bluuebunny/crossref_metadata_2025 huggingface dataset:
Understanding Reserves Uncertainties in a Mature Field by Reservoir Modelling
Authors: Verbruggen Rini , Pannett Stephen , Stone Greg
Published: December 2007

The Maui C Sands reservoir contains most of the remaining gas-condensate reserves in the mature Maui Field. Technical and commercial management of a hydrocarbon producing field such as Maui relies heavily on the confidence in the forecasted production and reservoir performance and the associated uncertainties. This paper discusses how the key static and dynamic uncertainties can be identified, evaluated, and modelled to determine their impact on remaining reserves and further development options. The approach is based on the use of a combination of representative sector and full field dynamic models to establish the model sensitivities. A few models covering the range of uncertainties are then history matched in an iterative process whereby the uncertainty ranges are updated based on the history match results. Finally, production forecasts are generated for the history matched models to assess the range of reserves and to evaluate and optimise further development options. As a precursor to this, a single base case model is history matched and production forecasted whereby a statistical method is used to select the base case parameters and to assess the associated reserves uncertainty range.
Decision-Making with Incomplete Evidence
Authors: Fletcher Alistair , Davis John P
Published: December 2007

The aim of the paper is to highlight the challenges in making decisions when there is incomplete evidence and information. By understanding the challenges, businesses should be able to make faster, higher quality, decisions. This paper proposes methodologies incorporating probabilistic and other knowledge management techniques to assist in decision making under these conditions. A wide variety of models are generally used to help in the decision making process. With reference to the parameters and structure of a model, four basic types can be identified depending on the degrees of vagueness and completeness.

Type 1 models are deterministic and characteristic of much hard science and engineering. Type 2 models allow for inputs known only as distributions. These models are probabilistic and the basis of probabilistic reserves assessment, probabilistic risk analysis and many economic models. Type 3 models are characterised by vagueness in the overall structure and with input parameters expressible only as ranges and limits. Techniques such as imprecise probabilities (fuzzy logic's and Interval Probability Theory) have recently been developed to handle these models. Type 4 models are characteristic of many complex situations where actions in the future and / or issues of relevance and completeness are central. In other contexts such problems have been referred to as "messy" or "wicked". Many of the problems concerning project evaluations are Type 3 and Type 4, as are most problems that include elements of human judgement, interpretation and choice.

We describe a methodology and mathematics to address Type 3 & 4 problems based on hierarchical process modelling, recording of attributes and a calculus that combines incomplete evidence. We discuss the modelling, philosophy and mathematics that allows explicit incorporation of vagueness and incompleteness. Our approach is illustrated through case studies, including gas to liquid (GTL) investment decisions, prospect evaluation and carbon dioxide sequestration options.
The Griffin Development – Flying High on Infill Success
Authors: Workman L. J. , Slate T. V. , Oke B. F.
Published: December 2007

In recent years the successful drilling, completion and tie-back of three Griffin area infill wells and a re-entry campaign has resulted in improved production rates and increased reserves.

The Griffin Area Development in the southern Carnarvon Basin, offshore Western Australia, consists of three oil fields; Griffin, Chinook and Scindian, tied to the "Griffin Venture" Floating Production Storage and Offloading (FPSO) facility. First production commenced in January 1994, with a maximum rate of 85,000 stb/d reached shortly after start-up.

The Zeepaard Formation is the primary reservoir in the development. It has excellent productivity and strong aquifer support. In eight years of production, over 100 MMstb of oil has been recovered through nine vertical wells. Production began to decline from 1996, with escalating water cuts from the majority of the wells.

Reprocessing of the 1991 3D seismic data, combined with reservoir modelling studies, led to the approval and subsequent drilling of two Zeepaard infill wells in mid 2000, one in the Scindian Field and the other in Griffin. The results of the Griffin infill well changed the understanding of reservoir sweep in that field and led to a re-entry campaign in late 2000. This was followed by a second infill well in early 2002.

Each infill well has flowed in excess of 20,000 stb/d, lifting the production potential of the Griffin Venture, improving the reservoir sweep and accelerating reserves into field life. In February 2002, the facility was producing at 60,000 stb/d, with 40,000 stb/d of this attributable to the three infill wells drilled in the area since July 2000.
The Valuation and Strategy Setting for Remote Gas Reserves
Authors: van Elk Jan F.
Published: December 2007

With excess gas reserves available for development by LNG or feedstock projects, the international gas industry faces new challenges. The challenge for companies in the upstream sector of the industry is to maintain an optimised Gas Reserves Inventory based on the prognosis for the development of their gas markets. Gas exploration and maturation programs should be timed and selected according to the capacity of the markets to absorb their gas.

This is especially the case for Western Australia, where large gas reserves have been found and further exploration prospects are excellent, but market proximity is a key issue.

