bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Risk, Resource and Value Assessment of Unconventional Petroleum Assets
Authors: Stabell C. 
Published: December 2007

Abstract
Unconventional (continuous) petroleum resources present unique assessment challenges. Unconventional petroleum assets are large single accumulations that cannot be counted and analyzed as discrete entities that are delineated by downdip water contacts. This paper presents an integrated stochastic risk, resource and value assessment framework for decisions related to exploration and exploitation of unconventional petroleum assets. The framework builds on the FORSPAN model (Schmoker, 1999) where the continuous accumulation is viewed as a play consisting of a set of discrete cells that have not been explored (exploited) and that have the potential for economic production. Each cell is the drainage area of a fixed number of wells. Recoverable volumes can vary between cells, with some cells being non-commercial. We extend the FORSPAN framework in several ways. First, the model includes an estimated size (in an uncertain number of cells) of potential "sweet spots". Second, the model also includes a measure of exploration efficiency that represents the probability of finding sweet spots. Exploration results in a discovery sequence of sweet spots where the sequence is partially ordered by an exploration efficiency estimate. Third, we do a full cycle economics assessment for each sweet spot. The overall full cycle economics assessment with expected aggregate production profile and after tax cash flows are used to compute the estimated net present value of the unconventional petroleum asset. The paper concludes with a discussion of model limitations and potential improvements.
New Life to an Old Field
Authors: Swanson J. S. , Swanson D. C. , Jarvis M. , Hall R. 
Published: December 2007

Abstract

Overview and Challenge
The East Tunstill Field is a tight, under-saturated sandstone reservoir with a 9% recovery factor on primary depletion. Marginal current production and a previous relatively unsuccessful waterflood did not present the potential value of the field. In order to present this value, within a limited budget, new procedures and methods were necessary. A project workflow was designed to handle the field characteristics of a high number of wells and many years of production, resulting in a large amount of data that could be used to achieve a better analysis.
The operator, Penn Virginia ("PVA"), believed an improved reservoir description applied with simulation methods could yield a better understanding of previous drainage, fluid movement, and the volume and location of the remaining oil. Additionally, the operator decided to utilize a new volumetric balancing technology that allowed a fast (15 minutes) analysis of various waterflood injection/producer patterns to derive the most economic and efficient flood pattern and thereby highlighting its potential.
Identifying the Economic Savings Beyond the Reservoir
Authors: Hogg C. 
Published: December 2007

Abstract
Utilizing past multilateral installations and studies, this paper analyzes and discusses potential up front cost savings gained from a multilateral approach. Downhole savings as a result of minimized drilling requirements, reduced casing requirements, and other equipment and operations are discussed. Additional cost savings resulting from decreased surface and support requirements will are also covered in detail. Additionally, intangible cost savings in the form of reduced rig mobilization costs, lessened HSE costs and lessened rig time cost savings are included in the discussion.
Identifying Technical and Economic EOR Potential Under Conditions of Limited Information and Time Constraints
Authors: Manrique E. , Wright J. 
Published: December 2007

Abstract
The application of Enhanced Oil Recovery (EOR) processes increases the economic value of existing fields through increased oil recovery and field life extension. This is especially important in depleted and mature fields, as oil production rates decline and water production increases. Additionally, environmental concerns also benefit EOR projects such as CO2 injection providing new opportunities for depleted and mature fields combined with a disposal of CO2 capturing emissions from industrial sources.
Generally, oil companies (from majors to independents) operate a large field portfolio or a large number of reservoirs with lack of information. In some other cases, many reservoirs lack enough financial performance to justify information or data gathering. The latter represents a common barrier to identify appropriate investment opportunities in a particular or a portfolio of reservoirs.
This paper describes an approach to perform an economic evaluation of EOR projects based on advance screening criteria and full field evaluations under conditions of limited information and time constraints. The proposed methodology estimates EOR technical viability and production potential in a particular field based on international field experience and fast evaluation tools such as analytical simulators and economic software programs. The proposed methodology not only provides a systematic approach for evaluating and ranking technical and economic EOR performance within a risk management framework but also shows an excellent potential to support decision-making processes in oil property acquisition and for the exploitation of unconventional reservoirs (CBM and Tight Gas), among others.
Active Filter-Cake Technology – Eliminating the Need for Post-Completion Cleanup
Authors: Ravitz R. , McCarter M. , Taglieri A. , Colazas G. , Montes E. , Rizkalla S. 
Published: December 2007

