bluuebunny/crossref_metadata_2025 huggingface dataset:
Increasing Oil Recovery by Preventing Early Water and Gas Breakthrough in a West Brae Horizontal Well: A Case History
Authors: Mclntyre A. , Adam R. , Augustine J. , Laidlaw D.
Published: December 2007

Inflow control devices, which prevent early water breakthrough by passively controlling the inflow profile of a well, have had a long and successful history in the Norwegian Sector of the North Sea and in Saudi Arabia. This paper will document the first application of inflow control devices in the UK sector of the North Sea.

This application took place on a 4,288 ft horizontal sidetrack of a well in the West Brae field. The completion was designed for a homogeneous permeability but the as-drilled permeability, as shown by logging-while-drilling data, had very high permeability regions in the heel of the horizontal, and lower permeability in the toe. If conventional completion methods (i.e. stand-alone screens, gravel packs, or expandable screens) were used, the result would likely have been early water breakthrough and well abandonment. The authors will highlight the inflow control device selection process, integrated completion and reservoir analysis, well completion operations summary, and production results and predictions. The successful application of inflow control devices on this well illustrates that long horizontal wells can be completed, the problem of early water and gas breakthrough can be prevented, and oil recovery can be increased by using inflow control devices.
Impact of Viscous Fingering on the Prediction of Optimum WAG Ratio
Authors: Juanes R. , Blunt M. J.
Published: December 2007

In miscible flooding, injection of solvent is often combined with water in an attempt to reduce the mobility contrast between injected and displaced fluids, and control the degree of fingering. Using traditional fractional flow theory, Stalkup estimated the optimum water-solvent ratio (or WAG ratio) when viscous fingering effects are ignored, by imposing that the solvent and water fronts travel at the same speed. Here we study how the displacement efficiency and the mobility ratio across the solvent front vary with the WAG ratio, when fingering is included in the analysis. We do so by computing analytical solutions to a one-dimensional model of two-phase, three-component, first-contact miscible flow that includes the macroscopic effects of viscous fingering. The macroscopic model, originally proposed by Blunt and Christie, employs an extension of the Koval fingering model to multiphase flows. The premise is that the only parameter of the model —the effective mobility ratio— must be calibrated dynamically until self-consistency is achieved between the input value and the mobility contrast across the solvent front. This model has been extensively validated by means of high-resolution simulations that capture the details of viscous fingering and carefully-designed laboratory experiments.

The results of this paper suggest that, while the prediction of the optimum WAG ratio does not change dramatically by incorporating the effects of viscous fingering, it is beneficial to inject more solvent than estimated by Stalkup's method. We show that, in this case, both the PVI for complete oil recovery and thedegreeof fingering are minimized.
Gas/Oil Nonequilibrium in Multicontact Miscible Displacements within Homogeneous Porous Media
Authors: Al-Wahaibi Y. M. , Muggeridge A. H. , Grattoni C. A.
Published: December 2007

Compositional simulation is usually used to predict the performance of multi-contact miscible (MCM) recovery schemes. One key assumption in most such simulations is that of instantaneous compositional equilibrium is achieved between phases in each grid block. This is despite the fact that most grid blocks are tens of metres long and at least a metre thick.

This paper investigates the non-equilibrium observed in series of multi-contact miscible displacements performed in the laboratory. For simplicity a two-phase, three-component (IPA/water/cyclohexene) liquid system that exhibits an upper critical point at ambient conditions was used. Both vaporising and condensing drives were performed in well-characterised homogenous glass-bead packs. The use of analogue fluids and bead-packs enabled visualisation of the displacements as well as the usual measurements of effluent composition against time and recovery.

Non-equilibrium was observed in the effluent from both the condensing and vaporising experiments. This increased with flow-rate but appeared to be independent of the permeability and the length of the bead-pack. Further experiments investigating the influence of gravity on vertical displacements indicated that non-equilibrium may also be a function of the viscous to gravity ratio.

Detailed simulation using a commercial compositional simulator was unable to predict this non-equilibrium unless the results were tuned to the experimental observed effluent profiles using alpha factors. This is despite the fact that all PVT data, relative permeabilities and other pack properties were taken directly from experiments. However good match was obtained from a layered model with the permeability distribution obtained from a unit mobility ratio miscible displacement in the same pack.

