bluuebunny/crossref_metadata_2025 huggingface dataset:
Developing Tight Gas Sand Adviser for Completion and Stimulation in Tight Gas Sand Reservoirs Worldwide
Authors: Holditch S. A. , Bogatchev K. Y.
Published: June 2008

As the demand for energy worldwide increases, the oil and gas industry will need to increase recovery from unconventional gas reservoirs (UGR). To economically produce UGRs, one must have adequate product price and one must use the most current technology. Tight Gas Sands (TGS) contribute three quarters to the total U.S. gas production from UGRs. TGS reservoirs require stimulation as a part of the completion, so improvement of completion practices is very important. We did a thorough literature review to extract knowledge and experience about completion and stimulation technologies used in TGS reservoirs. We developed the principal design and two modules of a computer program called Tight Gas Sand Advisor (TGS Advisor), which can be used to assist engineers in making decisions while completing and stimulating TGS reservoirs. The modules include Perforation Selection and Proppant Selection. Based on input well/reservoir parameters these subroutines provide unambiguous recommendations concerning which perforation strategy(s) and what proppant(s) are applicable for a given well. The most crucial parameters from completion best-practices analyses and consultations with experts are built into TGS Advisor's logic, which mimics human expert's decision-making process. TGS Advisor's recommended procedures for successful completions will facilitate TGS development and improve economical performance of TGS reservoirs.
Initial Surveillance in the Cannonball Field: Design, Implementation, and Interpretation
Authors: Jemmott Susan T. , Baksh Kirk , Jones Jack
Published: June 2008

The Cannonball West gas and condensate field is located in the Columbus basin, 35–40 miles off the southeast coast of Trinidad in water depths of 240 feet. It is comprised of a single reservoir unit, the TP65 sand, situated at 12,334 ft. true vertical depth subsea. This field was discovered in 2002 by the exploration well, Ironhorse-1 ST1, which penetrated the reservoir down dip of the Sparrow fault block, and just south of the adjacent Red Mango accumulation. The sand was initially over pressured at 6,400 psi; with a temperature of 220 °F. The volumetric estimate of gas in place was 1 trillion cubic feet of gas.

This reservoir was developed with three vertical wells, completed as open-hole gravel-packs with 7 5/8" production strings. The well design was based on parameters estimated from the discovery well and a target per-well production rate of 280 million standard cubic feet of gas. Each well was successfully instrumented with permanent downhole pressure and temperature sensors as well as wellhead, casing, pre-and post-choke pressure and temperature sensors, well-by-well ‘wet’ gas rate meters and well flowline acoustic sand detectors. All of this data is available real-time and is continuous.

Field startup followed in early 2006. Hydrocarbons are produced via a dedicated normally unmanned platform. This platform is Trinidad's first locally fabricated platform, and is a 9-slot installation with a production capacity of 1 billion cubic feet per day. Fluids flow through a 26″ subsea pipeline to the nearby Cassia B central hub for processing prior to sale to local industry and LNG facilities. The operation is managed by bp Trinidad and Tobago, plc. (bpTT).

To quantify completion efficiency, well-by-well drainage areas and connected volumes, and to garner data to help set safe nominally sand-free operating limits, a baseline surveillance program was designed prior to initial production. The purpose of this paper is to detail the design, implementation and interpretation of this baseline testing program. In particular, we show how the design reconciled the need for extended, high quality pressure buildup data with the need to maintain a reliable gas supply, one of bpTT's core reputation values. We also delineate how the test design incorporated multiple datasets allowing redundant, independent calculation of key parameters. Finally, we show how individual well completion condition, drainage area and connected volume were quantified and how the combined results fit within and tie to the seismic interpretation. Implications for inter-well connectivity along with future operations and drilling are discussed in the closing section of the paper.
The Optimal Hydraulic Fracture Geometry Under Non-Darcy Flow Effects
Authors: Zeng Fanhua , Zhao Gang
Published: June 2008

The presence of non-Darcy flow in the hydraulic fracture significantly reduces the effective conductivity of the fracture, and hence adversely affects the productivity of a hydraulically fractured gas well. It has been disclosed that under non-Darcy flow effect a shorter and wider fracture geometry provides better productivity than a longer and narrower fracture; on the contrary, for Darcy flow a longer and narrower fracture yields higher productivity.

