Park Royd P and P England Ltd

Ascot, United Kingdom

Park Royd P and P England Ltd

Ascot, United Kingdom
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Worthington P.F.,Park Royd P and P England Ltd | Worthington P.F.,Imperial College London
Journal of World Energy Law and Business | Year: 2016

Oil and gas fields that straddle a domestic licence boundary or a delimited international border are often unitized so that they can be developed efficiently and effectively as a single entity. The unitization process is usually governed by a pre-unit agreement and a unitization and unit operating agreement. Provision for expert determination in these agreements should include a decision on the basis for tract participation, the determination of initial tract participation around the time of unitization, the formulation of key elements of prescribed technical procedures for any redetermination of tract participation, the redetermination of tract participation post-production, and the enlargement or reduction of the unit area and/or unit interval. The agreements must also define the key issues of how an appointed expert is to arrive at a decision. Expert determination is generally preferred to pendulum decision-making, an expert should carry out an integrated study with a single deliverable as opposed to one that is subdivided into discrete incremental steps, and the expert should table an initial decision for technical and procedural scrutiny by the parties before delivering a final binding decision. Experience has shown that adherence to these principles of prescription facilitates expert engagement during subsequent field life and thereby promotes Pareto-efficiency, fairness and equitability. © The Authors 2016. Published by Oxford University Press on behalf of the AIPN. All rights reserved.

Worthington P.F.,Park Royd P and P England Ltd
First Break | Year: 2014

Several different methods have been evaluated for calculating tract participation in diverse reservoir situations where a unitized field straddles a domestic or international licence boundary. There are three key elements. The first concerns the choice of a static or dynamic basis for tract participation or a hybrid method that falls somewhere between the two. The second involves the introduction of any conversion or weighting factors that are designed to take account of systematic differences in hydrocarbon type or reservoir quality across the field. The third relates to adopted practices for the volumetric calculations, specifically the equity-sensitive areas of scale considerations, fluid levels, net-to-gross ratio, and reservoir mang. These key elements are analysed from the standpoint of securing a fair and equitable (re)determination of tract participation. Recommendations for a more technically substantive aoach reinforce the pareto-efficiency of unitization, so that the cost of the exercise to each partner is a good deal smaller than the greater revenue that can be secured by that partner through the integrated development of a straddling field. However, every unitization and redetermination situation is different, and each case should be considered on its merits if maximum benefits are to be attained. © 2014 EAGE

Bust V.K.,Gaffney, Cline and Associates | Bust V.K.,Royal Dutch Shell | Worthington P.F.,Gaffney, Cline and Associates | Worthington P.F.,Park Royd P and P England Ltd
SPE Reservoir Evaluation and Engineering | Year: 2014

The emergence in geoscience of 3D geocellular modeling has raised questions about the correspondence of hydrocarbon volumetric deliverables with those derived from 2D zonal modeling. These differences of approach are compounded because the contemporary 3D methods use net-reservoir volumetric algorithms whereas the more established 2D methods have traditionally used net-pay volumetric algorithms. Both methods are initialized using 1D "alongwellbore" datasets. Key parameters for comparison are initial hydrocarbon pore volume (IHPV) for 2D and 3D modeling and equivalent hydrocarbon column (EHC) for 1D along-wellbore modeling. The focus is twofold. The first objective has been to generate a functional petrophysical model as a basis for volumetric comparisons. The reservoir notionally comprises an oil accumulation within a water-wet, lithologically-clean sandstone that is partially saturated with high-salinity brine. The sandstone comprises five rock types (RTs), each of which has a defined set of interpretive algorithms. The second objective has been to compare static volumetric estimates of EHC and/or IHPV for a range of case models. This objective was approached using three workflows. Initially, 1D along-wellbore screening studies used different case models representing various stratigraphic sequences. These allowed a preliminary assessment of results arising from the use of net-reservoir and net-pay volumetric algorithms without the influence of mapping practices. The findings were corroborated by field studies. Second, 2D zonal modeling led to values of IHPV based on both net-reservoir and net-pay algorithmic protocols. Third, 3D geocellular modeling also led to values of IHPV based on both protocols. These data allowed equitable comparisons of 2D zonal deliverables with those from 3D geocellular models because a consistent inter-well interpolation methodology was used for all 2D and 3D cases. The analysis incorporated the influence of stratigraphic sequences of the five RTs with their different petrophysical characteristics. Comparisons of 2D and 3D models showed that IHPV values delivered by established 2D zonal models with net-pay algorithmic protocols are mostly lower than those values delivered by contemporary 3D geocellular models with net-reservoir protocols by approximately 4% on average, but the differences are highly variable. These outcomes, which have implications for reserves estimation, are strongly governed by the stratigraphic distribution of the RTs. They re-emphasize that each case must be investigated separately and thoroughly. Copyright © 2014 Society of Petroleum Engineers.

