of Houston, June, 2017
John Pendrel | Henk Schouten | Raphael Bornard

Bayesian inference procedures can be used as interpretation tools for seismic inversions. The results are facies and their probabilities of occurrence derived from the native outcomes of inversions or their derivatives. Although deterministic inversions produce a single outcome, they have uncertainties associated with them. Further, due to inappropriate low frequency models or thin bedding, biases in the inversion properties can arise. We use a phenomenological approach to model these effects and separately correct for them in the subsequent Bayesian inference. The results are facies interpretations and pay maps which account for bias and uncertainties and will provide greater confidence in reservoir volume estimates.

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