This work is to optimize hydraulic fracture geometry under non-Darcy flow effects in hydraulic fractured well in order to obtain maximum well productivity and economic benefit. A rigorous mathematical model is established to describe transient non-Darcy flow in hydraulic fractures and coupled with Darcy fluid flow in the reservoir. A semi-analytical method is further presented to solve this model. Then, on the basis of the simulation results, the fracture geometry is optimized for two goals. The first goal is to obtain the maximum well productivity under a given fracture volume. On the basis of theoretical analysis and hundreds of simulation results, a semi-experiential correlation is developed to calculate the optimal fracture length. The equation generated suggests that the optimal fracture length is proportional to (1/β)1/3, which means that if non-Darcy flow increases 8 times, the optimal fracture length would have been decreased by half. The optimal fracture length is also a function of fracture volume, formation permeability, fluid viscosity and density, net pay thickness and flow rate. The second goal is to achieve the maximum economic profit through optimizing the fracture volume, since larger fracture volume generally brings larger productivity, and also leads to higher hydraulic fracturing cost. Analyses show that the severer the non-Darcy flow, the smaller the optimal fracture volume required. Therefore, fracture geometry optimization should involve two stages: fracture volume optimization and fracture length optimization.

The proposed optimal fracture length equation had been applied to analyze several cases from the literature. The results show that the design criterion to eliminate the non-Darcy flow effects will cause such a short fracture length that the well productivity would be reduced significantly. Therefore, it is suggested that well productivity and economical benefit should be systematically considered being the design criterion in hydraulic fracturing stimulation.
The Study and Application of Low-Damage and Massive Hydraulic Fracturing Technique in Tight Gas Formations With High Temperature and High Pressure
Authors: Qun Lei , Jiang Tingxue , Yun Xu , Ding Yunhong , Lu Yongjun , Bo Cai , Shu Yuhua , Duan Yaoyao
Published: June 2008

There are a lot of tight gas formations with high temperature and high pressure in the south of Songliao basin in northeast China. However, it is very difficult to conduct successful fracturing treatment jobs as results of deep wells (more than 4200 m), high temperature (more than 150°C) and high pressure (more than 60 MPa), etc. Therefore, a systematic studies have been performed to overcome above mentioned difficulties, and the highlights are: 1) Fine formation evaluations prior to fracturing treatment; 2) A new finely processed Guar is developed, and the concentration is only 0.45% for the temperature of 150°C, and residue content 125 mg/l correspondingly, both are much less than those of commonly used Guar system; 3) Smaller sized proppant with high strength is optimized, sometimes, more than two proppant types or sizes is also chosen comprehensively; 4) Fuzzy undetermined analysis of economic benefit is performed to optimize propped fracture length and conductivity, in which the Monte-Carlo method is utilized; 5) Many fracturing treatment parameters are changed and combined optimizedly such as proppant's type and size, fracturing fluid's type, cross linked ratio, concentration of based fluid, concentration of gel breaking agent, and pumping rate as well, which makes it not only to ensure the successful treatment but also to minimize fracture damage so as to maximize fracturing treatment potential; 6) Spiral mode of proppant pumping schedule is put forward in order to prevent earlier screen-out; 7) A new forced fracture closure technique is utilized to improve propped profile in the case of multiple payzones. Above low damage and massive fracturing technique was put in to filed applications in 6 gas wells, all treatments were completely successful with the maximal proppant weight being as high as 165,000 kg, while in the past, there were many treatment failures. And the highest post-fracturing rate 70,000 m3/d, which is satisfied as expected. So, it has a great significance not only in improving fracturing treatment effect in above mentioned gas formations but also in perfecting low damage and massive hydraulic fracturing technique as well.
Dewpoint Pressure Model for Gas Condensate Reservoirs Based on Genetic Programming
Authors: Shokir Eissa M. El-M.
Published: June 2008

Successful prediction of the future performance of condensate reservoirs requires accurate values of dew point pressures of the interesting reservoirs. Although the dew point pressure can be determined experimentally from collected laboratory samples, these measurements are frequently not available. In these cases, fluid reservoir properties are determined with the use of empirical correlations or determined iteratively using an equation of state (EOS).