Worthington P.F.,Park Royd P and P England Ltd | Majid A.A.,Gaffney, Cline and Associates
Journal of Petroleum Science and Engineering | Year: 2014

The role of net pay in unconventional reservoirs continues to evolve as a design criterion for reservoir stimulation and well completions. Unlike conventional reservoirs, shale-gas development is not yet at the stage where longstanding net-pay protocols have been tried and tested. Therefore, any protocol has to be regarded as being at a pilot stage, especially in view of the pronounced complexity of shale-gas systems. This state of affairs is progressed by adopting a set of net-pay criteria and transposing this into a generic petrophysical workflow that interfaces with other key disciplines such as geochemistry and geomechanics. Essential parameters are total organic carbon (in the setting of thermal maturity), fracturability (based on quartz/calcite/dolomite volume fraction and thence brittleness), natural fracture density, effective gas permeability, and total porosity as an input to gas in place. The deliverables in the form of target net-pay intervals are based on functional cut-offs for each given reservoir system and for different appraisal fronts within the same reservoir system. This is important because different methods of reservoir zonation can result in very different zonal characteristics and associated parametric relationships. The estimation of uncertainty in cut-off specifications and its impact on the resulting net-pay intervals have been approached with reference to a commensurate suite of characterizing well logs groundtruthed by core analysis in at least one key well. These considerations lead to specific ranges of cut-offs for immediate application. Thus, the identification of net pay and thence candidate intervals for completion is placed on a quantitative footing. This is an important contribution to development planning in these highly complex unconventional systems. © 2014 Elsevier B.V.

Worthington P.F.,Gaffney, Cline and Associates | Worthington P.F.,Park Royd P and P England Ltd | Hattingh S.K.F.,ERC Equipoise
Petroleum Geoscience | Year: 2014

The initialization of a reservoir simulator calls for the populating of a three-dimensional dynamic grid-cell model using subsurface data and interrelational algorithms that have been synthesized to be fit for purpose. These prerequisites are rarely fully satisfied in practice. This paper sets out to strengthen initialization through four key thrusts, all of which seek to optimize the bridgehead between reservoir geoscience and reservoir engineering, and thereby maximize value from reservoir simulation. The first addresses representative data acquisition, which includes the key-well concept as a framework for the cost-effective incorporation of free-fluid porosity and permeability within an initialization database. The second concerns the preparation of these data and their products for populating the static and dynamic models. Important elements are dynamically conditioned net-reservoir cut-offs, recognition of primary flow units, and establishing interpretative algorithms at the simulator grid-cell scale for application over net-reservoir zones. The third thrust is directed at the internal consistency of capillary character, relative permeability properties and petrophysically-derived hydrocarbon saturations over net reservoir. This exercise is central to the simulation function and it is an integral component of hydraulic data partitioning. The fourth concerns the handling of formation heterogeneity and anisotropy, especially from the standpoint of directional parametric averaging and interpretative algorithms. These matters have been synthesized into a workflow for optimizing the initialization of reservoir simulators. In so doing, a further important consideration is the selection of the appropriate procedures that are available within and specific to different software packages. It is the authors' experience that implementation of these thrusts has demonstrably enhanced the authentication of reservoir simulators through more readily attainable history matches with less required tuning. This outcome is attributed to a more systematic initialization process with a lower risk of artefacts. Of course, these benefits feed through to more assured estimates of ultimate recovery and, thence, hydrocarbon reserves. © 2014 EAGE/The Geological Society of London.

Worthington P.F.,Park Royd P and P England Ltd
SPE Economics and Management | Year: 2015

Over the past two decades, pendulum arbitration has been increasingly incorporated into dispute-resolution procedures for the redetermination of tract participation (equity) for unitized oil and gas fields that straddle domestic license boundaries or international borders. In such cases, the pendulum has been prescribed for use in expert redetermination, ideally so that an expert determines tract participation and then selects the closer submissionmade by one of the parties. The tract participation of the selected submission then constitutes the expert's final decision. The process can function reasonably well in the originally envisaged situations (e.g., two opposing cases each originating from one of two straddled license areas). It is much more difficult to apply in the more-complex situations to which it has been extrapolated subsequently. These include multiphase reservoirs with separately unitized fluids, several straddled license areas, and the use of the same subsurface model for both field-development and equityredetermination purposes. An analysis of such situations has allowed the further identification of those circumstances for which the pendulum can be applied meaningfully in expert redetermination and those for which it should not be adopted. These additional expectations include a meaningful basis for tract participation in terms of one (equivalent) unit substance, fully prescribed technical procedures leading to a compliant reservoir model, and a single (as opposed to a staged) expert redetermination that post-dates the parties' submissions but allows for rebuttal in the event ofmanifest error. Case histories illustrate the difficulties that can arise where these principles are infringed. They also reaffirm the overarching message that each straddling field situation differs from others and therefore every redetermination of tract participation must be assessed separately and thoroughly. Copyright © 2015 Society of Petroleum Engineers.

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