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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
World Oil | Year: 2011

A data-driven approach identifies net-pay cutoffs takes account of rock type and reservoir depletion mechanisms and honors scale of measurement. The outcome includes more exact petrophysical interpretations of hydrocarbon-bearing intervals and more meaningful reservoir models. Net pay is a thickness with units of length, and it can only be measured at a well. Studies have shown that if net pay is systematically quantified, the performance of dynamic reservoir models is demonstrably improved in terms of more readily attainable history matches. If Dean-Stark extracted water saturations are available, it is possible to groundtruth the use of composite cutoff parameters such as bulk volume water, the product of porosity and water saturation. Volumetrics are addressed by grid cell and then aggregated for each reservoir unit.


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
SPE Economics and Management | Year: 2011

The unitization of oil and gas fields that straddle license or international boundaries traditionally has been effected with the aim of maximizing return on investment for all unit owners. The rationale is that the costs of unitization and any subsequent redeterminations of equity will be subordinate to the enhanced production and thence revenue that unitization might bring compared to a partitioned development. This outcome is more likely to be achieved in the traditional case of a sizable field with laterally consistent, discernible reservoir properties and fairly uniform hydrocarbon that is unitized before production startup with a perception of predictable commodity prices. This rationale is impacted by departures from the classical situation. These departures include field marginality, market volatility, reservoir complexity, hidden pay, the presence of multiphase hydrocarbons, cross-license trends in reservoir-rock or substance properties, and post-production unitization. Each of the major departures is analyzed from the standpoint of the challenges it presents to a value-adding unitization exercise. Part of this analysis calls for a consideration of alternatives to unitization where another avenue might prove more beneficial to the owners of straddled licenses. This evaluation is undertaken by reference to case histories, through which procedural recommendations are formulated for future guidance. Notwithstanding this collation of options, it is of paramount importance that each case be examined thoroughly so that the optimum development strategy can be identified for any straddling petroleum accumulation. Copyright © 2011 Society of Petroleum Engineers.


Bust V.K.,Gaffney, Cline and Associates | Oletu J.U.,Gaffney, Cline and Associates | Worthington P.F.,Gaffney, Cline and Associates
SPE Reservoir Evaluation and Engineering | Year: 2011

An examination of the core and log analysis of carbonate reservoirs has confirmed that identified shortcomings are rooted in disparate pore character. Many of the interpretation methods were developed for clastic rocks, which typically show an intergranular porosity, sometimes augmented by fracture porosity. In carbonate reservoirs, the primary pore system comprises interparticle porosity that coexists with a highly variable secondary system of dissolution voids and/or fractures. As a consequence, carbonate reservoirs are markedly heterogeneous from pore to reservoir scales, and this variability poses significant challenges to data acquisition, petrophysical evaluation, and reservoir description. For example, the ranges of carbonate facies and their pore character often control the distributions of net pay, porosity, and hydrocarbon saturation. Putting these matters together, conventional petrophysical practices that exclusively use reservoir zonation based on lithology/mineralogy have limited application in carbonates. Instead, recourse is made to a zonal discrimination that draws upon the distribution of microporosity and its connectivity with macroporosity and fractures. The discrimination scheme uses downhole technologies such as high-resolution imaging and magnetic resonance logs, supported by advanced core analysis. On this basis, a value-adding workflow is proposed to increase confidence in those petrophysical deliverables that are used in static volumetric estimates of petroleum Resources. © 2011 Society of Petroleum Engineers.