These results are consistent with physical dispersion being the underlying cause of the non-equilibrium. Viscous fingering is discounted due to the low mobility ratio (~2) of the displacements.
Multiscale Regularization of Flooding Optimization for Smart-Field Management
Authors: Lien M. , Brouwer D. R. , Mannseth T. , Jansen J. D.
Published: December 2007

Smart fields can provide enhanced oil recovery through the combined use of optimization and data assimilation. In this paper, we focus on the dynamic optimization of injection and production rates during waterflooding. In particular, we use optimal control theory in order to find an optimal well management strategy over the life of the reservoir that maximizes an objective function (e.g. recovery or net present value). Optimal control requires the determination of a potentially large number of (groups of) well rates for a potentially large number of time periods. However, the optimal number of well groups and time steps is not known a-priori. Moreover, taking these numbers too large slows down the optimization process and increases the chance of achieving a sub-optimal solution. We investigated the use of multi-scale regularization methods to achieve grouping of the control settings of the wells in both space and time. Starting out with a very coarse grouping, the resolution is subsequently refined during the optimization. The regularization is adaptive in that the multi-scale parameterization is chosen based on the gradients of the objective function. Results for the numerical examples studied indicate that the regularization may lead to significantly different optimum strategies, but may result in a similar cumulative oil production.
Influence of Initial and Residual Oil Saturation and Relative Permeability on Recovery from Transition Zone Reservoirs in Shallow Shelf Carbonates
Authors: Byrnes A. P. , Bhattacharya S.
Published: December 2007

Early work characterized the relationship between initial oil (Soi) and residual oil saturation to waterflood (Sorw) and recent work has investigated theoretical oil recovery in transition zones. This study details experimental results for shallow-shelf carbonate lithologies and explores model application in thin carbonate reservoirs, such as those of the Midcontinent U.S., where production is often primarily from the transition zone.

Understanding Soi, Sorw, and relative permeability (kr) in transition-zone dominated reservoirs is fundamental to understanding recovery, and planning and managing IOR and EOR operations in these reservoirs. Drainage and imbibition oil-water relative permeability measurements were performed on Pennsylvanian-age oomoldic limestones and Mississippian-age moldic porosity mudstone to grainstone lime-dolomites. For these rocks, Sorw increases with increasing Soi due to enhanced trapping by emplacement of oil in fine pores. The Land-defined trapping characteristic, C, increases with increasing porosity resulting in less trapping with increasing porosity. This relationship, coupled with increasing "irreducible" water saturation (Swrri) with decreasing porosity and permeability, results in a systematic increase in Sorw with decreasing porosity/permeability and Soi. As Soi decreases with depth in the transition zone, proper modeling of kr requires a family of kr curves that reflect changes in kr with changing Soi. Utilizing a family of kr curves in recovery analysis shows that both oil and water recovery are greater than predicted from models utilizing kr curves with a constant Soi and Sorw. Oil recovery is higher because Sorw(Soi) is lower and water recovery is higher because Sw increases with proximity to the oil-water contact and as Sorw(Soi) is lowered.

These results validate and expand on use of the Land equation in shallow-shelf carbonates and help to explain both the high oil recovery and the high water production rates that are often evident in these reservoir systems.
Favorable Attributes of Alkali-Surfactant-Polymer Flooding
Authors: Zhang D. L. , Liu S. , Yan W. , Puerto M. , Hirasaki G. J. , Miller C. A.
Published: December 2007

A laboratory study of the alkali-surfactant-polymer (ASP) process was conducted. It was found from phase behavior studies that for a given synthetic surfactant and crude oil containing naphthenic acids, optimal salinity depends only on the ratio of the moles of soap formed from the acids to the moles of synthetic surfactant present. Adsorption of anionic surfactants on carbonate surfaces is reduced substantially by sodium carbonate but not by sodium hydroxide. The magnitude of the reduction with sodium carbonate decreases with increasing salinity.

Particular attention was given to a surfactant blend of a propoxylated sulfate having a slightly branched C16-17 hydrocarbon chain and an internal olefin sulfonate. In contrast to alkyl/aryl sulfonates previously considered for EOR, alkaline solutions of this blend containing neither alcohol nor oil were single-phase micellar solutions at all salinities up to and even exceeding optimal salinity with representative oils. Phase behavior with a West Texas crude oil at ambient temperature in the absence of alcohol was unusual in that colloidal material, perhaps another microemulsion having a higher soap content, was dispersed in the lower phase microemulsion. Low interfacial tensions existed with the excess oil phase only when this material was present in sufficient amount in the spinning drop device. Overall solubilization of oil and brine for this system was high, leading to low interfacial tensions over a wide salinity range and to excellent oil recovery in both dolomite and silica sand packs. These experiments were performed with surfactant concentrations as low as 0.2 wt%. It was necessary that sufficient polymer be present to provide adequate mobility control and that salinity be below the value at which phase separation occurred in the polymer/surfactant solution.