The objective of this paper is to present an application of genetic programming (GP)-Orthogonal Least Squares algorithm (OLS) to generate linear-in-parameters dew point pressure model represented by tree structures. The GP-OLS based gas condensate reservoir dew point pressure model was generated as a function of reservoir fluid composition (in terms of mol fractions of methane through heptanes-plus, nitrogen, carbon dioxide, and hydrogen sulphide, and the molecular weight of the heptanes-plus fraction), and reservoir temperature. The new model was developed using experimentally measurements of 245 gas condensate systems covering a wide range of gas properties and reservoir temperatures. One hundred-thirty five gas condensate systems that not introduced in building the new model were used to test and validate it against the other early published correlations. The validity test shows that the new model is more accurate than the other tested correlations, whereas the new model has the lowest average absolute relative error. Therefore, the new model can be considered an alternative method to estimate the dew point pressure when the experimentally measurement is not available.
Gas Well Optimization: A Surface Roughness Approach
Authors: Farshad F. F. , Rieke H. H.
Published: June 2008

Gas Well Optimization implementations in the petroleum industry is taking on an important challenge as our industry moves into new frontier production areas such as deep water development and re-invigorated improved recovery operations in producing and abandon reservoirs. Today, high oil and natural gas prices dominate the energy fuels market, forcing companies to look into technologies that will efficiently produce and transport oil and gas to their customers. Attention to pipe performance in the recent past relied on conventional design values such as pipe strength parameters. The introduction of probabilistic evaluation of Oil Country Tubular Goods (OGCT) in the 1990s has provided a more focused approach to tubular strength design. Presently, strength optimization is not the only most cost-effective design concern. Current piping design is more concerned with the ability of pipes to transport fluids at a substantial reduced drag. This resistance to flow is caused mainly by inherent surface roughness due to pipe fabrication and/or corrosion products. A significant outcome in the reduction of surface roughness in pipes can help in optimizing deliverability of the production system. An application of a successful flow assurance program is the result of engineering and scientific knowledge integration, technological know-how, staff proficiency, and operability.

Our results are based on impact of surface roughness reduction as a result of utilizing internally coated pipes and newly developed alloys used in OCTG. Our approach to estimate the average surface roughness for modern pipes is based on using our new relative roughness tables and a graph (Farshad et al., 2006) in computer models showed a decrease in the pressure drop with an accompanying increase in the fluid throughput. The presenting case histories using the newly developed surface roughness values for internally coated and newly developed alloyed piping are discussed.

Computer models were used to apply the newly developed surface roughness graph and its application to simulate production results for two producing gas wells. Case histories are presented for the two gas wells located offshore Louisiana. TOPS and PIPEPHASE® 7.2 computer models were used to investigate the impact of changing the internal surface roughness of the tubing on production-performance (Simsci, 1999). Modeling results from one of the two Gulf of Mexico gas wells using different well production scenarios showed that gas flow rates increased by 24.5% when substituting a proprietary modified epoxy coated plastic tubing, and a 14.06% increase in flow rates for proprietary liquid phenolic coated production tubing over traditional bare carbon steel pipe. It is apparent that these results justify departure from existing pipe design practices.
Controlling Environmental Noise From Coalbed Methane Operations
Authors: DeGagne David C. , Burke Donald
Published: June 2008

A significant challenge for Coal Bed Methane producers is dealing with the impacts of high density development needed to effectively recover the natural gas resource. One such concern is the need to meet regulatory requirements for environmental noise as stated in the Energy Resources Conservation Board (ERCB) Directive 038: Noise Control (ERCB Directive 038) and Colorado Oil and Gas Conservation Commission (COGC) Aesthetic& Noise Control Regulations, Series 800 (COGCC Noise Regulations). Anyone who has ever been involved in the process of complying with regulatory noise standards will agree that it is a complex and challenging task. Some regulated companies struggle through this process often dealing with unfamiliar considerations such as trying to predict facility noise levels before it is even built, or gambling on a best guess as to what is the right, least expensive amount of noise mitigation needed to meet regulatory requirements for environmental and occupational noise. Even the best of intentioned operators fail to hit the mark, sometimes by wide margins and end up with a situation that is potentially worse than when they started. No company wants to go through a process where in the end a lot of time, resources, and public confidence have been lost not to mention now being in a regulatory non-compliant status.