Abstract
A new generation Reservoir Drill-in Fluid (RDF) has been developed to mitigate the potential of damage to the producing formation and eliminate the need for post-completion cleanup. This RDF system was developed to perform synergistically where openhole gravel-packing or expandable screen completion styles are utilized.
This new RDF system generates an active filter cake which is impermeable to aqueous fluids, thus reducing fluid loss into the producing formation. Concurrently, the now residual filter cake is permeable to formation hydrocarbons. This system utilizes organophilic components which generate preferential oil channels in the residual filter cake, thereby, eliminating the need for stimulation/cleanup from either internal or external chemical breakers. The preferential channels also help reduce the influx of aqueous formation and/or injection fluids.
This paper details the development of the RDF system and the engineering of it on two openhole gravel-pack completions in the East Wilmington Field off the coast of Long Beach, California. It discusses the development of the system and the field trials. A maintenance schedule used by the fluid engineers for anticipated potential problems is also discussed. The field performance is discussed and lessons learned are contrasted with conceptual design. Comparative data from earlier horizontal wells are included and contrasted with respect to the RDF system design, drilling parameters and well start-up. Finally, the initial well-test data are presented.
Forensic Reservoir Characterisation Enabled With Underbalanced Drilling
Authors: Culen M. S. , Killip D. R. 
Published: December 2007

Abstract
Underbalanced (UB) drilling techniques are no longer being used simply to minimize reservoir impairment and improve access to remaining reserves in depleting fields. Traditionally archived and forgotten after the well was drilled, production data and reservoir information gathered while drilling underbalanced are increasingly gaining importance with oil and gas companies.
One Operator has been using UB technology in both clastic and carbonate reservoirs initially to maximize production through the minimization of reservoir impairment. Most of the operator's fields are supported by a weak aquifer or are under tertiary development through waterflood, and the task of water management is a growing concern. While minimizing reservoir damage is now a foregone conclusion when discussing UB operations, the ability to further maximize production through the ability to shut off water-producing zones is now a prime driver for drilling UB.
The comparison of ‘snapshot’ fluid production data during drilling offers a unique perspective on the well being drilled against geophysical LWD/MWD and post-drilling logging data. Temporal production data offers another piece to the reservoir makeup puzzle, and when placed alongside other available data allows reservoir engineers and geophysicists to forensically characterize their reservoir.
Processes Determining the Composition of Produced Water from Subsea Fields and Implications for Scale Management - Birch Field, UKCS
Authors: McCartney R. A. , Williams J. C. , Coghlan G. 
Published: December 2007

Abstract
Produced water analyses from the Birch Field, UK North Sea have been interpreted and combined with simulation results to explain the causes of changes in produced water compositions over time. Preliminary conclusions are that two formation waters are present in the oil leg, both trapped at the time of oil emplacement. Lower salinity formation water has been expelled from the Kimmeridge Clay Formation (KCF) and dominates shallower sections of the reservoir. Higher salinity formation water is thought to be ancient Brae aquifer water and dominates the deeper sections. Some lateral variability in formation water compositions is evident. Produced water from individual wells is a mixture of the lower salinity formation water, higher salinity formation water and injected water. Trends in produced water compositions over time reflect a relative decrease in formation water production and increase in injection water production. Depending on the constituent, reactions occurring as a result of injection of water into the reservoir also affect the composition of produced water. The results have challenged previous concepts relating to water production at Birch and will be considered in scale management plans in future. They can also be used to constrain reservoir simulations, to aid enhanced oil recovery decisions and to provide more reliable tracking of injection water and formation waters entering the production wells at Birch.
More generally, this study has demonstrated the importance of evaluating produced water analyses as early as possible after water breakthrough. Integration of reservoir simulation studies with the interpretation of produced water analyses can provide information that benefits scale management, STOIIP calculations, reservoir models, and tracking of injection water as well as providing analogue information that can help reduce uncertainties associated with the development of deep water and marginal subsea fields.
Optimizing Estimates of Probabilistic Reserves from Production Trends Using a Bayesian Approach
Authors: Jimenez E. A. , Idrobo E. A. , Ernandez J. , Startzman R. 
Published: December 2007