A one-dimensional simulator was developed to model the process. By calculating transport of soap formed from the crude oil and injected surfactant separately, it showed that a gradient in local soap-to surfactant ratio develops during the process. This gradient increases robustness of the process in a manner similar to that of a salinity gradient in a conventional surfactant process. Predictions of the simulator were in excellent agreement with the sand pack results.
Laboratory Investigation of the Effect of Solvent Injection on In-Situ Combustion
Authors: Cristofari J. , Castanier L. M. , Kovscek A. R.
Published: December 2007

Application of cyclic solvent injection into heavy and viscous crude oil followed by in-situ combustion of heavy residues is explored from a laboratory perspective. The solvent reduces oil viscosity in-situ and extracts the lighter crude-oil fractions. Combustion cleans the near well region as well as thermally stimulates production. Both solvent injection and in-situ combustion are technically effective. The combination of the two methods has, however, never been tried to our knowledge.

Hamaca (Venezuela) and West Sak(Alaska) crude oils were employed. First, ramped temperature oxidation studies were conducted to measure the kinetic properties of the oil prior to and following solvent injection. Pentane, decane, and kerosene were the solvents of interest. Second, solvent was injected in a cyclic fashion into a 1-m long combustion tube. Then, the tube was combusted. Hamaca oil presented good burning properties in all cases. The pentane extracted lighter components of the crude preferentially depositing effective fuel for combustion. West Sak oil, however, did not exhibit stable combustion properties following solvent injection, even when metallic additives were added to enhance the combustion. We were unable to propagate a burning front within the combustion tube. Nevertheless, the experimental results show that this combined solvent-combustion method is applicable to a broad range ofoil reservoirs
A Model to Predict Gas Hydrate Equilibrium and Gas Hydrate Saturation in Porous Media Including Mixed CO2-CH4 Hydrates
Authors: Bhangale A. Y. , Zhu T. , McGrail B. P. , White M. D.
Published: December 2007

Phase equilibrium of gas hydrates is altered in porous media as compared to bulk systems. Inside porous media, the thermodynamic potential of chemical components changes due to molecular interactions with pore walls and due to the energy required to maintain capillary equilibrium. A pore-freezing model was developed that can be used to predict gas hydrate equilibrium for pure CH4, CO2 and mixed CH4-CO2 systems in saline pore waters for any given pore size distribution. The important feature of this model is that it takes into consideration salting out phenomena, i.e. increase in salt concentration due to gas hydrate and ice formation. It also gives the gas hydrate saturation in porous medium. A new EOS developed for prediction of bulk gas hydrate equilibrium conditions, based on van der Waals – Platteeuw model, is used in the pore freezing model and can also be used to calculate heats of formation of these hydrates for a given pore size and pressure. The results obtained from the model are compared with experimental results.
Oil Recovery From Fractured Carbonates by Surfactant-Aided Gravity Drainage: Laboratory Experiments and Mechanistic Simulations
Authors: Adibhatla B. , Mohanty K. K.
Published: December 2007

Waterflooding recovers little oil from naturally fractured carbonate reservoirs if the matrix is oil-wet and fracture intensity is high. Laboratory experiments and mechanistic simulations have been conducted to understand the injection of dilute anionic surfactant solutions into oil-wet, fractured reservoirs. In this process, surfactant diffuses into the matrix, lowers IFT and contact angle, which decrease capillary pressure and increase oil relative permeability enabling gravity to drain the oil up. The rate of oil recovery increases with an increase in matrix permeability, a decrease in initial gas saturation, a decrease of fracture height or spacing, and an increase in wettability altering capabilities of the surfactant. Increasing the surfactant concentration does not necessarily enhance the oil recovery rate, because IFT and wettability alterations are not related to surfactant concentration linearly. Adsorption of anionic surfactants on calcite can be suppressed with an increase in pH and a decrease in salinity.
Investigation of Pore-Scale (Local) Mixing
Authors: Jha R. K. , Bryant S. L. , Lake L. W. , John A.
Published: December 2007

Local displacement efficiency in miscible floods is significantly affected by mixing taking place in the medium. Despite decades of research on mixing and dispersion, there remain questions about the amount of mixing occurring at pore-scale (hereinafter local). This study has investigated the local mixing experimentally as well as computationally.

We developed a thin electrical-conductivity probe to measure local solute concentration to quantify local mixing. Miscible tracer displacement experiments were carried out in a homogeneous sand pack. Local solute concentrations measured at several radial and axial positions using the probe indicate non-zero local mixing. The core scale mixing is the same as the local mixing for the homogeneous pack.

