bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Method to Analyze and Plan for Political Uncertainties for Use in Project Evaluation and Management
Authors: Craig D. A. 
Published: December 2007

Abstract
Today&s petroleum engineers and economists are very comfortable incorporating technical and economic risk into project net present value calculations. These same individuals are often not as comfortable incorporating political uncertainties into project evaluation and few have had any training in this area. The goal of this paper is to provide the project evaluator with a method to analyze those political uncertainties that may impact the project.
There is no consistent, industry-wide definition for uncertainty, risk and politics. Therefore, this paper provides definitions for all.
A political uncertainty cross-plot is used to evaluate possible political threats that could impact project economics. The cross plot spans the legal to the extra-legal in the x-direction and the microeconomic to the macroeconomic in the y-direction. For example, regulatory changes appear in the first quadrant and consider legal and macroeconomic factors. Depending on the type of regulatory change, revenues could be reduced or costs increased. Personnel safety threats appear in quadrant four where extra-legal and microeconomic factors overlap. Kidnapping of company personnel is a type of personnel safety threat and the cost of insurance or extra-security staffing is considered in this quadrant.
A data collection method is given to provide the analyst with enough knowledge to estimate the subjective probabilities of potential risks to project profitability. The data needed to evaluate the likelihood of potential threats can be found from a variety of sources. Five areas are analyzed - government & politics, business - oil & gas, global linkages & interdependence, macroeconomics, and social, cultural, and human development.
The information developed using this method can be updated regularly to estimate if the threats are increasing or decreasing. Appropriate action to manage the risk, estimate the cost of managing the risk, and/or estimate the financial impact if the threat becomes a reality can be determined.
Multistage Oil-Base Frac-Packing in the Thick Inglewood Field Vickers/Rindge Formation Lends New Life to an Old Producing Field
Authors: Moodie W. H. , Minner W. A. , Fernandez M. , Lockman D. , Burgett W. 
Published: December 2007

Abstract
The Inglewood Field, located along the Newport-Inglewood fault trend in the Los Angeles Basin, was discovered in 1924 and has an estimated ultimate recovery of 400 million barrels of oil. The traditional shallow reservoir production target zones are the Vickers and Rindge formations, which have been waterflooded since 1954. These intervals consist of a 1200'-1800'+ thick sequence of friable turbidite sands in the depth range of 1000'-3000'. Contemporary reservoir development in the complex, faulted reservoir rock has been connected with improved reservoir characterization, leading to infill drilling and waterflood pattern realignment. However, infill well success using conventional water-base cased-hole and openhole gravel packing has been marginal and inconsistent, because the long intervals and large reservoir pressure variations across the completion column make it difficult to complete the wells with an effective gravel pack and without formation damage.
In 2003, a radically different frac pack completion strategy was developed and evaluated. This low-cost frac-packing strategy has the advantages of true wellbore stimulation (or at least skin minimization) and ability to effectively connect across the highly laminated formation layers. Eleven wells were completed with as many as 8 stacked frac pack stages per well, with each stage pumped over a wire-wrapped screen to enable fracturing and gravel packing in one step. In the new wells, a limited entry perforation strategy was used to effectively distribute the fracture treatments across each stage interval. 20° API Inglewood crude was used as both the frac fluid and completion fluid to virtually eliminate formation damage, reduce costs, and simplify completion procedures. Several innovative new downhole tools (based on cementing tool technology) and procedures were developed to enable multiple stages to be performed in a simple yet effective manner, and allow the technique to be applied in both new wells and to remediate existing cased-hole completions.
Average initial production rate from the frac pack wells was 110 BOPD and 1250 BWPD. This response is much better than the rates from cased-hole gravel packs, and on par with open-hole gravel pack wells, but without the risk associated with gravel packing a thick openhole interval in a single step. Stabilized oil cuts have settled in at &gt;5%, which compares favorably to the field average of 3% due to more effective completion of the deeper, lower permeability intervals that have been less swept by the waterflood. In response, additional wells will be completed at Inglewood and several other Los Angeles Basin fields in 2004.
Predicting Horizontal Gas Well Deliverability Using Dimensionless IPR Curves
Authors: Chase Robert W. , Steffy Cassandra R. 
Published: December 2007

