bluuebunny/crossref_metadata_2025 huggingface dataset:
Novel Perforating System Used in North Sea Results in Improved Perforation for Sand Management Strategy
Authors: Hillestad Eivind , Skillingstad Paal , Folse Kent , Hjorteland Oyvind , Hauge Janne
Published: December 2007

When performing hydraulic fracturing treatments, the completion community widely recognizes that if the perforations can be oriented to the maximum principle stress plane and the shot density can be maximized accordingly, the success of the fracture treatment will be much greater. These benefits result from the lower breakdown pressure and the minimal tortuosity effects experienced during the process when the above conditions are met. Also, if the perforations are oriented in the maximum principle stress plane for a naturally completed, cased, and perforated well, the resulting perforation tunnels will usually be more stable than other perforations that are placed away from this preferred stress plane.

In natural completion scenarios, oriented perforating becomes especially important if 1) the formation integrity is questioned, and 2) sustained production without the mobilization of sand that could impact production is challenged. Normally, when faced with this dilemma, operators have automatically defaulted to a conventional sand-control treatment to ensure that production is not interrupted and that costly well interventions to clean out wellbore sand accumulation will not be required. While traditional sand control methods; i.e., installation of screens, proppants, and completion fluids used in the completion, are capable of controlling unwanted sand production; significant productivity penalties are often experienced with their use.

Now, there is another viable sand-control option that can be considered by the industry. If the completion is a candidate for sand management, a gravity-force-oriented perforating strategy, which will eliminate traditional sand control treatments, can be planned. Since the system relies on gravity for proper orientation, the most important consideration for using this concept is that the wellbore under consideration must have a minimum deviation of 25 degrees to orient to maximum principle stress or the overburden gradient.

The new perforating system was used in a North-Sea field and resulted in a 37,600 BOPD sand-free production rate. The new gun system can be conveyed on wireline or coiled tubing and can also be used in conventional tubing-conveyed perforating (TCP) applications.
One-Trip Multizone Frac Packs in Bohai Bay - A Case Study in Efficient Operations
Authors: Vickery Harold , Baker Brad , Scott Randy , Black Dennis , Brown Pat
Published: December 2007

During the recent development of the Zhao Dong field in Bohai Bay, a One-Trip Multizone Sand Control System was combined with frac pack treatments for efficient completions in a series of stacked pay sands. These technologies were used to complete a total of 32 zones (28 frac packs and 4 circulating gravel packs) in eleven wells, in record time. This paper examines the factors that contributed to the success of these operations.

The One-Trip Multizone Sand Control system allowed pumping operations on each well to proceed with little or no interruption. While frac fluids were being prepared between pumping each zone, downhole sand-control equipment was repositioned and ready for the next frac pack. This allowed all of the frac packs on each well to be done in a few hours instead of days typical of this type of completion.

For the majority of the zones that were pumped, a mini-frac analysis was performed prior to redesigning and pumping the main frac job. The One-Trip Multizone tools allow live annulus data to be collected for a measure of the bottom hole treating pressure while the mini-frac is being pumped. However, once pumping has stopped on the mini-frac, pressure from the annulus does not allow actual monitoring of the pressure decline on the formation. The solution to this problem is discussed.

Due to rig space limitations, none of the frac equipment could be placed on the platform. It was placed on floating vessels in order to pump the frac packs. There was also shallow water depth around the platform. To help solve these logistical problems, two vessels were required. A fluids barge was refitted with the proper tankage and centrifugal pumps for moving drilling and completions fluids to the rig site. The other vessel was used as a platform for the pumping equipment, with all fluids mixed and stored on the fluids barge. This combination allowed pumping operations in preparation for each frac pack to proceed smoothly, without interfering with other rig operations.

Lessons learned about proper zone spacing, pre-job planning, and well preparations are also discussed.
Oil and Gas Energy and the US Economy
Authors: Skov Arlie M.
Published: December 2007

The US economy and use of oil and gas energy grew rapidly together for many decades. This seemingly symbiotic relationship ended when nominal oil prices jumped eight-fold (1973–81), triggering the worst US recession since World War II. Subsequent recessions have followed every significant, if generally short-term, oil price hike. Economic growth has happened when oil prices were either relatively low or stable. The oil price jump of the '70s also correlates with a nine-fold increase in natural gas price, a four-fold increase in coal price, a three-fold increase in cost of electricity, and a significant drop in energy demand. These events provide bases for better understanding of the relationship between energy use and economic growth.