Local mixing is also investigated by solving the Navier-Stokes and convection-diffusion equations in two dimensional packing of circular disks. The computational studies qualitatively support the experimental observations for the homogeneous sand pack and explain the mixing mechanism inside the pore body. Mixing results from velocity variations in pore throats and bodies and molecular diffusion. The converging-diverging flow around sand grains causes the solute front to stretch, split and rejoin. In this process, the area available for diffusion increases by an order of magnitude. Diffusion tends to reduce local variation in solute concentration inside the pore body. If the fluid velocity is small, diffusion is able to homogenize solute concentration inside each pore. Increasing the fluid velocity has the same effect on local mixing as decreasing diffusion coefficient by the same factor. In limit of very large fluid velocity (or no diffusion) local mixing tends to zero and core-scale mixing is entirely caused by variations in velocity.
Injection Strategies To Overcome Gravity Segregation in Simultaneous Gas and Liquid Injection Into Homogeneous Reservoirs
Authors: Rossen W. R. , van Duijn C. J. , Nguyen Q. P. , Vikingstad A. K.
Published: December 2007

We earlier presented a proof for the model of Stone (1982) for gravity segregation in steady-state, horizontal gas-liquid flow in homogeneous porous media using only the standard assumptions of the method of characteristics. We extend this method here to cases of co-injection of gas and liquid over only a portion of the formation interval, injection of water above gas over the entire formation interval, and injection of water and gas in separate zones well separated from each other.

If gas and liquid are injected at fixed total volumetric rates, the horizontal distance to the point of complete segregation is the same, whether gas and liquid are co-injected over all or any portion of the formation interval. The volume of reservoir swept by gas may be affected by these different injection strategies, however, and is not directly predicted by our model. At fixed injection pressure, the deepest penetration of mixed gas and water is expected when fluids are co-injected along the entire formation interval.

At fixed total injection rate, injection of water above gas gives deeper penetration before complete segregation than does co-injection, but again exactly where the two fluids are injected does not affect the distance to the point of segregation. At fixed injection pressure, injection of liquid above gas is predicted to give much deeper penetration before complete segregation. When injection pressure is limited, the best strategy for simultaneous injection of both phases would be to inject gas at the bottom of the reservoir and liquid over the rest of the reservoir height, with the ratio of the injection intervals adjusted to maximize overall injectivity.

These results apply equally to gas-liquid flow and to foam. Sample computer simulations for foam injection agree well with the model predictions if numerical dispersion is controlled.
A Novel 3D Field-Scale Reservoir Numerical Simulator for Predicting the Fines Migration and Production Performance
Authors: Ju B. , Dai S. , Fan T. , Wu H. , Li S. , Zhang M.
Published: December 2007

Sand fines release and migration is a universal problem in the production of oil from unconsolidated sandstone reservoirs which can result in both sanding problems and profound effects on oil recovery. A new three dimensional (3D) field scale mathematical model, differing from those used for conventional oil reservoir numerical simulator in that both the advanced theories of sand particle release and migration, is presented. And the model is solved by a finite-difference method and the line successive over relaxation (LSOR) technique. A numerical simulator is written in Fortran 90 and VC++ and it can be used to predict (1) the sand content in produced liquid, (2) the porosity and permeability changes caused by sand release and migration in formation, and (3) well production performances and residual oil distribution. A series of runs of oil field examples with five-spot patterns were made on the numerical simulator. The results show that sanding problems in the oil formation can accelerate the heterogeneity of the reservoir rocks, and has an obvious influence on production performances: water-drive process, water-cut trends, and oil recovery. In a conclusion, the new simulator improves the ability and accuracy for numerical simulating the development of the unconsolidated sandstone reservoirs.
Efficient Data Management on the Rig of the Future
Authors: Kirkman M. , Chapman P. , Greaves C. , Turnbull H. , Johnson D.
Published: December 2007

In 2000 BP identified an opportunity to collaborate with a major Norwegian operator and develop an initiative for updating the drilling data standards for contractor to operator rig-site data flows to speed and enhance decision-making. This led to the successful WITSML initiative for XML and Web Services standards in the Drilling and Completions domain1 This has seen rapid acceptance by all the major operators, service contractors and application vendors (www.witsml.org).

The WITSML initiative started with the objective to update the existing methods for drilling data exchange at the rig for the internet age, and to incorporate the lessons learned from its precursor, WITS 2. WITS was designed for point-to-point transfers whereas WITSML, which is based on a functional XML and web services approach, facilitates wider access to data. WITSML acquired early success at replacing the WITS standard; however, moving further into contextual and report data to create true application-to-application interoperability required the operator community to intervene.