The decision to initiate gas exploration has to be made many years prior to the maturing of market opportunities and the requirement for reserves certification to support gas sales agreements.

An upstream gas supply venture is typically engaged in several marketing opportunities at the same time. Each of these has a discrete chance of successfully maturing into a gas sales purchase agreement (SPA). This paper explores and proposes a framework for analysing the relationship between a dynamic demand situation and the optimum Reserves Inventory. The method recognises the uncertainty in both the Reserves Inventory and in the prognosed Captured Market.

The concept of a Reserves Cover is introduced as the chance that the gas markets captured (as SPA's), within the reserves maturation timespan, can be supplied from reserves in a company Reserves Inventory. It is used to derive the optimal Reserves Inventory and the requirement and timing for growth of the Inventory through exploration.

The method allows a high level analysis of long term issues like the attractiveness of increasing the Reserves Inventory by gas exploration in the catchment area of the plant or gas scope maturation, and helps to determine the timing of the decision to approach other gas reserves holders.
The Integration of Intelligent Well Systems into Sandface Completions for Reservoir Inflow Control in Deepwater
Authors: Hill Leo E. , Izetti Renaldo , Ratterman Gene , Fonseca Sergio , Moreira Oswaldo , Ray Dan L. , McDonald Ken
Published: December 2007

This paper describes the application of the integration of intelligent well systems into sandface completions for reservoir inflow control in deepwater. In deepwater subsea applications, the ability to remotely control the inflow of water eliminates costly rig intervention while extending well life and increasing recoverable reserves. In deepwater Brazil, open-hole horizontal gravel pack completions with mechanical open-hole isolation have been integrated with proven all electric intelligent well systems. The planning, testing and implementation of these technologies will be detailed in this paper.

Deepwater Brazil continues to be a region where the need to improve economic performance in deepwater drives the implementation of new technologies. Horizontal gravel pack completions were implemented into deepwater subsea Brazil in 1998. To date, over 52 successful subsea horizontal gravel packs have been implemented for both production and injection wells. To further improving the economics of operating in deepwater, implementation of Level 5 Multilateral wells in the Campos Basin was initiated in 1999. As the success of open-hole horizontal gravel packing continued to show economic benefit, it was necessary to provide positive zonal isolation in conjunction with gravel packing. Application of diverter valve technology to achieve zonal isolation was successfully implemented in 5 subsea wells in the Campos Basin during the year 2001. The zonal isolation and long reach of horizontal wells provides the operator the ability to selectively drain a reservoir and achieve the lowest development cost per barrel oil equivalent (BOE).

The fully electric intelligent well system consisting of 3-1/2" and 5-1/2" inflow control devices was deployed on land in the Mossoro Field. The purpose of the installation was to prove the technology before transferring the application into subsea wells. These valves were operated remotely from the office location. After months of successful actuation and data acquisition, the system was pulled and prepared for installation into a deepwater subsea well. During the land based well test, it was deemed necessary to modify the volumes of data stored. Software modifications were made to optimize the rate of data storage.

In order to integrate the Intelligent Well System into the sand control completion, a process of optimization was necessary to meet well construction and operational requirements. This process was inclusive of well path design to reach the targeted well location while controlling the dogleg severity to allow placement of the intelligent well system and completion design to achieve inflow control and minimize operational risk during installation. This is the first application of an all electric remotely operated intelligent well system integrated into a sandface completion for the purpose of reservoir production management.
Multirate Test in Horizontal Wells
Authors: Merzouk Khelifa , Tiab Djebbar , Escobar Freddy H.
Published: December 2007

During a pressure drawdown test, it is quite difficult to hold a constant rate long enough to achieve the test requirements, especially for horizontal wells. Any change in rate, if not taken into account, can lead to erroneous results. Furthermore, pressure drawdown tests are not suitable in sand producing wells. Pressure buildup tests, in high production wells, are uneconomical because of income loss. For gas wells, it is impossible to determine both the coefficients of turbulence and the skin factor from a single constant rate test. For these reasons, a Multi-Rate test should be run instead of buildup or constant rate drawdown tests.

A method is presented to analyze variable rate tests for oil reservoirs. In this study, it is proposed to plot first the pressure variation, Δp/Qn versus the flowing time, t, and in a Log-Log graph the principle of superposition is applied for each flow regime, taking into account the time interval of each flow period. This method is used to estimate the reservoir parameters such as the permeability and skin. The pressure derivative concept is introduced for interpreting multi-rate tests. Only two different parameters are needed from the graph, the slope and intercept. The slope is used to estimate the permeability, and the intercept yields the skin factor.