Although the conventional measure of "economic growth" is percentage change in GDP, other criteria - inflation, interest rates, unemployment, relative strength of currency, imports and exports, corporate profitability, etc. - are also important and are reviewed since the "economy" is complex and multidimensional.

Sudden energy price changes provide measures of elasticity (effect of price on supply and demand) essential for better understanding and predictions of energy use and economic growth. Knowledge of elasticity is vital for forecasting, planning and policy development.

Inevitable constraints imposed by changing environmental and political considerations impact both future US energy use and economic activity not unlike actual physical shortages. Possible means for alleviating adverse impacts, and for transitioning from oil and gas to other energy sources must be explored. Importantly, the potentially significant impacts of both anticipated and unforeseen technological breakthroughs must be evaluated and incorporated into any meaningful view of the future.

Introduction: A History of US Oil and Gas

Colonel Edwin L. Drake discovered oil in the US in 1859. Five years later, production was 6000 BOPD, and oil's value for illumination spurred growth to 83,000 BOPD by 1882, at an annual rate of 15%. Subsequently, Appalachian Basin growth faltered; by 1918 it accounted for only 8% of US total of 1 million BOPD, as large new fields were found in California, Texas, and Oklahoma. Between 1900 and 1920, oil and gas consumption in the US grew at 11% and 9% respectively, as use of automobiles with internal combustion engines proliferated1.

Table 1 illustrates subsequent consumption as MBOPD and MMCFPD and as quadrillion BTU's (or quads), and also oil and gas energy as a percent of total US energy use2,3. (One quad is 172 million bbls or nearly 500 MBOPD, and also equates to 0.9 TCF or about 2.5 BCFPD).

Significant changes either in energy use or the economy are illustrated. The period 1920–29 is the post WW I boom, 1929–40 is the Great Depression, 1940–45 is WW II, 1945 to 1970 covers the post WW II boom, 1970–83 is the period of oil price increase and uncertainty triggered by the Arab Oil Embargo and the Iran-Iraq War, and 1983 to 2003 is the post price shock period beginning at the low point in US energy consumption in 1983.
Innovative Expandable Liner-Hanger Application Saves Time on Pinedale Anticline Drilling Operations: Two Case Studies
Authors: Nida Ron , Meijs Raymund , Reed Shawn , Arnold Bill
Published: December 2007

Across the globe, liner casing strings are sometimes required. The installation process leads to a variety of challenges from both cementing and tools aspects. Among the challenges are proper isolation of both formation and liner lap, placement of the liner in the desired position, and associated operational time required to return to drilling operations.

The use of the expandable liner hanger provides a way to better address each of these issues. Well conditions on the southeast Pinedale Anticline require drilling liners to be set at specific casing points to allow all of the productive strata to be penetrated. Because the strata behind the liner string is also gas productive and completed with multiple hydraulic-fracture stimulation treatments, proper isolation behind the liner is critical right up to the lap of the liner across the intermediate casing shoe. The mechanics of the expandable hanger system eliminate the potential for a premature set. The normal operating procedures require testing conventional liner tops and "dressing" cement left on top of the liner. These operations can require substantial investments of time and money. The new technology simplifies these processes and reduces the time required to return to drilling operations.

The cases investigated in this paper have similar wellbore conditions, but were cemented using different methodologies. The first was isolated using a foamed-cementing process, while the second used conventional slurries. Both cases exhibited good isolation, good bond performance across formation and lap, and a faster, more simplified operation compared to conventional mechanical liner-hanger applications.
Geomechanics-Based Automatic Well-Planning Software Provides Drilling Decision Support to Asset Teams
Authors: Givens K. , Luppens C. , Menon S. , Ritchie G. , Veeningen D.
Published: December 2007

Minimizing well costs and associated risks requires well construction planning techniques that account for the interdependencies involved in the well design. The inherent difficulty is that most design processes and systems exist as independent tools used for individual tasks by the various disciplines involved in the planning process. In an environment in which increasingly difficult wells of higher value are being drilled with fewer resources, there is now, more than ever, a need for a rapid well-planning, cost- and risk-assessment tool.