The intervention by BP has been to stimulate the marketplace and create a foundation to drive additional functionality for data exchange and reporting in the rig based environment and is the subject of this paper.

The approach taken by BP has been twofold: enabling the acceptance of contextual data from data acquisition providers by promoting enhancements of a widely used daily reporting tool; enabling the storage of time-based data within BP's own custodial databases and the merging of contextual data with the same. The deployment of the first trials of these enhanced applications is discussed. These enhanced applications have been used in harmony with "Decision Support Centres" where the opportunities to use improved technology to enable rig-office team decision-making are explored.
The Central Role and Challenges of Integrated Production Operations
Authors: Ella R. , Reid L. , Russell D. , Johnson D. , Davidson S.
Published: December 2007

This technical paper endeavours to describe the central role of Integrated Production Operations (IPO) in exploiting hydrocarbon reserves through the production phase of an asset. It provides definition of the key characteristics of IPO, sets out business case criterion for investment in IPO, challenges current industry positions and paradigms on future field management and provides a generic roadmap for operators seeking to be early adopters of IPO as a platform around which to organize their Digital Oil Field of the Future 1 (DOFF) initiatives.
Facilitating Risk Management in E&P Using Collaboration and Data-Visualisation Tools
Authors: Cain G. , Deliac E.
Published: December 2007

Technological progress alone is insufficient in the E&P industry today given the wider administrative, legal and organisational challenges that E&P development Projects currently have to contend with. In particular, risk management has become fundamental to both operator and service provider companies.

This paper presents two E&P case studies that illustrate how the use of collaboration and data visualisation tools provided significant assistance and support to E&P risk management activities. The first case study concerns a deep offshore E&P development project where the risk management activity had become virtually impossible to coordinate because of a very aggressive project execution environment. The implementation of collaboration technology for the project's executive management team established and sustained risk visibility at the appropriate level, whilst allowing all risk-related information to be seamlessly integrated with the rest of the project execution plan. The second case study concerns the collection and monitoring of safety and risk performance indicators (RPIs) at operational E&P sites of a major oil company. We will describe how analysis and feasibility work led to the design and development of a methodological tool capable of collecting and organising a diversified set of RPIs and then presenting them in an innovative graphical form for analysis and prioritisation.

The added value for E&P projects is evident: risk management without risk.
The Use of Integrated Decision Making To Embed Sustainable Development
Authors: Kuijper M. , Stephenson M. , Howard M.
Published: December 2007

The necessity of sustainable development presents some significant opportunities and challenges to companies in the petroleum sector. They need to consider the consequences of their activity on the economy, environment and society, as well as how these domains interact with each other. There follows a requirement to integrate these consequences and interactions into corporate actions. And, since actions are the consequences of decisions, decision-making can provide a vital foothold for developing sustainable development thinking within the corporation. This paper describes Integrated Decision Making (IDM), an approached developed by Shell Exploration & Production in Europe designed to enable decision makers to contribute to sustainable development when executing their core responsibilities. The paper describes the theoretical background to IDM, its history, practice and some lessons-learned. The IDM approach continues to be improved by the authors.
Well Location Selection from a Static Model and Multiple Realisations of a Geomodel Using Productivity-Potential Map Technique
Authors: Narayanasamy R. , Davies D. R. , Somerville J. M.
Published: December 2007

One of major field development decision is choosing the number of wells required to efficiently drain an oil or gas reservoir. It is an interactive process in which various development scenarios are chosen and their performance analysed. Formation geology and zone connectivity have a major impact on the choice of well location since they determine well productivity. The industry's current well placement selection process is time consuming and costly. It requires analysing numerous development options by performing a large number of flow simulations.

This paper describes a technique to partially automate this well placement process. It has been found that a new map which ranks the reservoir zones based on their productivity potential can speed-up, and hence reduce the cost, of this decision making process. This map, termed the Productivity Potential Map (PPM), is based on fundamental petroleum engineering principles. It is generated from the numerical reservoir models developed from standard data measured during the exploration and appraisal process. It incorporates both static and dynamic properties (e.g. porosity and saturation respectively).

A static and stochastic numerical reservoir model are coupled with the PPM and well locations that maximise production are identified. The technique was tested using flow simulation models of two UK reservoirs by generating PPM and identifying the drilling targets that could deliver the maximum, sustained production potential.

The first example uses a static reservoir simulation model of a field that had been production history matched for 18 years. Compared to the development plan implemented many years ago, the PPM map reduced the number of development wells by 15% while increasing the cumulative oil production by 2.6% at 2.5 years since production started. The second example employs multiple realisations developed from exploration well data using PETREL™. Well locations were chosen from a PPM map derived from these multiple realisations. The chosen well locations clearly matched the reservoir geology. Well locations were also chosen from a STOIIP based map. The performance of the STOIIP and PPM based field development were compared - the PPM based well placement consistently performed best.