The proposed technique is applicable for the interpretation of either continuously changing flow rate tests or a series of constant rate tests. This technique is illustrated by several numerical field examples for oil reservoirs.
Hydrocarbon Reservoir Detection Using Acoustic / Seismic Spectroscopy Method
Authors: Barzandji O. H. , Singer J. M. , Rodel E. D. , Leu W. , Plunkett J. , Ghirlanda F. , Akrawi K.
Published: December 2007

The seismic signal of the earth in the frequency range 0.1–20 Hz is recorded continuously from the surface using ultrasensitive velocity sensors. Hydrocarbon reservoirs are characterised by a unique spectral signature present in the frequency range 1–6 Hz. This signature diminishes at the rim of the reservoir and is absent at non-reservoir locations.

The results of our experiments are remarkably uniform for a great number of major oil producing areas worldwide, regardless if producing or virgin reservoirs are examined. Phenomenologically and structurally, the observed signals are similar to previously documented tremor signals ("continuous narrow band ground motion") originating, for example, from volcanoes and glaciers ("fluid-induced tremor"). Numerous continuous seismic signals exist which are usually rather weak and are often considered as useless background noise only. However, this "noise" also carries useful information, which is identified through inherent characteristics, such as the frequency spectrum, statistical properties or non-linear behaviour. It contains a spectral signature characteristic of the media or environment that it has passed through. Some such broadband background noise of the earth is present at every location around the world. The correlation between the output of the acoustic / seismic spectroscopy method and the net pay zone thickness can be calibrated at existing exploration or production wells. Moreover, a spatial mapping of our indicator allows a localisation of the potential oil/water contact and, indirectly, detection of faults and facies boundaries. The seismic spectroscopy method presented here can be used as an easy to apply and environmentally safe method for the detection of hydrocarbon reservoirs as well as for hydrocarbon field development and production monitoring.
Reservoir Modelling With Neural Networks And Geostatistics: A Case Study From The Lower Tertiary Of The Shengli Oilfield, East China
Authors: Wang L. , Tyson S. , Song X. , Cao H. , Wong P. M.
Published: December 2007

This paper demonstrates a case study of a hybrid methodology based on the combination of radial basis function neural network and sequential Gaussian simulation. The methodology is demonstrated with an application to modelling the porosity distribution in an oil reservoir of the Lower Tertiary in the north of Dongying depression, Shengli Oilfield, East China. The methodology first uses radial basis function neural networks to estimate the porosity trends (fluvial directions) from high-dimensional data system with both well and seismic data. Gaussian simulation helps to do the local uncertainty analysis for the reservoir model. The final results from the hybrid methodology assure our confidence on the reservoir model both horizontally and vertically. They are realistic and honour the geological rules of the oilfield. The technique is fast and straightforward, and provides an effective computational framework for conditional simulation.
Comparison of Predictions from Reservoir Models to Actual Production Data: Field Examples
Authors: Ezekwe John N.
Published: December 2007

Reservoir models were constructed on two gas condensate reservoirs (M-4/M4-A and M-6) in the Gulf of Mexico. The gas reservoirs are at a depth of 15000 feet subsea, over pressured and supported by active aquifers. Initial gas production was essentially water-free with steep pressure decline that was later followed by rapid rise in water production. Peak gas production from either reservoir reached about 166 MMCFPD.

The reservoir models were fully compositional. The models were history-matched with production data and then used to predict future performance. This paper compares predictions of the models to actual reservoir production data. The model for the M-6 reservoir predicted gas production with an accuracy of −0.72%, condensate production at +2.80% and water production at +12.4%. The predicted accuracies for the M-4/4A reservoirs are as follows: gas (-0.33%), condensate (−4.99%) and water (+25.56%).

The main objective of this paper is to provide data on the errors associated with the use of history matched models to forecast reservoir performance. Surveys of the petroleum literature indicate that they are few technical papers that compare model predictions to actual reservoir performance data over an extended period of time. Mass publications of these types of results are essential in establishing reservoir simulation as a valuable analytical tool for reservoir engineers. It will also improve its acceptance in the petroleum industry as a reliable tool for prediction of reservoir performance.
Predicting Critical Borehole Pressure and Critical Reservoir Pore Pressure in Pressure Depleted and Repressurized Reservoirs
Authors: Rhett D. W. , Risnes R.
Published: December 2007

Borehole instability, sand production, and completion failures during production and pore pressure depletion continue to be significant problems confronting the petroleum industry. This study develops quantitative models for predicting borehole shear failure in pressure-depleted and repressurized reservoirs by incorporating stress path into equations for shear of borehole wall rock. Critical reservoir pore pressure (CRPP) is defined as the pore pressure below which any drawdown or additional pore pressure depletion will result in the onset of borehole shear failure. Critical reservoir pore pressure and critical borehole pressure (CBHP) are defined in terms of initial stress state, initial reservoir pore pressure, the two horizontal principal stress paths, and commonly used failure criteria. The model includes both overbalanced (drilling) and underbalanced (production) scenarios. The model is applicable to both vertical and horizontal wells.
Field Application of a Novel Core-Based In-Situ Stress Estimation Technique
Authors: Pestman B. J. , Holt R. M. , Kenter C. J. , van Munster J. G.
Published: December 2007

