Worthington P.F.,Gaffney, Cline and Associates
Journal of Applied Geophysics | Year: 2010
Reservoirs that contain dispersed clay minerals traditionally have been evaluated petrophysically using either the effective or the total porosity system. The major weakness of the former is its reliance on "shale" volume fraction (Vsh) as a clay-mineral indicator in the determination of effective porosity from well logs. Downhole clay-mineral indicators have usually delivered overestimates of fractional clay-mineral volume (Vcm) because they use as a reference nearby shale beds that are often assumed to comprise clay minerals exclusively, whereas those beds also include quartzitic silts and other detritus. For this reason, effective porosity is often underestimated significantly, and this shortfall transmits to computed hydrocarbons in place and thence to estimates of ultimate recovery.The problem is overcome here by using, as proxy groundtruths, core porosities that have been upscaled to match the spatial resolutions of porosity logs. Matrix and fluid properties are established over clean intervals in the usual way. Log-derived values of Vsh are tuned so that, on average, the resulting log-derived porosities match the corresponding core porosities over an evaluation interval. In this way, Vsh is rendered fit for purpose as an indicator of clay-mineral content Vcm for purposes of evaluating effective porosity. The method is conditioned to deliver a value of effective porosity that shows overall agreement with core porosity to within the limits of uncertainty of the laboratory measurements. This is achieved through function-, reservoir- and tool-specific Vsh reduction factors that can be applied to downhole estimates of clay-mineral content over uncored intervals of similar reservoir character. As expected, the reduction factors can also vary for different measurement conditions. The reduction factors lie in the range of 0.29-0.80, which means that in its raw form, log-derived Vsh can overestimate the clay-mineral content by more than a factor of three. This exposition constitutes a major product of this paper.The implementation of the reduction factors demonstrably improves the evaluation of effective porosity from density, density-neutron and sonic logs, an exercise that also becomes more consistent across different tool types, with substantial reductions in uncertainty. This outcome brings petrophysics much closer to a verifiable equivalence of the effective and total porosity systems for enhanced quality assurance and thence a greater confidence in petrophysically-sourced reserves estimates. © 2010 Elsevier B.V.
Worthington P.F.,Gaffney, Cline and Associates
SPE Reservoir Evaluation and Engineering | Year: 2010
A knowledge of net pay is important for the volumetric estimation of hydrocarbon resources, a practice that underpins the value of the petroleum industry. Yet, there is no universal definition of net pay, there is no general acceptance of its role in integrated reservoir studies, there is no recognized method for evaluating it, and there are disparate views on how to make use of it. Partly for these reasons, net-to-gross pay constitutes a major source of uncertainty in volumetric reserves estimates, second only to gross rock volume. With the aim of improving this unsatisfactory state of affairs, I chart a critical path of net-pay understanding and application to dispel some of the unhelpful myths that abound within the industry and replace them with a defensible rationale to guide the quantification of net pay (thickness). Central to this process is the identification of net-pay cutoffs, themselves the subject of much controversy over the years. The approach is data-driven, in that it uses what we know, and also fit-for-purpose, in that it takes account of reservoir conditions. The outcome is a sounder basis for incorporating net pay into volumetric estimates of ultimate recovery and thence hydrocarbon resources. Copyright © 2010 Society of Petroleum Engineers.