ABSTRACT
A dimensionless inflow performance relationship (IPR) model, similar to Vogel's method, developed by Chase and Alkandari to predict the deliverability of an hydraulically fractured vertical gas well, has been modified to predict the performance of horizontal gas wells. An equation given in terms of the Xe/Xf ratio was derived by combining equations offered by Joshi and by Russel and Truitt. Twenty wells were simulated and the IPR curves generated were compared to those obtained using the modified dimensionless IPR model. The average error between the IPR curves generated using the new model and the simulator was 11.1%. When just the absolute open flows were compared, there was an average error of only 3.34%. Reservoir rock and fluid data and modified isochronal test were obtained on a real horizontal well. The IPR curve generated from a conventional modified isochronal analysis and that generated from the new model were compared. The AOFs were within 2.1% of each other, and the average error between the two curves was approximately 4%. The dimensionless IPR curve model appears to offer a cost-effective way of predicting horizontal gas well deliverability.
Fluid Oscillation Tool Restores Gas Delivery Rate from Storage Wells
Authors: Jockel Dan , Guoynes John , Stilson David 
Published: December 2007

Abstract
Gas-storage wells experience gas deliverability decline over the lifetime of the well for a variety of reasons, but most often decline is caused by near-wellbore skin damage. Recent developments in diagnostic techniques enable operators to identify near-wellbore damage and apply a tailored treatment to reverse the deliverability decline. In a Sayre, Oklahoma gas-storage field, gas deliverability was improved 32.5% in 14 wells, using pretreatment damage diagnostic analysis to remove near-wellbore damage with new coiled-tubingconveyed fluid-oscillation treatments.
A fluid-oscillating tool (FOT) is key to the damage-removal technology. The FOT sends out alternating bursts of fluid to create pulsating pressure waves within the wellbore and formation fluids. These pressure waves help break up near-wellbore damage and restore effective permeability by carrying the fluid past the wellbore into the formation. These oscillating pressure waves are not affected by standoff, which is common with conventional jetting or velocity tools. Kinetic energy in the pressure pulse travels through the wellbore fluid with no appreciable energy loss. The pressure waves expand spherically, providing 360° coverage as the tool is moved through the interval. As damage is removed, the waves penetrate deeper into the formation.
This paper presents a technical description of the processes incorporated to remediate damage in the Sayre field and the technology used in the oscillation treatments. A case study from West Virginia is also presented. Both cases illustrate pretreatment planning, job design, application procedures, and results.
Microannulus Leaks Repaired with Pressure-Activated Sealant
Authors: Rusch David W. , Sabins Fred , Aslakson John 
Published: December 2007

Abstract
Sustained casing pressure is a serious problem that is prevalent in most of the oil producing regions of the world. Annular pressure can be a significant safety hazard and, on a number of occasions, has resulted in blowouts. Sustained casing pressure results from the migration of fluids in the annulus. The most common path for migration of fluids is through channels in the annular cement. To safely and economically eliminate sustained casing pressure on a well in the Gulf of Mexico, W& T Offshore, Inc. utilized an injectable pressure-activated sealant technology to seal channels in the annular cement of their well and eliminate the casing pressure. The mechanical integrity of the well was restored, saving over $1,000,000 compared to a conventional rig workover.
Pre-Frac Treatment Pressure Analysis in the Huntersville Chert and Oriskany Sandstone
Authors: Gottschling John , Myers Roger 
Published: December 2007

Abstract
Pre-frac pressure analyses were done on the Oriskany or Huntersville Chert/ Oriskany combination in wells located in Ohio and Pennsylvania. The pre-treatment pump-in tests were designed to pump several thousand gallons of chemically treated fresh water at multiple pump rates. Upon pump shutdown at the end of this "mini-frac", the wellhead pressure decline was monitored for an extended time period. Using a commercially available computer software program, the pump rate vs. pressure data and the pressure decline data were analyzed. Pressure decline analysis incorporated a Horner plot for reservoir pressure and permeability along with regression analyses including the Nolte G Function to identify normal leak-off or pressure dependent leak-off and fracture height recession.
Subsequent to the above analyses, hydraulic fracturing treatments were performed on the wells. The treatment designs were tailored to each individual well incorporating the information obtained from the mini fracs about reservoir properties and hydraulic fracture behavior. Use of a Net Pressure Plot of the fracturing treatment was used to validate leakoff behavior identified in the mini fracs.
Enhancement Well Productivity-Investigating the Feasibility of UBD for Minimizing Formation Damage in Naturally Fractured Carbonate Reservoirs
Authors: Salimi S. , Andersen K. I. 
Published: December 2007