In this paper, we present the first field application of a novel method to estimate in-situ rock stress. This technique, which we have baptized "PKM (Pestman-Kenter-vanMunster) method", uses Acoustic Emission-controlled polyaxial reloading of core in the laboratory. The method works analogous to the Kaiser effect that is observed when reloading along a single stress axis. Contrary to other Acoustic Emission methods, our novel approach is likely to measure present-day stresses, even if the core has been subjected to paleo-stresses that are higher than the present day stresses1. Proof of concept of the method has been provided using extensive experimental work on outcrop sandstone2 (which was subjected to a stress path simulating burial, coring and core retrieval to surface), a simple analytic model3 and numerical simulations using a 3D discrete particle method4.

Recently, the method was applied for the first time on real core material, a preserved sandstone core from the Munnekezijl field (onshore gas) of NAM (Nederlandsche Aardolie Maatschappij) in The Netherlands. An advantage of first application of the technique to this field was that there was availability of good quality stress estimates (for the same layer as where our core was taken) obtained from other methods. A study including hydraulic frac data and borehole breakout shape had been performed in the past to estimate the magnitudes of the major and minor horizontal effective stress. Hence, the results of our method could be compared to other good quality data.

Three samples have been cut from core taken at a depth of some 4000 m [13000 ft] in the Munnekezijl field, for application of our PKM method. Only the weakest sample showed a clear stress memory effect, and was used for stress estimation using our method. The results compared very satisfactorily with the estimates from the hydraulic frac data and borehole breakout analysis. Although this is only the first application, and further validation is needed, these results show a clear promise of the PKM method.
Improved Determination of Stress-Dependent Permeability for Anisotropic Formations
Authors: Bai M. , Meng F. , Roegiers J. -C. , Green S.
Published: December 2007

Qualitative determination of formation permeability is often obtained through laboratory flow tests on core plugs. However, the experimental determination of the permeability for anisotropic plugs (particularly the horizontal permeability) is difficult and less than perfect; generally relying on a highly simplified Darcy flow analysis. Numerical analyses could greatly improve the resolution, reduce the testing costs, and allow parametric investigations using sophisticated 3-D formulations. This paper reports such an analysis that interprets the analytical Darcy flow-pressure measurements, using numerical results to provide a "geometric factor". A numerical iterative procedure correlates the core plug measured flow and pressures at the inlet and outlet boundaries for different boundary sources to derive the core plug anisotropic permeabilities. Since stress changes generally influence permeability, a conceptual model is developed—again via an iterative numerical method—that accounts for the effects of the solid deformations. From this, numerical schemes have been developed using "equivalent geometric factors" with embedded mechanisms for modifying core plug permeability based on the changes in the solid strains that simulate the coupled flow-deformation behavior of selected reservoir rocks. This is the first detailed 3-D numerical analysis iterative scheme that practically allows realistic determination of permeabilities in anisotropic core plugs.
Integrity of Bounding Seals for Geological Storage of Greenhouse Gases
Authors: Jimenez J. A. , Chalaturnyk R. J.
Published: December 2007

The injection of CO2 will give rise to a variety of coupled physical and chemical processes, which may affect the hydraulic integrity of caprocks. Likewise, when CO2 is stored as a component of EOR projects, the initial depletion of the reservoir, and all the influences associated with the EOR processes may affect the hydraulic integrity of caprocks. Therefore, it is necessary to understand how the hydraulic integrity evolves to make geological storage of greenhouse gases a feasible option. Such information must be imbedded in a performance assessment to determine the integrity of a reservoir and its caprock over an extended period of time. A preliminary methodology to evaluate the hydraulic integrity of the Weyburn project is presented.
Numerical Simulation of the Coupled Behavior of Faults During the Depletion of a High-Pressure/High-Temperature Reservoir
Authors: Charlier R. , Fourmaintraux D. , Samier P. , Radu J.-P. , Guiducci C.
Published: December 2007