Worthington P.F.,Gaffney, Cline and Associates
Petroleum Geoscience | Year: 2010
Gas hydrates are recognized as a massive source of fossil fuel that could be far in excess of conventional hydrocarbon resources. The evaluation of formations that contain gas hydrates is therefore receiving renewed emphasis through contemporary petrophysical technology. A key factor is the use of logging-while-drilling (LWD) to sense hydrate-bearing intervals before drilling-induced thermal invasion and thence hydrate dissociation take hold. Recent advances in LWD technology have brought most of the potentially diagnostic tools onto the drill string, so there is little disadvantage in not having a wireline database. Moreover, modern tools have a sharper spatial resolution and a greater capability for differential depths of investigation. Petrophysical models have to be capable of distinguishing hydrates from ice in permafrost regions: this complication does not exist in the subsea environment. In general, pristine hydrates are characterized by high resistivity, low sonic transit time, and low density, possibly in conjunction with gas shows from mud logs. High neutron porosity can also be diagnostic away from permafrost. Other tools with a role to play include dielectric logs, for distinguishing ice from methane hydrate; electrical imagers, for identifying laminated hydrate formations; and magnetic resonance logs, for contributing to estimates of hydrate volume by difference, because of hydrate invisibility to these tools. The mode of hydrate formation is especially important, because a hydrate-supported structure will not produce as well as a framework-supported structure due to pore collapse with dissociation. A proposed workflow for the petrophysical evaluation of gas hydrates is guided by field examples. This is set against the backdrop of a hydrate categorization scheme, which brings together the type mode of hydrate formation at the pore scale, the type class of hydrate occurrence at the reservoir zonal scale, and the resolvability of mesoscale hydrate-bearing layers by contemporary logging tools. Although the formation evaluation of gas hydrates remains largely semi-quantitative, current interests are driving towards data-driven interpretation protocols that target estimates of producibility. Indicators are provided as to how this objective might be best approached. © 2010 EAGE/Geological Society of London.
Berry J.,Gaffney, Cline and Associates
Offshore Engineer | Year: 2014
Since 2014, eight of the top 10 discoveries have been offshore and have been transformational in opening completely new plays. By far the most significant discovery since 2004 is the Galkynysh gas field onshore Turkmenistan. What is interesting to note is their wide geographic distribution and that they comprise new plays in both already proven basins and in new petroleum provinces. Seven are located in deepwater, one on the shelf and two on land. Huge gas discoveries in the Rovuma Basin offshore Mozambique take fourth and seventh places in the rankings and are a new play and basin opener. Operated by Anadarko and Eni drilling activities have achieved phenomenal success with up to 150 Tcf already discovered. Commercialization is principally dependent on liquefaction and export, although many additional gas utilization options are also being considered. Very significant discoveries in the Ultra-high pressure and high temperature (HPHT) of Gulf of Mexico and a normally pressured giant find in Norway (Johan Sverdrup) have confirmed new plays in established basins.
Worthington P.F.,Gaffney, Cline and Associates |
Worthington P.F.,University of London
SPE Economics and Management | Year: 2011
Equity redetermination is most commonly encountered where a straddling field is developed as a discrete entity through a process of unitization. It is enacted through evaluation procedures that prescribe the technical methodology for requantifying different license shares, or tract participations, in a field unit as more data become available. The formulation of these procedures usually takes place at unitization, it is based on appraisal data, and, therefore, it is guided by simplified perceptions of reservoir character. For this reason, many such technical procedures have been found to be lacking when they are applied later at the equity redetermination stage. These shortcomings can take the form of ambiguous wording, misleading definitions, technically inappropriate specifications, contradictory prescription, or simply a lack of sufficient detail to render the intended process meaningful. They have impeded the determination of revised tract participations by triggering interlicense disagreements that might otherwise have been avoided. With the objective of reducing this unhelpful impact, experience of redetermination situations is used to illustrate the nature and consequences of poorly constructed procedures for the recomputation of tract participations. The analysis is then flipped to generate a framework of key elements of technical procedures together with indications of how they are best implemented. These matters form the basis for a high-level set of protocols for a more efficient and effective redetermination of equity that would avoid the previously encountered shortcomings. The protocols encompass the proper incorporation of data character, a sound technical basis for redetermination, a balance between under- and over-prescription, an auditable deterministic ethos, and adherence to good international petroleum practice. They constitute recommendations for a better approach to the compilation of fit-for-purpose evaluation procedures within those unitization agreements that make provision for a future redetermination of equity. The recommendations are equally applicable to domestic and international unitizations. The principal benefit lies in an enhanced efficiency of the equity-redetermination process, which feeds through to a greater collective asset value. Copyright © 2011 Society of Petroleum Engineers.