PPM thus reduced the flow simulation effort required, improved the flow forecast and reduced the uncertainty in flow performance. This paper will show that the use of a PPM is a quick and cost-effective technique for analysis of the reservoir production performance and the generation of drilling targets. The technique may also aid reservoir management decisions e.g. water flood front location and selecting the preferred water flood front direction.
Analysis of Possible Applications of Dual ESPs—A Reservoir Engineering Perspective
Authors: Davies D. R. , Narayanasamy R. , Kristensen B. , Somerville J. M.
Published: December 2007

Field installation of a dual Electric Submersible Pump (dESP) completion has been reported. The purpose of the second pump was to increase the pumping capacity and to act as a back-up to improve the reliability of the pumping system. However, dESPs can potentially address a much wider range of reservoir management challenges. This paper will analyse the performance of a dESP in a range of reservoir scenarios. It will show how dESP performance can be modelled using commercially available, coupled, well performance and reservoir simulation tools.

Four dESP applications were analysed. Where possible, the robustness of the numerical modelling results will be compared with analytical predictions. dESPs gave improved oil production and recovery in reservoirs with strong aquifer support and became progressively more attractive in a layered reservoir scenario as the pressure difference between the production zones increased. However, while dESPs had no significant advantages in a long, horizontal well placed in a homogenuous resevoir, they can increase recovery in a tilted, layered resevoir. Preliminary results on a deep-sea well example where the combination of deep-set single ESP (sESP) and a second pump placed at the seabed are discussed.

This work provides a comparison of the drivers for the choice of a sESP and a dESP in the scenarios studied. It illustrates a modelling methodology and provides dESP selection guidelines, thus aiding the increased application of this technology.
Acid Number Measurements Revisited
Authors: Fan T. , Buckley J. S.
Published: December 2007

We propose an improved procedure for measuring acid numbers and illustrate the significance of the results by correlating with oil/brine interfacial properties.
Beyond The Big Crew Change, Dumbing Down Or Getting Smarter?
Authors: Heaney M. , Davidson J.
Published: December 2007

The introduction of innovation and increasingly complex "Smart" technologies coincides with reduced manning levels, and the "big crew change". Corporate drivers require that the industry operate safely without damaging the environment, uphold and enhance company reputations while developing and maintaining producing on a shorter time line, reduce manning and control costs, extend the life of ageing infrastructure, accelerate development with minimised Opex minimised maintenance requirements and maximised uptime. As they reduce the requirement for intervention employees must embrace change and be open to innovation

Several soft "people factors" such as openness to change, enthusiasm for the new and an environmentally aware mindset may assist in improving the effectiveness of the systems.

Several other challenges also need to be addressed – over reliance on "Black box Data" or decision support systems that mask inexperience, and a willingness to take risks that may not be tempered by understanding.

This paper explores the strength of such effects and indicates several areas for attention. It evaluates several methods used to quantify these factors and present a methodology to address the emergent issues.

Stated simply, we have to provide easy access to years of experience for those who are coming next. We have to put old heads on young shoulders.
Steady-State Coning Solutions With Multiple Wells and Reservoir Boundaries
Authors: Ansari R. Z. , Johns R. T.
Published: December 2007

The critical oil (or gas) rate to avoid coning of unwanted fluids into production wells is an important design parameter. Simulation methods are useful to predict critical rates in reservoirs with complex heterogeneities and boundaries, but they are manpower intensive and prone to errors when large grid blocks are used. Current analytical methods are quick and easy to use, but their assumptions are too restrictive. Thus, there is a need for improved analytical methods that can account for well patterns and more complex boundaries, and also serve as further benchmarks for simulation.

This paper makes analytical solutions more realistic by extending existing single-well analytical solutions to account for multiple wells and common no-flow and constant pressure boundary conditions. A potential function is derived to superimpose existing single well coning solutions for single-or simultaneous two-phase flow. Capillary pressure and relative permeability effects on coning are included. The only limiting assumptions are vertical equilibrium (VE) and steady-state flow.