This paper presents the study of the coupled hydro-mechanical behavior of a faulted HP-HT hydrocarbon reservoir during depletion. Because of the large expected depletion, a number of phenomena may be enhanced, all related to the changes during production, of the in-situ stresses, which control the mechanical response of the reservoir. This includes essentially two types of deformation, the first one being the reactivation of in the reservoir existing faults, while the second one is the reservoir compaction. The objective of this paper is principally to present the study of the first phenomenon, and more particularly their hydro-mechanical aspects. The study has been carried out with the help of numerical simulations of the fully coupled hydro-mechanical behavior of 2D reservoir models, using the finite element code LAGAMINE.
Optimization of Drilling Fluid Design for Managing Wellbore Instability in K-Shale in the Malay Basin of Peninsular Malaysia
Authors: Tan C. P. , Yaakub Mohd Azriyuddin , Chen X. , Willoughby D. R. , Hamid Pauziyah Abdul , Wu B. , Zamanuri Ibrahim , Zahari Ibrahim
Published: December 2007

Drilling experience in K-shale in the Malay Basin of Peninsular Malaysia highlighted the issue of wellbore stability in the formation. A wide range of drilling problems has been experienced, ranging from sloughing shale to tight hole and stuck pipe. Subsequently, a major collaborative project between CSIRO Petroleum and PETRONAS Research & Scientific Services Sdn Bhd was conducted to address the problems. The aim is to develop a technical framework of drilling fluid design and consolidate into a methodology for overcoming wellbore instability-related problems in the shale.

This paper describes the outline of the project and the approach adopted in the development of the methodology. The approach is based on drilling fluid-shale interaction and proven rock mechanics principles which include an extensive laboratory testing program on downhole core specifically cut for the study. Based on the gathered drilling experience and laboratory tests conducted on downhole core material, dominant time-dependent failure mechanisms of the shale were identified. Examples of critical mud weight contour plots and design charts of pressure change (due to drilling fluid-shale interaction mechanisms) which form part of the consolidated methodology for designing optimal drilling fluid are presented. Comparisons between predicted mud weights determined from the contour plots and mud weights used in one of the fields showed an overall good agreement between the mud weights, drilling experience and hole size. Counter to operational expectations, the results from the laboratory study showed that some water-based muds, through correct fluid design, are capable of preventing time-dependent instability in the shale.

The methodology provides a pragmatic approach for managing shale instability problems in drilling extended reach wells in the Malay Basin as well as other regions worldwide. The approach would result in an increase in drilling efficiency and a reduction in drilling cost.
Stability of a Multilateral Junction: Experimental Results and Numerical Modeling
Authors: Papanastasiou P. , Sibai M. , Heiland J. , Shao J-F. , Cook J. , Fourmaintraux D. , Onaisi A. , Jeffryes B. , Charlez P.
Published: December 2007

We studied the stability of multilateral junctions in a combined experimental and numerical modeling program. The experiments were carried out in a true triaxial machine on large size cubical blocks (40 cm) of weak triassic sandstone with two holes intersecting. Six tests have been performed with two different geometrical configurations and three different stress states. The experimental results are presented and compared with numerical modeling obtained with finite element software developed for assessing the integrity of rock surrounding a multilateral junction.
Sand Production Prediction of Gas Field - Methodology and Field Application
Authors: Wu B. , Tan C. P.
Published: December 2007

A model has been developed for sand production prediction in gas wells. The model is based on linear poroelasticity and brittle plasticity with a critical equivalent plastic strain as sand production initiation condition. It included effect of residual strength in the plastic zone surrounding the cavity. The model has been applied to sand formations in a gas well in offshore North West Australia. The calculated drawdown pressure is higher than that based on linear poroelasticity but lower than the predictions based on the plasticity model without including the residual strength effect previously developed.
Assessment Of Several Sand Prediction Models With Particular Reference To HPHT Wells
Authors: Vaziri Hans , Xiao Yuing , Palmer Ian
Published: December 2007

HPHT wells represent one class of problems where the performance of current sand prediction models has not been properly evaluated. We applied three different sanding models to a cluster of six HPHT wells. In all these wells, no sanding was observed under considerable levels of drawdown, certainly far surpassing conditions required for sand failure. Moreover, under failed conditions, the wells were producing high rates of gas for very long periods.

The approaches used included popular analytical shear failure and tensile failure based models which showed an unusually high level of conservatism in their prediction of sanding in high pressure wells. We provide a plausible explanation for this behavior which is attributed to the underlying proposition that sand production occurs when sand fails. While this supposition is used in all applications of such models, in deep, high stress and pressure systems, the problem is magnified due to the fact that failure occurs relatively early in the operating life of the reservoir. We propose an alternate approach where sand production criterion is extended to include not only sand failure but also adequate seepage forces to liquefy the sand and hence mobilize it. This approach is shown to better capture the observed response in the field. As an added bonus, the proposed approach quantifies the volume of sand rather than simply give indications of the onset of sand production. This information is helpful in developing the optimal production strategy throughout the life of field.