Abstract
This paper described the result of simulation study in naturally fractured reservoirs, when using underbalanced drilling (UBD). It has been recognized that short period of overbalanced can occur in UBD operation. The intention of this paper to investigate that nature of that damage in short overbalanced conditions during UBD operation. The model intends to study of OBD and time effect during UBD.A PC-based reservoir simulator, which free version is available 6000 cells is used to simulate overbalanced and underbalanced wellbore conditions. The model is characterized by very low matrix permeability (1 mD) and very high fracture permeability (5000 mD) and matrix pore volume. The model is formed by a number of matrix blocks (cubes) intersected by an orthogonal network of fractures. The matrix blocks permanently feed the fractures network. Both OBD and UBD wellbore condition were studied and productivity has been calculated for a various boundary conditions and reservoir parameters. Drilling operation (both UBD and OBD) is simulated in 10 days and followed by 50 days production at constant drawdown pressure. The effects of invading fluid are studied by employing production model with skin and without skin. The skin option represents the permanent damage around wellbore, where non-skin accounts the saturation changes around wellbore region that can be cured by production. For simulation of UBD case, no mud invasion is taking placed, however damage in UBD has arise as capillary forces observed liquid into the formation. The simulations study is summarized as following cases:
UBD with no influx during drilling (without reservoir inflow) OBD with continuous filtration from the wellbore to the formation (with constant over pressure of 5, 50, 500 psi) UBD with 72 minutes of over balance condition after the 7th drilling day (10 days for UBD operation). OBD with change in rock-wettability around wellbore. UBD with capillary effect.
Finally, the simulation results as productivity gained are discussed for all cases.
Numerical Simulation of the Gas Inflow During Underbalanced Drilling (UBD) and Investigation of the Impact of UBD on Longtime Well Productivity
Authors: Friedel Torsten , Voigt Hans-Dieter 
Published: December 2007

Abstract
UBD is defined as a drilling operation where the pressure of the circulating drilling fluid is lower than the pore pressure of the target formation of interest. The most widely recognised benefit of underbalanced drilling is the reduction of formation damage, in terms of minimising the drilling fluid leak-off and fines migration into the formation.
The main targets of this paper are to present the development of a methodology to simulate the gas inflow during UBD processes. The prediction of the inflow during the drilling process is important in order to maintain continuous UBD conditions. Therefore, a multi-phase UBD simulation tool is introduced. The model incorporates discrete consideration of the well with proper, time varying UBD boundary conditions, i.e., pressure and saturation. Capillary forces, which facilitate countercurrent imbibition, are taken into account. The simulation model is applied for a detailed investigation on the impact of UBD on the productivity of gas wells. Reservoir permeability, penetration rate, thickness of the formation as well as the underbalanced conditions are subjects of a sensitivity analysis. The main emphasis is placed on the derivation of the relation between productivity and the multi¬phase flow characteristics of the reservoir rock. The process of countercurrent imbibition is analysed.
Technical contributions in this paper include the presentation of a novel UBD reservoir simulation model utilising special boundary conditions. The framework of conventional reservoir modelling using, e.g., an existing geomodel of the reservoir, can still be reverted to. The flexibility of the technical realisation is illustrated by means of a UBD simulation for a horizontal well utilising unstructured grids.
Changing the Value Equation for Underbalanced Drilling
Authors: Davidson I. , Medeiros R. , Reitsma D. , Selby B. 
Published: December 2007

Abstract
The value of underbalanced drilling (UBD) and completion technology lies in several distinct areas. These include improvement in drilling performance by, for example, reducing losses or differential sticking, or increasing rate of penetration or even depletion of troublesome high-pressure zonesi. UBD is also used to improve production rates and increase ultimate recovery. In these cases, UBD has been applied to avoid formation impairment and thus to enhance well productivity. Recently, some operators have recognized that value can also be created through gathering and interpreting reservoir data while drilling underbalanced. This information is used to improve reservoir knowledge and consequently enhance reservoir management.
In low-cost drilling environments, such as land operations in the Middle East and USA, UBD drilling-enabling savings are often marginal and the cost of UBD operations becomes a blocker for wider implementation. The extra cost of UBD acts to discourage a company from fully evaluating the technology's capabilitiesii, even following technically successful trials. In addition, historically the Well Engineering community has championed UBD programs often with scant involvement from the subsurface Petroleum Engineering (PE) disciplines.
Petroleum Development Oman (PDO) operates in such a low-cost drilling environment. PDO commenced UBD campaigns in 2002 with the primary goal of enhancing production and has succeeded in sustaining UBD operations by making significant progress both in reducing costs and increasing the value of information derived from UBD to the Petroleum Engineering organization. This has created the opportunity to more fully evaluate the technical and economic benefits that UBD can deliver and the possibility to deliver cost-neutral UBD wells.
This paper describes some of the challenges faced when initially introducing UBD and the step-by-step approach followed by PDO in Oman and Shell Exploration & Production Co. (SEPCo) in the USA to widen its implementation to other fields. The paper underlines the need for integrated well engineering and petroleum engineering teams in UBD and confirms the pivotal role of sub-surface engineers in interpreting and using the additional and complementary reservoir data that becomes available during UBD. The paper also analyses more closely the actual cost of UBD and provides a balanced perspective on the longer-term UBD value equation.
Underbalanced Drilling in Canada: Tracking the Long-Term Performance of Underbalanced Drilling Projects in Canada
Authors: Kimery Dave , McCaffrey Matt 
Published: December 2007