Abstract
The estimation of probabilistic reserves distributions is nowadays a mandatory task in the oil industry. The trade-off between speed and accuracy, coupled with the urgency of results is still making of Decline Curve Analysis (DCA) one of the most popular method to address these calculations.
In a previous paper, we introduced a quick and efficient application (PREP) to estimate probabilistic reserves distribution combining the advantages of stochastic methods (Bootstrapping) and DCA. Although the proposed tool is robust and effective, one of the limitations found was reconciling the statistical uncertainty associated in the generation of the DCA parameter distributions with the observed production trends.
The objective of this paper is to present a proficient procedure to reduce the uncertainties in DCA probabilistic reserves estimation via Bayesian techniques. The procedure allows the analysis of multiple decline trends taking full advantage of the self-learning capability implicit in Bayesian techniques. The usefulness of the results is maximized when coupled with proper reservoir knowledge, leading to statistically strong results.
The new methodology was applied in the reserve evaluation of three (3) Colombian fields located in the Valle Superior del Magdalena Basin in Colombia, South America. The method provided a new set of declination parameters with smaller covariance, reducing the uncertainty compared to any previous reserves distribution.
A Quantum Leap in Horizontal Gravel-Pack Technology
Authors: Mendez A. , Curtis J. , Evans B. , Farias R. 
Published: December 2007

Proposal
Horizontal gravel packs typically employ heavy sand or ceramic gravels, laid down with un-gelled brines in the well-known alpha/beta wave sequence.As operators push the limits of horizontal open hole interval lengths, especially in low fracture gradient formations, it may become technically difficult or economically unfeasible to perform the gravel pack with conventional fluids and gravels.
Ultra lightweight gravels allow significant reductions in pumping rate (to avoid fracturing the formation), without risking premature settling and screen-out, therefore, longer wells can be treated.Higher gravel concentrations can also be used, even at low pump rates, resulting in drastic reductions in fluid volumes and treatment time, which is critical in cost-intensive offshore applications.In certain instances, the alpha wave can be eliminated, and the well packed directly in the beta wave mode, from toe to heel.
This paper summarizes the development and application of the ultra lightweight media and associated technologies for horizontal well gravel packing.Pioneering case histories will also be reviewed from the initial wells treated.
Case History of Breaking a Paradigm: Improvement of an Immiscible Gas-Injection Project in Buracica Field by Water Injection at the Gas/Oil Contact
Authors: de R. A. Lino U. 
Published: December 2007

Abstract
In May 1991 an immiscible carbon dioxide injection project began in the Sergi-C reservoir in the Main Block of Buracica Field. The injection has been performed in seven wells located in the upper part of the reservoir. Some time after the beginning of CO2 injection, the reservoir pressure increased and an increment of the oil production was attained. But, later on, the producing wells in the upper rows, beyond being the most productive wells, were also those that experienced the higher producing rates of CO2. This obliged for the shutting in of some wells and also the creation of a gathering system for the CO2 being produced, with the connection of the annular space of some wells to their pipelines. It was verified that the producing rate of gas and CO2 followed close upon the CO2 injection rate. Production data and simulation results have shown that the interruption or reduction of the CO2 injection would cause a significant reduction of the oil production. Due to the great demand for CO2 by new projects it was considered which would be the best way for ceasing the CO2 injection in the field, aiming at an increase in the supply of CO2 for other projects, but reducing its detrimental effect on the oil production. The adopted solution consisted in the creation of a water barrier for isolation of the CO2 cap. For this, seven wells closer to the gas-oil contact were chosen for water injection of a total rate of 2400 m3/day. The plan considers the interruption of CO2 injection when the water barrier is completely formed, which will take about 4 to 5 years after the beginning of the water injection. At that time the CO2 injection can be interrupted without impairing the project profitability. The water injection began in January 2002 and since then the project has been showing to be a success. The success can be seen by the increase in the oil rates and reservoir pressure and also reduction of CO2 production. The paper presents the main features of the project, as well as the results attained so far.
Chemical Water Shutoff Interventions in the Tunu Gas Field: Optimisation of the Treatment Fluids, Well Interventions, and Operational Challenges
Authors: Chenevière P. , Falxa P. , Alfenore J. , Poirault D. , Enkababian P. , Chan K. S. 
Published: December 2007