This paper will elucidate valuable lessons & experience learned and case histories for the successful approach to noise solutions accepted by regulatory agencies and industry clients. In addition to discussing the complexities of acoustical engineering practices this presentation will also cover the most significant points of ERCB Directive 038 and COGCC Noise Regulations.
Applicability of the Arps Rate-Time Relationships for Evaluating Decline Behavior and Ultimate Gas Recovery of Coalbed Methane Wells
Authors: Rushing J. A. , Perego A. D. , Blasingame T. A.
Published: June 2008

This paper presents results of a simulation study designed to evaluate the applicability of Arps’ [1945] decline curve methodology for assessing reserves in coalbed methane reservoirs. We simulated various coal properties and well/operational conditions to determine their impact on the production decline behavior as quantified by the Arps decline curve exponent, b. We then evaluated the simulated production with Arps’ rate-time equations at specific time periods during the well's production decline period and compared estimated reserves to the "true" value (defined in this paper as the 30-year cumulative production volume). To satisfy requirements for using Arps’ models, all simulations were conducted using a constant bottomhole flowing pressure condition in the wellbore.

The significant results from our study include:

All of the computed values of the long-term decline exponents were within the limits originally defined by Arps, i.e., 0.0 ≤ b ≤ 1.0. Agreement between Arps’ recommended b-exponent range and our results using simulated performance data also suggests that, if applied under the correct conditions, the Arps rate-time models are appropriate for assessing reserves in coalbed methane reservoirs; The Arps b-exponents were not constant during the production decline period. For many simulated cases, the early decline behavior (within a few years after reaching the peak production rate) appeared to have exponential decline but eventually became more hyperbolic later in the well's life. Use of Arps’ exponential model early in the production history in those wells with long-term hyperbolic decline behavior tended to underestimate gas reserves; The largest reserve estimate errors typically occurred during the first few years after reaching the peak production rate and during the initial production decline period. For those wells exhibiting long-term hyperbolic behavior, the initial reserve estimate errors underestimated reserves by as much as 20 to 30 percent; Heterogeneities in coal properties cause the production declines to deviate from exponential to hyperbolic. Properties having the largest impact on the production decline behavior include the shape of the adsorption isotherm, cleat permeability anisotropies, the shape of cleat gas-water relative permeability curves, stress-dependent cleat permeability and porosity, and layered coal seams with differences in initial reservoir pressures; We also observed a strong influence of well flowing pressure conditions as modeled with a bottomhole flowing pressure constraint. For all other properties and conditions being equal, wells with lower bottomhole flowing pressures exhibited more long-term hyperbolic behavior as defined by higher Arps b-exponents.
A New Approach to Improve the Phase Behavior of Supercritical Hydrocarbons Using PR EOS
Authors: Faradonbeh M. Rabiei , Bahramian A. , Masoudi R.
Published: June 2008

Reliable predictions in compositional reservoir simulators require a proper equation of state to describe accurately the phase behavior of fluids both in sub/super-critical regions. In miscible processes such as CO2 and lean gas injections, the injected fluid is usually at it's super-critical temperature, and therefore the current forms of EOS might not be suitable, since their temperature-dependency term (Alpha Function) have been obtained using experimental data of pure components at sub-critical regions. The same problem exists for compositional simulation of gas condensate reservoirs in which the major components are above critical temperature.

A new alpha function was developed using sound velocity data of pure components at their super-critical temperatures, since sound data can be measured accurately at large temperature range. Sound velocity can be thermodynamically related to the EOS parameters. An appropriate form of alpha function has been hence obtained for each component at super-critical temperatures.

In this work, the sound velocity experimental data of pure methane, ethane, propane and carbon dioxide has been used to generate a new form of alpha function at super-critical temperatures using PR EOS. The new function was then tested and validated against different experimental data from binary, ternary and multi-component systems and was found satisfactory in improving the prediction results.

By adapting the new methodology and developing the new alpha function for other components at super-critical region, it diminishes the need for temperature-dependent BIPs and also decreases the task for tuning of a given EOS against experimental data.
Estimating Water Production Behavior from Edgewater Drive in a Monocline Reservoir
Authors: Ayeni Kolawole , Wattenbarger R. A. , Maggard J. B.
Published: June 2008

It is often important to predict water production performance of oil wells early in, or maybe before, their production life. Some of the challenges encountered include difficulty in predicting water breakthrough time and post breakthrough performance. The case considered here is a well producing from a monocline with an edge-water aquifer. Although such problems can be computed with reservoir simulation, the objective of this work was to develop simple empirical correlations for predicting water production behavior from a monocline reservoir.

The reservoir model was described as a single well producing from the top of a monocline drainage block with water drive from an infinite-acting aquifer. During the reservoir simulation runs, water would cusp and cone into the well, increasing water production and decreasing oil production. A number of simulation runs were made, varying eleven model variables. Typical model variables include dip angle, formation thickness, production rate, etc. For each run, a modified Addington-style13 plot was made. The relationship between each model parameters and three graphical variables was used to develop the set of empirical correlations. The empirical correlations developed were integrated with some derived equations that relate important reservoir parameters and incorporated into a computer program.