Worthington P.F.,Gaffney, Cline and Associates
Petrophysics | Year: 2011

Contemporary thrusts in petrophysics are identified by considering the technical and commercial forces of the present day and the technology that is needed if the petroleum industry is to respond effectively. The identified response leads to a projection for petrophysical practice in 2020. Fundamental to this projection is an expansion of the concept of a "standard" suite of downhole measurements with supporting core data to one of fit-for-purpose relational datasets for the petrophysical analysis of problematic reservoirs. The major interpretative thrusts include: an all-embracing pore characterization scheme for carbonate reservoirs; identified procedures for the petrophysical evaluation of unconventional gas and oil reservoirs; a targeting of by-passed and hidden pay, especially in larger mature fields; and the evolution of interpretation protocols for horizontal wells. In particular, petrophysics needs to manage better the effects of scale of measurement on data integration for improved reservoir models, the statistically significant sampling of anisotropic and heterogeneous reservoir zones for the reduction of predictive uncertainty, and the identification of net reservoir and net pay intervals for more effective initialization of reservoir simulators. These projections are set within a twofold strategy. First, a scenario approach allows the challenges posed by a given type of problematic reservoir to be sorted into their different forms. Second, the key-well concept leads to the identification of the prevailing form(s) in the reservoir under investigation. This process defines the requisite data acquisition. These thrusts form part of an overall industry drive towards sharper subsurface imaging, overcoming difficult drilling conditions, directing wells to identified targets, and understanding better how complex reservoirs work. Through these initiatives, petrophysics will continue to grow significantly at the interfaces with geology, geophysics, geomechanics, 3D reservoir modeling and reservoir engineering, and thereby strengthen its pivotal role in integrated reservoir studies. © 2011 Society of Petrophysicists and Well Log Analysts.


Wilson S.,Gaffney, Cline and Associates
Society of Petroleum Engineers - SPE Europec Featured at 78th EAGE Conference and Exhibition | Year: 2016

At any stage of the Exploration and Production cycle decisions must be made with limited information. This situation can always be improved by investing more money or time in improving the quality and variety of information available. However, this in itself presents a decision as to whether the investment to get new information such as a new seismic survey is worth it. This paper outlines a practical and structured method to estimate the value of new information in monetary terms, which can be used to make an informed business decision on whether the new information is worth it. The method is comprised of two primary elements. Firstly the problem is defined using a decision tree analysis approach that considers what decisions are to be made and their possible outcomes. Secondly, a collaborative workshop is used to estimate the probabilities required to populate the decision tree. This then enables the Expected Monetary Value to be calculated both with and without the technology that acquires the new information. The difference between the two is approximated as the value of the information. This paper uses a case study approach to explain this method that considers an operators dilemma in deciding whether or not to drill an appraisal well. Obtaining a meaningful result from this process requires time and commitment from management and technical staff. However, at stake are the considerable sums of money in acquiring the new information and the subsequent investment decisions that draw on the new information. The method described as a minimum provides fiscal information to make investment decisions and at best, provides a framework in which the benefits and risks of investing in new technology can be fully understood. There has already been much published on the use of decision trees to estimate the value of information. However, in practice it can be difficult to estimate the probabilities required for a decision tree analysis to work as they are not intuitive to describing the situation. This approach simplifies this by arranging the mathematics to make the task of the workshops clearer and more achievable. The result is a practical method that can be easily understood and implemented. Copyright 2016, Society of Petroleum Engineers.


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.


Worthington P.F.,Gaffney, Cline and Associates
Journal of Petroleum Science and Engineering | Year: 2011

The petrophysical evaluation of clastic freshwater-bearing hydrocarbon reservoirs cannot be approached using the standard composite Archie equation because these reservoirs show departures from the assumptions that underpin its application. The problem is placed on a sounder technical footing by defining the preconditions for the application of non-Archie saturation models and showing where and how these are satisfied. This exercise assumes that porosity has been evaluated at an earlier stage of the petrophysical workflow. It reveals that there is no fixed salinity level below which reservoirs show freshwater character in an electrical sense: the level is reservoir-specific. Where the non-Archie models do break down, a conditioned pseudo-Archie approach is proposed. This approach demonstrably enhances the estimation of hydrocarbon saturation, typically by up to 20 saturation units, as evidenced through groundtruthing core measurements and comparisons with other log deliverables. These comparisons can, of course, impart additional quality assurance. The approach is illustrated using field examples. On this basis, a protocol is outlined for the optimum acquisition of petrophysical data in clastic freshwater-bearing hydrocarbon reservoirs. Central to this protocol are charts for identifying the most appropriate values of the porosity and saturation exponents. The adoption of this protocol leads to a significant reduction of uncertainty in the volumetric evaluation of these challenging hydrocarbon accumulations. © 2011 Elsevier B.V.

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