In this paper, we discuss the pros and cons of the commonly used models for sand prediction and provide examples to validate the newly proposed concepts for quantifying sand production.
Geomechanical and Thermal Reservoir Simulation Demonstrates SAGD Enhancement Due to Shear Dilation
Authors: Collins P. M. , Carlson M. R. , Walters D. A. , Settari A.
Published: December 2007

A novel numerical analysis is described, in which the steam-assisted gravity drainage (SAGD) recovery process in bituminous oil sand is studied. A geomechanical/reservoir simulator was modified to incorporate the absolute permeability increases resulting from the progressive shear dilation of oil sands. The objective was to obtain a realistic prediction of shear dilation, as the oil sands approached failure and beyond, and the concomitant increases in permeability. Changes in the in situ stresses that caused this dilation were due to the combined effects of reduced effective stress with high-pressure steam injection, and increased deviatoric stress with thermal expansion under lateral confinement. The resultant volumetric strains were used to modify the absolute permeability characteristics of the oil sands as the SAGD process progressed. The spatial and temporal growth of enhanced permeability zones resulted in an accelerated steam chamber growth.

The relationship between volumetric strains and absolute permeability changes was obtained from existing laboratory data on quality specimens of non-bituminous Athabasca oil sands. The source sample was obtained from an outcropping of the McMurray Formation, thus avoiding most of the sample disturbance associated with unconsolidated core obtained conventionally. Under triaxial loading, the resultant volumetric strains increased absolute permeabilities by a factor of 4 to 6.

The analysis is innovative in that the model used an effective stress approach, and used the volumetric strains to modify absolute permeabilities. Thus, the encroaching SAGD steam chamber was found to modify the stress regime, which in turn modified the permeabilities within the reservoir. Geomechanical enhancement of the SAGD process was found to be a significant beneficial effect, and would be increased by operating the SAGD process at higher injection pressures.
Extrapolation of Rock Mechanical Properties From a Cored Well to an Uncored Well Through the Use of Electrofacies
Authors: Miskimins Jennifer , Graves Ramona , Hurley Neil , Barree Robert
Published: December 2007

A technique for extrapolating core-measured rock mechanical properties from a cored well to an uncored well is presented. The process uses electrofacies and square wave techniques to develop rock mechanical property logs for the uncored wells.

Data from the North LaBarge Shallow Unit (NLBSU) is used to develop the process. The NLBSU wells require hydraulic fracturing to generate economic production rates. The NLBSU produces from Cretaceous-age Mesaverde sandstone that is composed of thinly bedded sand and shale layers. The reservoir heterogeneity caused by these layers complicates hydraulic fracture growth characteristics. Improvements in hydraulic fracture simulation are needed to accurately predict these growth characteristics. This includes improvements in input data, such as rock mechanical properties, for the simulations.

The described methodology uses electrofacies developed from core and FMI in one well and extrapolates the electrofacies to other wells via an AO10 induction log curve (depth of investigation 10 in (25 cm)). Induction logs are run in almost every well in the field and provide a universal extrapolation medium without incurring additional costs. The process uses acoustic velocity measurements for rock mechanical values, but any accepted measurement technique can be used. Only two major facies are present in the NLBSU and the presented technique only addresses the two facies. However, the methodology can be expanded to include more facies if cutoff values can be established.

The process described in this paper is being used to improve hydraulic fracture modeling in the NLBSU. It can be used in other fields which need improved modeling also. Additionally, it can be used for any computer simulation program that requires rock mechanical property input including reservoir simulation and wellbore stability programs.
Dynamic Optimization of Water Flooding with Smart Wells Using Optimal Control Theory
Authors: Brouwer D. R. , Jansen J. D.
Published: December 2007

We used optimal control theory to develop optimization algorithms for the valve settings in smart wells. We focussed on their use in injectors and producers for waterflooding of heterogeneous reservoirs. As a follow-up to an earlier, intuitive, optimization approach, we developed systematic algorithms and investigated the effect of well constraints on the scope for optimization. The objective was to maximize recovery or net present value over a given time period. We concluded that: 1) For wells operating on bottom hole pressure constraints the benefit of using smart wells is mainly reduced water production rather than increased oil production. 2) For wells operating on rate constraints, there is a very large scope for accellerating production and increasing recovery, in combination with a drastic reduction in water production.
Modeling and Flow Simulations of a North Sea Turbidite Reservoir: Sensitivities and Upscaling
Authors: Stephen K. D. , Clark J. D. , Pickup G. E.
Published: December 2007

We have created a variety of detailed geological models, in order to carry out a sensitivity study in a turbidite oil reservoir. The base case stochastic model was generated using well-log data, seismic attribute data and information from outcrop analogues. In addition, some small-scale models were created to capture the effects of fine sedimentary structure (mudstone intra-clasts, and interbedded sandstone and mudstone layers).