Abstract
The development of underbalanced drilling (UBD) for production enhancement has advanced significantly since the advent of this technology in the early 1990s. The basis for the initial judgment as to the success of a UBD campaign was usually limited by the information that was available at the time of project completion: project execution success and initial production rates. However, the full scope of the effect of UBD on the overall economic success of a project remains unknown for many cases. While several underbalanced field developments have sufficient production history, drilling records, and cost data available for analysis, to date the body of published literature lacks thorough, long-term case histories.
This paper addresses this scarcity by analyzing several UBD projects in the Western Canadian Sedimentary Basin. The discussion includes a comparison of UBD and completed wells with the offsetting conventional producers in the same reservoir. Comparative analysis using industry-standard decline analysis and economic techniques yield technical and economic insight. To provide a balanced picture of the economic benefits that UBD can bring, both successful and unsuccessful projects are examined. The unsuccessful cases are analyzed to determine the reasons for underperformance, whether they fall into the categories of poor candidate selection or sub-optimal execution.
Understanding the magnitude and the driving factors behind the success and failure of UBD projects is critical to the growth and acceptance of the technology. This paper attempts to assist in that understanding and provide a benchmark for thorough comparisons of UBD case histories for the future.
Hydraulic Optimization of Foam Drilling For Maximum Drilling Rate
Authors: Kuru E. , Okunsebor O. M. , Li Y. 
Published: December 2007

ABSTRACT
The theory of hydraulic optimization of drilling with conventional (incompressible) drilling fluids is well known and has been widely practiced in the industry.
Classical theory of hydraulics optimization for maximum drilling rate calls for either the use of empirical correlations or the use of optimization theory to maximize some arbitrary objective functions such as maximum bit hydraulic horsepower or jet impact force.
Concept of hydraulic optimization for maximum drilling rate when drilling with foam, however, is not well investigated. Compressible nature of the foam makes the use of conventional optimization theory difficult.
A transient-mechanistic model of cuttings transport with foam has been developed and numerically solved recently. In this study, the new model has been used to re-visit classical theory of hydraulic optimization (i.e. maximum bit hydraulic horsepower/jet impact force criteria).
A new methodology has been suggested to determine optimum gas/liquid injection rates for maximizing drilling rate when drilling with foam while keeping the bottom hole pressure minimum.
The new method can be easily used in the field to determine best combination of gas/liquid injection rates and total bit flow area (i.e. jet nozzle sizes) such that maximum drilling rate is achieved.
Optimal Production Management in Unconsolidated Mature Sandstone Environment
Authors: Mufarji S. S. 
Published: December 2007

Abstract

Proposal
In matured unconsolidated clastic hydrocarbon formations there are several factors which contribute to production declines. One of the major factors that significantly impairs inflow into the welbore is solid fines particles which if not managed appropriately can jeopardise hydrocarbon productivity hence prevent maximum/plateau production maintenance.
This paper, presents a new and unique technique which incorporates a combination of a CFD and 3D reservoir simulation approaches to study conditions leading towards pore blocking, characteristics of the damage. Based on the analyses results, optimization suggestions are given. This approach eliminates today's core flood limitations which keep us away from being capable of reducing or avoiding pore plugging damage. The limitations include: inability to inject hydrocarbon gas in a multiphase laboratory test, non-representative nature of core sample size, sample conditions being different from reservoir condition, the questionable applicability of scaling up to field extent and so forth. Hence based on these limitations, there is a need for better pore blocking characterization techniques in risk assessments.
Results suggest that in high permeability sand, the finer the grain size (10 -100microns) the lesser the pressure decline rate. On the other hand, when 150 - 200 microns fines were simulated, the decline in pressure was comparatively more. The sensitivity of grain size in tighter formation is less compared to that found in more permeable formations as in the letter, higher magnitudes of permeability decline were revealed in which case a shallow invasion mechanism was likely. Unlike the grain size influence to pressure drop and permeability decline, the simulated fines concentration ranging from 20% to 50% by volume did not have significant impact. As far as water cut sensitivity is concerned, significant difference in permeability drop was observed between 0% and 10% water cut at fixed fines concentration.