Comparisons with simulation show good agreement in predicted critical oil rates when steady state and VE are approached. VE and steady-state are approximately achieved when aspect ratios are greater than about 10. Even when aspect ratios are less than 10, the predicted critical rates are useful in that they are always conservative. The proposed analytical solutions are quick and easy to use compared to reservoir simulation and can be used in the development of downhole water-sink technology (DWS).
Experimental Investigation of Drainage Capillary Pressure Computed From Digitized Tomographic Images
Authors: Olafuyi A. O. , Sheppard A. P. , Arns C. H. , Sok R. M. , Cinar Y. , Knackstedt M. A. , Pinczewski W. V.
Published: December 2007

This paper presents comparisons between drainage capillary pressure curves computed directly from 3D micro-tomographic images (micro-CT) and laboratory measurements conducted on the same core samples. It is now possible to calculate a wide range of petrophysical and transport properties directly from micro-CT images or from equivalent network models extracted from these images. Capillary pressure is sensitive to rock microstructure and the comparisons presented are the first direct validation of image based computations. The measured data include centrifuge and mercury injection drainage capillary pressure for fired Berea, Bentheimer and Obernkirchner sandstones and unfired Mount Gambier carbonate. The measurements cover a wide range of porosities and permeabilities. The measurements are made on core samples with different diameters (2.5 cm, 1.5 cm, 1 cm and 0.5 cm) to assess the effect of up-scaling on capillary pressure measurements. The smallest diameter samples were also used to obtain the 3D micro-CT images. Good agreement is obtained between the experimental measurements and direct computations on 3D micro-CT images.
Optimum Selection of Artificial-Lift System for Iranian Heavy-Oil Fields
Authors: Taheri A. , Hooshmandkoochi A.
Published: December 2007

Kuh-E-Mond as the first priority of heavy oil prospect in Iran is located in southwest of Iran and 80 km southeastern of Boushehr, one of the important Iranian ports in Persian Gulf coasts.

Well MD-6 was spudded on September 19, 1984 for confirmation of the heavy oil occurrence in Asmari-Jahrum formation and Bangestan group in Kuh-E-Mond structure. Black tarry oil with gravity of 13 API degree occurred in the samples through most of the Sarvak limestone. Because there were no development programs in this field, the well was secured and the rig was released on May 5, 1985. The field was put on the development program on early 1999. The well MD-6 was opened and the static oil level in the well was 400 m below surface.

Clearly, some sort of artificial lift was needed in order to flow the well and restore the production rate to the normal levels and to maximize the ultimate recovery.

The decision of which artificial lift method to use is very important to the long-term profitability of the field. An improper selection of artificial lift can reduce production and increase the operating cost substantially. Once a decision has been made on the type to install on a well, it can be rarely altered whether or not the method selected was and still is the optimal for the existing conditions.

This paper presents the screening criteria on the different artificial lift techniques and discusses why the choice were confined to PCP as the most suitable techniques to be applied in this well. The paper studies the technical consideration behind each method of artificial lift for this well (Beam Pump, ESP, PCP, Gas Lift and Hydraulic Lift) and the technical discussions for selecting PCP.
Continuous 4D Monitoring is Now Reality
Authors: Arts R. , Brouwer J. , Hofstee C. , Kooijman J. , Drijkoningen G.
Published: December 2007

With the implementation of smart fields where sensors play a major role for measurement and control of the production process, continuous monitoring becomes increasingly important. In wells it is common practice to constantly monitor parameters like flow, pressure, and temperature. For imaging techniques like (active) seismics so far monitoring has only been applied in a time lapse manner with a repetition interval generally in the order of a year, not in a continuous way. The Vallhall field probably comes closest to continuous monitoring with permanently installed ocean bottom cables (OBC) and repeated surveys in the order of months.

The main challenge with permanent seismic monitoring is not so much the technical feasibility, but more the data transfer and processing of the vast amounts of acquired data. TNO together with the TU-Delft, KNMI and ASTRON have started to implement a seismic monitoring network in the Netherlands using an ultra-fast digital optical fibre network linked to one of the most powerful computers in the world, the IBM BlueGene/L system. Data can be sent to this computer at speeds up to 20 Tera-bits/second. Currently passive seismic data is constantly acquired at Exloo, the first out of 50 test fields to be installed in the next year.

Besides seismics, the network and the ICT infrastructure make it possible to combine all sorts of observations from the natural environment, infrastructure and processes anywhere and any time. This paper will give an overview of the first results of the incoming data and a description of the ICT infrastructure and network. Furthermore a view will be given on future applications.
Right Time Decision of Artificial Lift Management for Fast Loop Control
Authors: Campos S. R. V. , Silva M. F. , Correa J. F. , Bolonhini E. H. , Filho D. F.
Published: December 2007

This paper describes the efforts of Petrobras to design control strategies for artificial lift optimization. The work relies on several challenges starting with a process variable identification for each artificial lift method up to the implementation of control algorithms on wellhead. The target achieved is an artificial lift closed loop management.