This paper presents an automated process for integrating the well construction planning workflow and accounting for process interdependencies. The process is based on a prototype drilling simulator developed with a consortium of major oil companies in 1999–2000 that first demonstrated the technical feasibility of such a tool. The highly interactive process is encompassed in a software system that

allows well construction practices to be tightly linked to geological and geomechanical models enables asset teams to plan realistic well trajectories by automatically generating cost estimates with a risk assessment, thereby allowing quick screening and economic evaluation of prospects enables asset teams to quantify the value of additional information by providing insight into the business impact of project uncertainties reduces the time required for drilling engineers to assess risks and create probabilistic time and cost estimates faithful to an engineered well design permits drilling engineers to immediately assess the business impact and associated risks of applying new technologies, new procedures, or different approaches to a well design.

Discussion of these points and field examples illustrate the application of the workflow and verify the value, speed, and accuracy of this integrated well planning and decision-support tool.
Modern Carbon/Oxygen Logging Methodologies: Comparing Hydrocarbon Saturation Determination Techniques
Authors: Eyvazzadeh Ramsin Y. , Kelder Oscar , Hajari A. A. , Ma Shouxiang , Behair Abdallah M.
Published: December 2007

Recent advances in Carbon/Oxygen (C/O) logging technology have provided measurements that have become more quantitatively robust in reservoir monitoring projects, especially in mixed salinity environments. Enhancements in tool design, characterization and interpretation algorithms have contributed to increases in precision and accuracy of fluid saturation measurements.

Even though these innovations have led to major improvements, fluid saturation profiles provided by different service companies are often varied. The variations are due to differences in tool designs and interpretation methodologies and thus, a unique solution is not always provided. The inconsistencies in answers are generally not understood due to characterization complexities of the formation and the borehole environment including cements, casing, fluid types, etc.

As a consequence, a study was conducted in a large Middle Eastern carbonate field to evaluate and compare accuracy and precision of different types of Pulsed Neutron Spectroscopy (PNS) tools in a controlled environment. Several open-hole wells were chosen and logged with the latest types of tools under identical conditions with well defined environmental parameters, thus enabling accurate correlations between tool responses and fluid saturations. The accuracy of the results was then evaluated based on a comparison to core, production logs, pulsed neutron sigma, resistivity and fluid sample data.

This paper presents the results of the study and illustrates how differences in service company tool designs, characterizations and interpretational methodologies affect fluid saturation computations in this field. In addition, recommendations are provided on job planning and utilization of this technology in large scale reservoir monitoring projects.
A Novel Technique to Acidize Horizontal Wells with Extended Reach
Authors: Nasr-El-Din H. A. , Al-Habib N. S. , Jemmali M. , Lahmadi A. , Samuel M.
Published: December 2007

Drilling horizontal wells with extended reach is intended to maximize reservoir drainage and minimize water production due to water coning. However, an inherent problem with these wells is poor acid distribution during matrix acidizing, especially in reservoirs with high permeability streaks. This paper discusses an innovative approach to treat horizontal wells with extended reach. This new technique comprises mechanical diversion in the wellbore, and chemical diversion in carbonate formations.

Coiled tubing has been used for years to better distribute the acid in vertical and horizontal wells. However, application of coiled tubing in long horizontal wells is a function of wellbore diameter and length. Coiled tubing cannot reach the total depth of the well if there is large washout, or if the length of the openhole is greater than what the CT can reach. The maximum length that CT can reach depends on the length of the reel, diameter of the coil and wellbore geometry. To extend this length, we have used a hydraulic tractor to pull the coiled tubing to the total depth of the well. This will ensure better acid distribution over the wellbore. To enhance acid diversion in the formation, a visco-elastic surfactant-based acid system was employed.

Wells selected are horizontal that were drilled in a carbonate reservoir in the oil fields (both land and offshore) that are present in the eastern part of Saudi Arabia. The total length of the target zone for the well "A" and well "B" is 13,543 and 20,304 ft, respectively. Typical coiled tubing (1¾-inch) cannot reach the total depth in these wells (CT lockup length is 10,300 ft for well "A" and 13,200 ft for well "B").