The developed correlations and program can be used to carry out sensitivity analysis to evaluate various scenarios at the early planning stages when available reservoir data are limited. This gives a quick and easy method for forecasting production performance with an active edge-water drive. Furthermore, the approach developed in this work can be applied to water production problems encountered in other field/reservoir.
Increased Oil Production by Unconventional Wells—Short-Radius, Horizontal, and Multilateral in the Hassi Messaoud: Thick Multilayer Cambrian Formation, Algeria
Authors: Youcef Boughaba , Tiab Djebbar
Published: June 2008

Unconventional drilling technology has been widely and successfully applied around the world for the recovery of Hydrocarbons. Significant technological achievements have been made in horizontal technology through a variety of innovations in tools, and experience gained over the past years.

Unconventional drilling provides solutions to the recovery of oil from inaccessible areas in reservoirs such as un-drained fault blocks, marginal fields, production improvement in tight reservoirs, intercepting natural fractures that cannot be accessed to their full potential with vertical technology and/or improvement of water-flood sweep efficiency, etc. In case of forced abandoning of highly productive vertical wells, the existing well bores can be reentered and horizontally re-drilled through the pay zone, primary objective being, increasing the well bore contact with one or more reservoirs.

One of the most important issues affecting economics, especially of re-entries, is whether the production enhancement will consist of accelerated production, increased reserves, or both. For a well with accelerated production only, net worth is improved, although total revenue is not increased. An increase in reserves is important to the economic success of a horizontal re-entry program.

This paper discusses performance review of unconventional wells in Hassi Messaoud including selection of target reservoir, planning options, well testing methodologies,well completions, specific reservoir response, and production management Complex reservoir response poses a challenge for us in identifying flow behavior in the horizontal bore hole, flow regimes in the reservoir, flow mechanisms during well testing, and during vertical lift.

This research is an attempt to meet such challenges and involves analyzing the actual field data to identify the potential response of highly complex reservoir system to the unconventional wells. Flow regime and flow pattern identification is duly supported by flow equations with modification related for Hassi Messaoud Field.
Use of Hydrajet Perforating to Improve Fracturing Success Sees Global Expansion
Authors: McDaniel B. W. , Surjaatmadja Jim B. , East Loyd E.
Published: June 2008

As shown by technical papers as early as the 1960s, our industry has long known that hydrajetting perforations or slots through cemented casing could often "bail-out" a problem well that otherwise seemed completely resistant to hydraulic fracturing attempts. For most of the first 50 years of fracturing applications, few operators had sufficient demand for the fracturing process to make it a commodity service, especially before the advent of coiled tubing (CT) services in the 1980s. Often, this type of well service was costly because of the need for both abrasive mixing and high-pressure pumping. In many cases, it was too time consuming to be practical as an "every-well" application, and lower-cost conventional explosive shape- charge perforating seemed sufficient for most wells.

As oil and gas prices have drastically increased in recent years, many operators have realized that for some well conditions, the use of hydrajet perforating (HP) can improve fracture stimulation efficiency and well economics. In a few cases HP has proven to be the only way that effective fracture stimulation could be achieved. In the past few years there has been a growing acceptance among both operators and service companies that hydrajet (abrasive jetting) perforating can improve overall well economics for fracture stimulated wells in many reservoirs. Some newer methodologies have combined hydrajet perforating and hydraulic fracturing into a single, continuous, multi-stage stimulation method. For many wells needing multiple fracture stimulations, significant reductions in nonproductive time (NPT) allows for reduced well costs even when more actual fracture stages are pumped. Use of more stages has often provided significant production gains and greater recoverable reserves.

Enhanced stimulation success in many moderately hard and very hard formations have proven the value of converting from shape charge perforating to hydrajetting as a stand-alone operation to avoid severe near-wellbore problems during hydraulic fracturing stimulation treatments. Since about 2000, and especially during the most recent 5 years, service providers have progressively expanded the processes, which included hydrajet perforating, especially in conjunction with hydraulic fracturing methods. This paper will review the expanding applications of hydrajet perforating in recent years, including case histories from several global applications.
Geothermal Reservoirs: A Renewable Source of Energy and an Extension of Petroleum Engineering
Authors: Ullah Syed Zahoor , Bukhari Syed Rehan Shah
Published: June 2008

With the concern over anthropogenic climate change (i.e. man-made climate change), there is a growing awareness that we must utilize energy resources that are sustainable. The power obtained from geothermal reservoir is one such sustainable resource that has the potential to supplement our energy systems and to displace many conventional fuels. In contrast to many renewable technologies, such as wind or solar, the geothermal resource can be used 24 hours a day, 7 days a week without any harm to the environment.