Abstract
Several Indonesian gas fields such as the Tunu field exhibit a specific behavior which causes a rapid decrease of the gas production. At shut in conditions, cross-flows from watered out layers to gas producing layers, were clearly identified as the major cause for gas production impairment.
The offloading of water from wells is performed at the preliminary stage of water production and often allows restarting the wells, but in a second stage it is ineffective. The nature of the damage in the gas-producing zones is not entirely understood but it seems to be a combination of at least two phenomena: (i) water adsorption on the high amount of clays present in these highly water sensitive layers (15 to 40 wt %) and (ii) water imbibition due to some capillary pressure experienced in the tightest layers (0.1 to 10 mD). Clay swelling or migration seems also to contribute for this damage but to a lesser extent.
Unwanted water along with gas and condensate production from several layers were quantified from multi-rate PLT, to define a strategy for well candidate selection and water shut off interventions. An inorganic gel was then selected to be selectively squeezed into the water-producing layers. The optimization of this fluid and of the preflush fluid required a complete qualification program which aimed at three main objectives: (a) maintain injectivity during the squeeze to allow an entire placement of the fluid, (b) provide, once set an extrusion pressure sufficient to withstand a significant drawdown and (c) gives a treatment's lifetime of one year minimum.
Three wells were treated in 2004, following the qualification of the fluids, the selection of candidate wells and the implementation of a complete treatment setup on a barge. This article describes the successes and the failures of some of them, pointing out the need for finely filtered fluids, low viscosity fluids and robust selective placement tools.
CO2 Energized Hydrocarbon Fracturing Fluid: History & Field Application in Tight Gas Wells in the Rock Creek Gas Formation
Authors: Gupta D. V. S. , Leshchyshyn T. T. 
Published: December 2007

Abstract
Gelled hydrocarbon has been used as a fracturing fluid from the early days of fracturing. Over the years, its use has diminished in the U.S. However, its use internationally continues to the present day in Canada, South America, Russia and East Asia. The paper will discuss the use of gelled oil fluids in Canada, particularly in low pressure tight gas wells, where the use of CO2-energized gelled hydrocarbon fluids has been very successful. The chemistry of these fluids and their application is discussed. The energized fluids have been used in a variety of formations and in wells of permeabilities from 0.1 mD to 10 Darcies, depths in excess of 3000 m and BHT from 10 to 110°C. Initial and longer-term production data from wells fractured with the energized fluid will be compared to wells fractured with conventional gelled hydrocarbon fluids to show the effectiveness of the system in tight gas applications.
The case study will include gas wells fractured and producing from the Rock Creek formation east of Edson, Alberta, Canada from 47-10W5 to 56-15W5 in the Western Canadian Sedimentary Basin (WCSB). Observations on proppant type and proppant amount are made in addition to comments on the fracturing fluid selection.
Scale Inhibitor Placement: Back to Basics—Theory and Examples
Authors: Sorbie K. S. , Mackay E. J. 
Published: December 2007

Abstract
Downhole scale inhibitor (SI) squeeze treatments are a common feature of the scale control plans of many oil operators. However, reservoir formations are large, heterogeneous rock bodies in which fluid flow is strongly determined by the permeability structure. Thus, when a slug of scale inhibitor is injected into the formation, fluid placement is an important issue. To design successful squeeze treatments, it is necessary to know where the injected fluid goes or, even better, we would like to control where the fluid package is placed in the near-well reservoir formation.
In this paper, we go "back to basics", in that we re-derive the analytical expression that describe placement in linear and radial layered systems for unit mobility and viscous fluids. In itself, this is not new since these equations are well known. However, we apply them in a novel manner to describe scale inhibitor placement. We also demonstrate the implications of these equations on how we should analyse placement both in the laboratory and by numerical modelling before we apply a scale inhibitor squeeze. We present an analysis of viscosified SI applications for linear and radial systems both with and without crossflow between the reservoir layers.
Visualisation experimental results are also presented of simple and viscosified slug placement in layered bead packs with crossflow between layers. It is shown that these agree very well with the numerical predictions. Additional calculations on near well placement in radial systems are also presented showing how the theory carries over into real field near-well, heterogeneous systems. Some novel ideas are presented on the application of viscosified scale inhibitor treatments.