A special hydraulic tractor was used to pull the coiled tubing to the total depth of these two wells. A visco-elastic surfactant based-acid system was utilized to remove formation damage induced by the drilling fluid (water-based mud) and enhance the permeability of the formation in the critical wellbore area. Corrosion inhibitor and other acid additives were carefully selected to maintain the integrity of well tubulars, coiled tubing and the tractor (metallic parts, O-rings and seals of the tractor). Before attempting the stimulation of the extended reach well, a water jetting method was adopted to remove near well bore damage resulting from the drilling mud cake and mud invasion. Production logging tests were conducted after drilling the well, after the water jetting treatment, and after the matrix stimulation. The productivity index of the well decreased after the water jetting treatment. However, the acid matrix treatment delivered through the CT-tractor nearly doubled the productivity index of the treated well.
Installation and Application of an Intelligent Completion in the EA Field, Offshore Nigeria
Authors: Constantine Jesse
Published: December 2007

Traditional barriers to general industry acceptance of intelligent well technology have been cost, reliability, and integrated functionality; but, over the past decade, the number of operators that have started to recognize the value potential of intelligent wells has grown. The evolution of intelligent well technology that can now address initial barriers and user perceptions is responsible for this increasing acceptance.

An offshore completion recently installed for a major operator illustrates how two essential factors—correct technology selection and development and operational excellence in planning and installation—can lead to successful deployment of an intelligent well system. This paper discusses the challenges that the project presented, the benefits delivered, and the lessons learned.
Identification and Resolution of Water Treatment Performance Issues on the 135 D Platform
Authors: Yang Chiffon , Galbrun Michel , Frankiewicz Ted
Published: December 2007

The 135 D platform is located in the Campos Basin off the coast of Brazil. The platform functions as a central processing facility, receiving degassed liquids for treatment from four remote production platforms. Dry oil is sent via pipeline to Cabiunas, while water with <20 mg/L total oil and grease (TOG) is discharged overboard. Upon startup, the ability of the systems on 135 D to clean produced water to the required TOG of <20 mg/L was limited. This paper describes the means by which the fundamental causes of the water treatment performance problems were identified and resolved. Modifications to the original process design are discussed, and the impact of those modifications on the quality of discharged produced water is presented.

The root causes that limited water treatment performance on 135 D were identified as a combination of very high variations in arriving fluid flow rates, unexpected variations in solids concentration, process recycle streams, unexpectedly small oil droplets, and sludge generated by the mixing of excess chemicals with inlet fluids.

On-platform modifications to existing process vessels and to the process itself were required to successfully treat produced water whose character varied significantly from design specifications. Since completing modifications, the platform has routinely produced water with <20 mg/L TOG at or above plant design capacity.
Production Profile Evaluation as an Element of Economic Viability and Expected Outcome
Authors: Haskett W. J.
Published: December 2007

Industry needs to move away from standard, volume based, assessment of the success case that only involves the establishment of sufficient recoverable product, within a container of sufficient size, to enable a critical volume of product to be commercialized. Volume based techniques at best, whether deterministic or parametric, serve only to calculate the mean case and as such are insufficient to provide adequate information regarding the true economic potential of an asset or any decision management capability. Frequently, an assumption is made that the recovery factor (bbls per acre foot), or the individual components that lead to the calculation of a recovery factor equivalent, provides a valid assessment of production rate. Economic analyses of prospects tend to be based on and constrained by detailed earth-models, assessments of risk and uncertainty coupled with cursory, deterministic, and biased assessments of rate and production profile. The result is a fairly good record of Chance; finding recoverable hydrocarbons, and an over-estimation of the Uncertainty; finding sufficient hydrocarbons that will produce at economic rates through time providing at least a minimally acceptable volume. This results in economic over-estimation.

We require a more rigorous, uncertainty ranged approach to rate and profile in order to provide a better assessment of the true potential and downside possibilities of exploratory and producing assets. Elements such as Initial Production Rate, Plateau Life, and Total Cumulative Production should be ranged as correlated elements to base reservoir properties such as porosity, saturation, and composition. For appraisal and development planning, the significance and extent of element correlation is assisted by links to an experimental design or other reservoir simulation process.