It is due to this reason that geothermal development, a natural extension of oil and gas development activities, is attracting both new petroleum engineering graduates and established petroleum engineers in increasing numbers. Along with the importance of geothermal energy, this paper details as to how different phases of geothermal industry like drilling, production, and reservoir utilize petroleum engineering techniques, the challenge awaiting engineers as they work to solve first- time problems and improve technology for future activities. The geothermal industry has tremendous potential for growth and will make a significant contribution to worldwide energy supplies.
Test Method to Optimize Acid-Soluble Cement for Unconventional Gas Completions
Authors: Luke K. , Soucy K.
Published: June 2008

In recent developments of unconventional gas reservoirs, there has been a move towards drilling horizontally to increase formation contact with the objective to increase production. A longer horizontal extension gives greater formation contact. However, these extended laterals must be cemented which has caused constraints on optimal reservoir production. Studies have indicated that conventional cements are one of the primary causes resulting in reduced fracture initiation.

Acid-soluble cements have been advocated for use in unconventional gas reservoirs as a means to reduce the rate of inefficient fracture initiations. The logic behind using acid-soluble cement was based on field study examinations completed in 2005. These studies indicated that more than 25% of cemented horizontal laterals experienced fracture initiation problems compared to 4% for uncemented horizontal laterals. In acidizing acid-soluble cement in the area of strategically placed clusters, conditions approaching open hole are obtained similar to that of uncemented horizontal laterals. Cement remaining between clusters provides sufficient zonal isolation for well bore stability.

There are no standard tests to define the characteristics of acid-soluble cements such as acid solubility or rate of dissolution that are factors crucial to obtaining good cement removal and minimal near well-bore issues. In this context a prototype test method has been developed to more closely simulate dissolution of acid-soluble cement for unconventional gas reservoir applications. Data obtained indicate the benefits of such a method to define the most appropriate acid-soluble cements, acid treatments and develop improved systems.

Published test parameters vary considerably and given the number of variables involved in dissolution techniques there is a question as to what defines a good acid-soluble cement. Development of a test method that simulates down hole conditions provides a tool to design acid-soluble cement systems to optimize open hole around perforations and ultimately minimize fracture initiation problems.
Investigation of Water-Swelling Packers
Authors: Al-Yami A. S. , Nasr-El-Din H. A. , Al-Arfaj M. K. , Al-Saleh S. H. , Al-Humaidi A. S. , Awang M. Z. , Al-Mohanna K. S.
Published: June 2008

Achieving successful zonal isolation during well completion is critical to minimize early water production. Currently, cementing is the only method used in Saudi fields to provide zonal isolation. However, in horizontal sections, cementing becomes a challenge and water flows can occur due to channeling. Another method for zonal isolation is to use a rubber elastomer bonded onto a base pipe. The rubber swells in water and provides a seal between the base pipe and the open hole.

This paper will outline the step-by-step qualification testing that was carried out in Saudi Aramco facilities in an attempt to improve zonal isolation in horizontal and multilaterals wells.

In this study, we present lab evaluation of elastomers at 190°F using brines of different ionic strengths and pH values. The evaluation involved examining the effect of salinity and pH on the rate of swelling of elastomers. Also, the study investigated the effect of 15 wt% HCl acid on the swelled elastomers. To the best of the authors' knowledge, no previous work was done to examine the impact of these factors on the swelling mechanisms.

The elastomer bonded in pipes was tested in autoclaves. The pressure drop across the pipes was measured as a function of time. The influences of fluid density and viscosity were also investigated using elastomer samples. Swelling was related to volume of the samples and fluid characterstics.

Water swelling elastomers withstand pressures up to 5,000 psi at 190°F after placing the elastomers in salinities up to 200,000 mg/l. However, the swelled elastomers shrink in 15 wt% HCl. This paper discusses the advantages and limitations of swelling elastomers and gives recommendations for successful field applications.
Design and Operational Factors for the Life of the Well and Abandonment
Authors: Tahmourpour Farzad , Exner Mike , Khallad Isaac
Published: June 2008

Zonal isolation throughout the life of the well is important to help ensure that health, safety, and environmental (HSE) standards are not compromised and that the well operates economically. The life expectancy of a well is dependent on the protection that the wellbore can receive from primary cementing operations.