The main focus of this paper is on the flow simulation, upscaling and sensitivity analysis, rather than on the geological modelling. We carried out a range of sensitivity studies on two-phase flow parameters, gridding effects and upscaling. Our results show that the large-scale geological structure is potentially dominant. Integration of seismic information and the definition of zone transitions is crucial if an adequate history match is to be obtained. Redistributing the facies by successive realisations also impacted strongly on the productivity. The dominant two-phase flow property was wettability, particularly the shape of the capillary pressure curve, which could lead to a large capillary transition zone.

In this particular field, the fine-scale structure, as modelled for two genetic units, did not have a large impact on the results, because these units occurred in isolated regions and were largely by-passed. Small scale heterogeneity in the main Channel Sandstone genetic unit did impact on flow, however.
The Use of a Virtual Chemistry Laboratory for the Design of Matrix Stimulation Treatments in the Heidrun Field
Authors: Ziauddin M. , Kotlar H. K. , Vikane O. , Frenier W. , Poitrenaud H.
Published: December 2007

In this study, a new technique for designing matrix stimulation treatments is examined. The technique uses a geochemical simulator in combination with simple experiments with batch reactors and short reservoir cores. The new technique is compared with alternative design techniques, such as those using long core flow tests and laboratory radial flow setups. The strengths and weaknesses of the design techniques are presented.

The effectiveness of the treatment design with the new technique is evaluated with a case study on a well in the Heidrun field. It was found that compared to alternative approaches, the new technique provides a simpler, faster, and cost-effective method for treatment design. Furthermore, the new technique also provides a more accurate scaleup to reservoir flow conditions than other design alternatives. The improved accuracy results from more precise accounting for reservoir and damage mineralogy and radial flow. Heidrun is a heterogeneous reservoir with high clay content. We found that these effects were more practical to examine with a validated simulator than with specially designed laboratory experiments.

Treatment design in the case study was difficult because the target well was the first to be acidized in the formation. As no prior stimulation experience existed, a reliable means of treatment design was required. We show how the new technique can be used to develop such a design. Post-treatment data from the well showed a successful matrix treatment design. The productivity index for the well increased from a pre-treatment value of 20 to a post-treatment value of 55 m3/day/bar at standard conditions.
Improved Rt And Sw Definition From The Integration Of Wireline And LWD Resistivities, To Reduce Uncertainty, Increase Pay And Aid Reservoir Navigation
Authors: Page G. , Benefield M.
Published: December 2007

The measurement of true formation resistivity (Rt) in order to determine fluid saturations, has resulted in the development of a wide variety of wireline and logging while drilling (LWD) measurement systems. These devices are generally treated as independent systems when determining Rt and fluid volumetrics. However, the sensor technologies are complementary, and all available data can be used together to effectively reduce uncertainties inherent in the single data sets. This results in more accurate water saturation (Sw) calculations, and reduced reservoir uncertainties. Techniques, which will be discussed, are not limited to mathematical models and inversion, but include methodologies for identifying the best acquisition strategy in order to acquire the required data, correct preparation for geosteering and reservoir navigation.

The development of wireline tensor resistivity devices that are capable of measuring transverse electrical anisotropy has significantly improved the quantification of fluid saturations in thin bedded formations, and even thicker formation units drilled through at high apparent dip. Additional low contrast pay zones have also been identified which were missed by traditional techniques. In certain circumstances LWD measurements can be used to provide an initial qualitative assessment of electrical anisotropy, and determine if these specialised wireline measurements would be beneficial in order to quantify fluid saturations. The identification of these zones will be discussed with the benefits and limitations involved.

Where tensor resistivity data is available it can significantly improve the geological models used for geosteering. Incorporation of this data can predict anomalies not seen on simple models, which may be interpreted incorrectly resulting in unnecessary wellbore deviations, and loss of reservoir penetration. Examples of these effects, and their magnitude, will be used to demonstrate the importance of incorporating electrical anisotropy in the models.
10 Years of WAG Injection in Lower Brent at the Gullfaks Field
Authors: Instefjord Rune , Todnem Annick Chazy
Published: December 2007

The Gullfaks field is a large oil field in the Norwegian sector of the North Sea. Production started in 1986 with water flooding as the primary recovery method. A WAG injection pilot in lower Brent well A-11 was initiated in March 1991. The well is located south in the GFA-area.

A simulation model was built and history-matched until January 1993 for the whole pilot area, including upper Brent. Predictions to the end of year 2005 indicated an increased oil recovery of 0.3 mill. Sm3 in addition to some accelerated production. Most of the predicted increased oil recovery was however reached during 1993.

The WAG injection has continued in A-11 but with fewer gas periods the last years. The updated estimate of increased oil recovery from WAG injection in A-11 up to year 2001 is 2 mill. Sm3.