It is our view that this can only be accomplished via the stochastic approach. Economic outcome is sensitive to initial rate and profile, sometimes to a greater degree than volume. A stochastic approach enables assessment of viability as profile pathways, facility constrained yearly ranges, or "discounted production". This enables identification of valid minimum completion criteria, or at least illuminates risk potential, and establishes a fairer representation of the distribution of expected outcomes.
Intelligent Completions: Lessons Learned from 7 Years of Installation and Operational Experience
Authors: McLauchlan Alan , Nielsen Victoria Jackson
Published: December 2007

Since the first intelligent completion was installed in August 1997, over 200 such systems have been installed globally. The systems installed encompass a wide range of downhole and surface equipment, though some aspects are similar for all installations. This paper will address the lessons learned and best practices developed since the installation of the first system seven years ago.

Detailed project and operational planning is critical to the success of any project, but is of paramount importance to complex projects such as intelligent completions. Operational planning and execution begins before the equipment is manufactured and carries through to equipment testing, shipping, and surface checks prior to picking up the assemblies.

Installation and proper execution is critical for all projects - though specifically important in many of the intelligent completion installations which take place in applications with very high rig rates. To complement success, post-job reviews allow for lessons learned and best practices to be disseminated throughout the intelligent completion provider organization as well as the operating company.

The tangible results of this detailed planning and execution are realized as rig time savings without jeopardizing safety. Though more difficult to quantify, reliability improvements and an increase in customer satisfaction and confidence can be achieved by the incorporation of standardized, downhole components and installation equipment.
Design, Analysis, and Full-Scale Erosion Testing of a Downhole Flow Control Device for High Rate Water Injection Wells
Authors: Russell Ronnie , Barrilleaux Mark , Gai Huawen , Macrae Jonathan
Published: December 2007

There is an increased need for flow control devices that will operate at very high flow regimes in production and injection modes. The deepwater locations of these wells require that this equipment and the well casing operate reliably over the life of the well.

This paper presents the design and full-scale injection erosion flow testing of a new sliding sleeve port geometry. An improved flow port shape incorporates features contoured by Computational Fluid Dynamics (CFD) to dramatically lower erosion for high flow rates. Extensive material testing formed the basis of an erosion model used in the design and configuration of the port geometry. The erosion model and design work are compared and contrasted in a full-scale flow test. This test was run on the pumping vessel "HR Hughes" at the flow rates, sand content, and sand type expected at the reservoir.

This project demonstrates the ability of this flow control equipment to operate at downhole flow regimes higher than anything previously encountered. The full-scale testing of the sleeve port design verified aspects of the design analysis and confirmed the value of this type of testing to ensure design integrity and verify that these devices can operate reliably over the life of a given well. The flow control devices will enable producers to maximize production for a given size of tubing and expand operational flexibility.
Analyzing Well Performance in Hydraulically Fractured Gas Wells: Non-Ideal Cases
Authors: Cramer David D.
Published: December 2007

To facilitate timely solutions, practical gas-well performance analysis is based on ideal (simplifying) assumptions regarding the reservoir, completion and reliability of input data. Yet phenomena can exist in field situations that violate some of the ideal assumptions implicit within the analytic approaches. This paper investigates the impact of several known non-ideal cases on analytic solutions.
Cheap, Directional Wells Drilled Underbalanced With Coiled Tubing: An Experience in the Australian Outback
Authors: Portman Lance , Lan Nguyen , MacArthur Jim
Published: December 2007

Coiled tubing directional drilling can be an expensive operation, requiring a significant quantity of specialized equipment and personnel. This is particularly true of underbalanced drilling operations involving compressible fluids. The cost of using and mobilizing this equipment can be prohibitive.

In some circumstances, the equipment, personnel and engineering requirements can be greatly reduced, leading to a large reduction in the overall operation cost. Such savings are particularly beneficial for smaller campaigns of work in more remote locations. This paper describes many equipment and method simplifications made during a four-well underbalanced, directional drilling campaign conducted in Queensland, Australia.
Solvent / Acid Blend Provides Economic Single Step Matrix Acidizing Success for Fines and Organic Damage Removal in Sandstone Reservoirs: A Niger - Delta Case Study
Authors: Chike Uchendu , Awoleke Obadare , Linus Nwoke
Published: December 2007

The formation of petroleum residue and deposits is a recurrent problem in low API gravity or heavy oil reservoirs and reservoirs with significant pressure and temperature fluctuations. It is also a challenge in fields where recent well interventions has pushed pipe dope into the perforations resulting in severe loss of native formation permeability and productivity.