A primary cement job design that provides zonal isolation and preserves structural integrity over the life of the well can reduce or eliminate the need for remedial operations. Achieving successful zonal isolation comprises three key mechanisms:

Design and delivery of a reliable cement system that can withstand the effects of the operational loading and cyclical stresses exerted on the well by drilling, completion, and production operations. An auto-seal feature in the cement sheath itself. In the event that the cement sheath fails and develops cracks and/or micro-annuli because of primary cementing job failure in the presence of a mud filter cake, the sealant sheath can then react and respond in an attempt to automatically seal itself if formation fluid enters the cemented annulus. This is a fail-safe technology mode that can be included in the design of the cement slurry. Employing a packer element as part of the casing/liner string that can swell and seal the annulus if formation fluid comes in contact with the element. This additional contingency can help prevent flow of the hydrocarbon past the packer element by creating an effective mechanical seal.

By applying these features, it is possible to effectively and successfully perform primary cementing operations with additional protective options and place sealants that will last throughout the life of the well (Fig. 1).
Integrating Multiple Production Analysis Techniques To Assess Tight Gas Sand Reserves: Defining a New Paradigm for Industry Best Practices
Authors: Ilk D. , Perego A. D. , Rushing J. A. , Blasingame T. A.
Published: June 2008

Decline curve analysis using the Arps rate-time equations has historically been the primary tool used for reserve evaluations in tight gas sands. However, characteristic tight gas sand properties often preclude accurate assessments using only or primarily decline curve analysis — especially early in the productive life. Moreover, the Arps models are essentially used as curve-fitting devices with (very) limited theoretical basis. As such, this paper presents a reserves appraisal process that complements traditional decline curve analyses with theoretically-based production analysis techniques.

Specifically, we incorporate multiple reserves estimation techniques ranging from simple extrapolation techniques to rigorous model-based analysis/interpretation methods, including:

Arps exponential and hyperbolic relations — rate-time and rate-cumulative plots, as well as other auxiliary plots, Semi-analytical rate-cumulative techniques for boundary-dominated flow, The "flowing material balance" approach in its various formulations, and Model-based analysis ("rate-transient" or "model-matching" approaches).

We provide both separate and combined analysis, including "diagnostic" plots which guide the evaluation process and help prevent erroneous reserve estimates resulting from use of single methods. Implementation of the proposed workflow will prevent unrealistic (either too low or high) reserve bookings by integrating multiple production analysis techniques. We demonstrate where and how each component technique should be used as well as their limitations. We also demonstrate how each technique can be used to reinforce/validate results from other techniques (i.e., multiple redundancies of methods).

The primary objectives of this work are to:

Provide a consistent workflow for integration of multiple reserve estimating techniques for tight gas sands, Provide an assessment of strengths and weaknesses of individual reserves estimation techniques, and. Provide demonstrative examples for implementing this workflow (including diagnostics).
Global Possibilities of Future Methane and Hydrogen Economies
Authors: Aguilera Roberto F. , Aguilera Roberto
Published: June 2008

There is concern within some factions of the energy industry about an approaching energy crisis. In the case of hydrocarbons, eventually there will be a maximum peak in global production. The question is if it will occur sooner or later, and if it will happen because of depletion or because of substitution to other energy sources - perhaps unconventional or non-fossil. This does not preclude hydrocarbon shortages that might still occur due to temporary factors such as political instability and lack of investment.

Although the past is not always an indication of the future, an analysis of global market shares (i.e. the mix) for solids, liquids and gases from the year 1850 to 2005, leads to a model that permits a reasonable forecast of the global possibilities of future methane and hydrogen economies.

It is concluded that if there is a supply problem in the future it will not be the result of depletion, but rather the failure of society to invest in the research and development of technology needed to provide conventional and unconventional hydrocarbons, as well as alternatives such as hydrogen, on a timely basis.