The paper will also give a short evaluation of WAG injection in two other lower Brent injectors at Gullfaks with a joint estimated increased oil recovery of 0.7 mill Sm3.
Optimisation of an Aggressive Drilling Programme at the Statfjord Field - Maximising Production in a Mature Field
Authors: Hansen Anne-Grethe , Brendsdal Atle , Arnesen Dag Schistad , Morris Marian
Published: December 2007

The giant Statoil-operated North Sea oil field Statfjord is currently far down its production decline curve. During 23 years of production more than 60% of the STOOIP has been recovered, and the remaining reserves are characterized by complex distributions of oil, water and gas.

In order to obtain a cost-effective production of the remaining oil, an aggressive drilling and intervention programme is necessary. The main challenge that the geoscientists and reservoir engineers face in this scenario is to identify remaining oil in targets becoming increasingly smaller, more complex and more uncertain, and to drain these in the most profitable manner. This paper reviews the working method that has been used at the Statfjord Field when defining a drilling schedule. It shows how the different work processes are linked, starting with the identification of possible new well locations, continuing with the estimation of reserves and risk evaluation and ending up with final drilling projects.
Minimizing Energy Cost by Maintaining High Volumetric Pump Efficiency
Authors: McCoy J. N. , Becker D. J. , Rowlan O. L. , Podio A. L.
Published: December 2007

Many wells operate in the United States with beam pump artificial lift equipment. Most of these wells have a pump capacity that exceeds the production rate of the well. These wells would operate more efficiently and at a lower cost if they operate with a full pump. This requires the elimination of gas interference in the pump, insuring that the pump has no mechanical problems and then optimizing the run time so that the well operates periodically, yet removes all the available liquid from the wellbore.

Optimization of the pumping system requires an integrated analysis1 of the prime mover, surface equipment, wellbore equipment, downhole pump, downhole gas separator and the reservoir. Analysis is based on information obtained from liquid level instruments, dynamometers and motor power probes.

This paper reviews the analysis of the pumping system and then discusses the various methods of controlling the operating time with devices such as timers and pump off controllers. Using the integrated analysis method presented in this paper, the operator can monitor pump fillage and set run time on these devices, thereby efficiently producing his well.
Advances in Heavy Oil and Water Property Measurements Using Low Field Nuclear Magnetic Resonance
Authors: Bryan J. L. , Manalo F. P. , Wen Y. , Kantzas A.
Published: December 2007

Low field NMR of fluids can be used to measure physical properties of water and oil such as viscosity and diffusion coefficients. Remarkably accurate measurements can be obtained from simple and fast measurements in a beaker. Algorithms for the determination of heavy oil and bitumen viscosity have been previously developed that can provide first order estimates over a variety of viscosity ranges (100-107 mPas) covering variable temperatures, water/oil ratios and oil compositions. When the algorithms are tuned for single oils, then the accuracy increases dramatically and the predictions are as accurate as direct viscosity measurements.

In this paper, the aforementioned algorithms are extended to predict NMR response and viscosity predictions for live vs. dead heavy oil samples, and virgin vs. solvent-diluted heavy oil samples. The viscosity predictions of oils in beakers are compared to the predictions of the same oils while in reservoir conditions (i.e. in-situ). The proposed algorithms can be used in reservoir characterization and on-line viscosity measurements in heavy oil reservoirs.

A NMR based water cut meter was recently introduced for accurate measurement of oil and water cut values. The instrument appears to be superior to conventional measurement devices since it does not seem to be affected by salinity, emulsion characteristics or temperature to date. Extensive field measurements have proved the above claims. The principles of this water cut device are further extended to the measurement of water cut oil cut and gas cut under laboratory conditions. Mixtures of heavy oil and bitumen with water and air were prepared in the laboratory and their NMR characteristics were identified under a broad range of saturations. The results were compared against mass balance measurements. It is demonstrated that the two-phase measurement algorithms can be extended to three phase systems. Thus the first step towards accurate multi-phase measurements can be achieved.
Fully Coupled Chemico-Geomechanics Model and Applications to Wellbore Stability in Shale Formation in an Underbalanced Field Conditions
Authors: Wang Yarlong , Lu Baoping
Published: December 2007

Time-dependent wellbore stability has been observed in the field. Yet, a combined effect of pore fluid advection, swelling shale, and thermal diffusion may not be sufficient to explain and simulate this process adaquately. A coupled chemico- geomechanics constitutive model combined with a model with an ion-concentration dependent strength is developed in this paper. Strength reduction due to water hydration seems to dominate the time-dependent process in wellbore collapse. The ultimate borehole instability is proposed to be determined by the damage radius not the onset of wellbore wall mechanics failure, the latter is usually practiced. A field case is analyzed, and from experimental testing and simulations, it is concluded that the time-dependent nature is dominated both by the time- dependent strength reduction and damage zone propagation.