This paper discusses the application of a unique solvent acid dispersion that offers one step stimulation of reservoirs damaged with both plugging solids and organic deposits. Conventional acid systems including the numerous patented HF - HCl and organic acid blends dissolve the plugging solids and cementitious materials but cannot stimulate sandstone reservoirs damaged with organic deposits or a combination of plugging solids , fines migration and organic deposits. In fact, the formation of acid induced sludge is common.

However, this acid - solvent blend dissolves asphaltene and paraffin deposits, prevents the formation of wax crystals and removes organic residue and inorganic materials simultaneously. A special surfactant train acts synergistically with the acid blend, prevents acid induced sludge and leaves the rock surfaces strongly water wet. Overall treatment efficiency was increased especially in gravel packed intervals by using a rotating jetting tool although success has also been recorded using the bullheading option. Recent experience has shown the acid blend is particularly suitable as a spearhead for injection wells. Optimum solvent loading for effective stimulation is between (10 - 20) percent depending on reservoir temperature, suspected damage mechanism and the severity of relative permeability effects.

Unique experience detailing standard lab / field practice and exceptional results for several wells in the Niger Delta is the focus of this paper. Wells treated with this unique blend either as spearhead for other specialty acid systems or as a one step treatment show dramatic and sustained productivity increases of between (50 - 150) % relative to initial well data. The system has been proven to be successful in most types of completion architecture. Key technical and economic performance indicators including skin factors, production rates, specific productivity indices, payback time and treatment cost indicate this low viscosity acid blend is both technically proficient and cost effective.
Application of After-Closure Analysis Techniques to Determine Permeability in Tight Formation Gas Reservoirs
Authors: Britt Larry K. , Jones Jack R. , Heidt J. Harmon , Adil Imtiaz , Kelly Patrick , Sparkes Dan , Collin Bruce
Published: December 2007

The primary objective of hydraulic fracturing is to create a propped fracture with sufficient conductivity and length to maximize or at least optimize well performance. In permeable reservoirs where transient flow is short lived, a fracture with a Dimensionless Fracture Capacity, FCD, of 2 is required to meet the design objective. In low permeability formations where transient flow can be extensive and where fracture fluid cleanup requires additional conductivity, an FCD in excess of 10 is desired. As a result, reservoir permeability becomes/is a key fracture design and analysis parameter. In higher permeability applications, permeability is determined simply, inexpensively, and routinely through conventional well testing techniques. Conventional well testing in tight formation gas reservoirs has not been proven as effective, can be expensive (cost of lengthy tests and production deferment), and is quite simply not routinely utilized. These reservoirs are often non productive without fracture stimulation and post fracture stimulation testing requires extensive shut-in time as the time to pseudo radial flow is proportional to the square of the fracture half-length. As a result, the development and routine use of any technique to determine permeability in these tight formation gas reservoirs has great value.

In addition, without adequate well testing techniques and capabilities in tight gas reservoirs, the engineer is left with the use of log derived values of permeability which can often overstate in-situ permeability by factors of five to ten. Determination of in-situ permeability not only aids the well completion and stimulation but can be used to calibrate the log and core derived estimates of permeability improving performance predictions and field development. Prior papers have developed the use of After Closure Analysis techniques in permeable reservoirs, this paper will show the application of this technique to several tight gas formations in North America.

This paper will demonstrate the following: The effective application of this technique in tight gas formations in the U.S. and Canada,Develop a cost effective and operationally simple means of collecting and analyzing the data,Compare and contrast the technique to other methods of determining permeability in tight formation gas reservoirs, such as impulse, Perforation Inflow Diagnostic (PID), Closed Chamber Drill-Stem Tests (CCDST), post-frac build-up, production decline analysis, Modular Dynamic Formation Tester (MDT).Show the application and value of calibrating log and core-derived permeability with in-situ measurements for improved well performance predictions.
A Method to Analyze and Plan for Political Uncertainties for Use in Project Evaluation and Management
Authors: Craig D. A.
Published: December 2007

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

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 >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

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

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

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

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

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

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.