Onshore and offshore cases will be presented showing the different sensibilities and importance that the same variable can represent depending on the artificial lift method and the well type completion. It will also be discussed an option of high level language tool to translate the experience of petroleum engineers into field algorithms.

Petrobras elected three values as the main target for fast loop design:

– First, to develop tools to add operational flexibility and right time decision for the artificial lift methods. The objective is to assure the best economical production point for each well, even under flowrate change due to zone selectivity and secondary recovery management. Another focus is to enable real time analysis, fault diagnostic and permanent monitoring. Technologies behind these tools are based on heuristics and artificial intelligence. – Second, to develop a methodology that facilitates the translation of knowledge from a senior petroleum well analyst into field strategies. A photography of the oil industry professionals shows an advanced age profile. The expertise of those engineers applied in real time is one of the milestones to reach the profits that the Smart field development allows. – Third, field connectivity and data availability. The automation architecture is designed to be hardware and software independent. The objective is to assure data to reach the analyst with transparency of hardware and software implementation. Communication specifications represent the project data flow assurance. This communication directive is the key for integration between smart completion and artificial lift automation. The synchronized production data integrated with reservoir engineering analysis built Petrobras strategy for fast and slow loop management.
Production Optimization with Adjoint Models Under Nonlinear Control-State Path Inequality Constraints
Authors: Sarma P. , Chen W. H. , Durlofsky L. J. , Aziz K.
Published: December 2007

The general petroleum production optimization problem falls under the category of optimal control problems with nonlinear control-state path inequality constraints (i.e. constraints that have to be satisfied at every time step), and it is acknowledged that such path constraints involving state variables are particularly difficult to handle. Currently, one category of methods implicitly incorporates the constraints into the forward and adjoint equations to tackle this issue. However, these are either impractical for the production optimization problem, or require complicated modifications to forward model equations (simulator). Thus, the usual approach is to formulate the above problem as a constrained nonlinear programming problem (NLP) where the constraints are calculated explicitly after the dynamic system is solved. The most popular of this category of methods (for optimal control problems) has been the penalty function method and its variants, which are, however, extremely inefficient. All other constrained NLP algorithms require the gradient of each constraint, which is impractical for an optimal control problem with path constraints, as one adjoint has to be solved for each constraint at each time step at every iteration.

We propose an approximate feasible direction NLP algorithm based on the objective function gradient and a combined gradient of the active constraints. This approximate feasible direction is then converted into a true feasible direction by projecting it onto the active constraints by solving the constraints during the forward model evaluation itself. The approach has various advantages. Firstly, only two adjoint evaluations are required at each iteration. Secondly, all iterates obtained are always feasible, as feasibility is maintained by the forward model itself, implying that any iterate can be considered a useful solution. Thirdly, large step sizes are possible during the line search, which can lead to significant reductions in forward and adjoint model evaluations and large reductions in the objective function. Through two examples, we demonstrate that the algorithm provides a practical and efficient strategy for production optimization with nonlinear path constraints.
A Service-Oriented Data-Composition Architecture for Integrated Asset Management
Authors: Soma R. , Bakshi A. , Orangi A. , Prasanna V. K. , Da Sie W.
Published: December 2007

The goal of an Integrated Asset Management (IAM) framework for the oil and gas industry is twofold. From the end users’ perspective, it should offer a single, easy-to-use user interface for specifying and executing a variety of workflows from reservoir simulations to economic evaluation. The framework should not require the user to be an expert in any of the underlying software applications; in fact, the details of selecting, configuring, and invoking the underlying software modules should be hidden from the end user. From the software development perspective, the IAM framework should facilitate seamless interaction of diverse and independently developed applications that accomplish various sub-tasks in the overall workflow. For instance, it should be possible to pipe the output of a reservoir simulator running on one machine to a forecasting and optimization toolkit running on another and in turn piping its output to a third piece of software that can convert the information into a set of reports in a specified format.
Combining Adjoint Calculations and Quasi-Newton Methods for Automatic History Matching
Authors: Rodrigues J. R. P. , Wachter A. , Conn A. , Moraes R. J. de , Silva F. P. T. da
Published: December 2007

This work describes the combination of adjoint methods for derivative calculation with a trust-region Quasi-Newton optimization algorithm for solving history matching problems. The techniques employed allowed for the resolution of problems with a larger number of parameters, when compared to other approaches, based on derivative free optimization or the forward method for derivative calculation.

Applications to both synthetic and real cases will be shown. A substantial improvement of the match was obtained in all examples. Problems with more than 250 parameters were solved efficiently. The ability to handle problems with a large number of parameters is exploited to discuss the possibility of accessing the uncertainty in the history matching process through exausting the space of possible models.