Proper development of these resources will lead to sustainable and efficient global economic growth.
Making the Most of Conventional Decline Analysis
Authors: Jordan Colin L. , Jackson Robert , Smith Cooper
Published: June 2008

Despite its many limitations, conventional decline analysis is still commonly used in gas production analysis due to its minimal data requirements and ease of application. Yet, there is strong desire and need for more sophisticated methods such as those loosely defined by the term advanced decline analysis. As a result, this paper presents an automated computer method for estimating original gas-in-place and other reservoir flow parameters. The method is semi-analytical in that it is based on a semi-empirical relationship between gas production and initial reservoir conditions, but is coupled with conventional decline analysis methods for ease adaptation into the workflow.

The procedure provides additional information comparable to flowing material balance analysis, but within the familiar Arps decline environment – a critical component that makes the procedure very amendable to traditional workflows. Another advantage is that the proposed methodology does not require a prior knowledge of net pay, formation and/or fluid compressibility, or reservoir pressure (other than initial conditions) for estimation of OGIP. Results will also show that the approach is generally accurate and robust (when used appropriately) and provide additional information such as effective permeability if a few volumetric parameters are provided. And that the procedure is extremely simple and can be implemented in desktop applications or spreadsheets with minimal computational effort.

Although there are limitations such as constant flowing pressure (as well as multiphase flow), it will be demonstrated that the procedure is generally versatile and can be applied to a number of gas systems including conventional sands and silts, thermogenic and biogenic shales, as well as (dry) coal bed methane. Results and observations are based on both simulated and field examples for a variety of operating conditions. In conclusion, a novel and rapid methodology has been introduced for estimating original gas-in-place, ultimate recovery (EUR), and other flow parameters with the simplicity of conventional decline.
Cementing Horizontal Wells: Complete Zonal Isolation Without Casing Rotation
Authors: Carrasco-Teja M. , Frigaard I. A. , Seymour B.
Published: June 2008

There is a common perception that displacing mud in horizontal wellbores is made ineffective by large density differences due to stratification of the fluid layers along the annulus. Hence the industry commonly employs methods such as casing rotation to move fluids around the annulus. Whilst such methods may be effective, they are not always necessary. Using a mathematical model of the process, we show that even with large density differences it is still possible to have a steadily advancing displacement front that displaces mud all around the annulus without casing rotation. The conditions when this is possible depend on the fluid rheologies, flow rate and hole geometry, but not the density difference. These conditions are easily quantified. Although density difference does not enter into the criteria for an effective displacement, the length of the interface along the wellbore does scale with the density difference. This means that, provided one is able to tolerate additional fluid volumes, we are able to effectively displace the mud even using fluids with large density differences. This new understanding of the displacement fluid mechanics opens up new opportunities for cementing difficult horizontal wells, (e.g. slimhole), where casing rotation is not possible.
Evaluating Crossflow Migration Drainage
Authors: Scholz J. , Sorensen F. , Hamp T.
Published: June 2008

Understanding the effects of lease-line drainage has always been a challenge facing natural gas producers. When approaching this issue, companies generally focus on gas migration caused by reservoir pressure gradients. However, ‘crossflow migration’ in multi-layered reservoirs also needs to be evaluated.

Crossflow migration occurs when wells produce at a flowing pressure higher than the near-wellbore reservoir pressure of a commingled and depleted high permeability zone. This can result in unexpected crossflow of gas from a low-permeability, high-pressured, high-reserves zone to the depleted zone, and, through this ‘thief zone’, migration of the gas to adjacent lands.

This study quantifies reserves and production impacts of crossflow migration, using a model of two neighbouring shallow gas properties in S.E. Alberta, and based on geological characteristics typical of the area around the Alderson, Suffield and Medicine Hat Fields (Figure 1).

The analysis showed that historical lease-line drainage of 1.9 BCF (55 e6m3) occurred during 1960–2007 over a one-mile boundary between two operators, one of which had aggressively developed its property through reduced operating pressure and infill drilling. Of this amount, approximately 45% was through the permeable Medicine Hat A (MHA) formation. Drainage through the MHA was supported by approximately 0.6 BCF (18 e6m3) of crossflow into that formation from other zones completed in the commingled wellbores. If left unaddressed, further drainage of 0.7 BCF (20 e6m3) was predicted to occur over the 30-year forecast period.

Using reservoir simulation, this study also identifies an optimal development strategy to minimize the impact of crossflow migration drainage.
Directional-Specific TCI Drill-Bit Design Features Allow for High Penetration Rates and Improved Durability in Tough Build Sections in Canadian Applications
Authors: Mason Chad , Rickabaugh Caleb , Olson Eric , Christensen Hughes
Published: June 2008

Regions of western Canada comprise tough interbedded formations of hard sandstone, siltstone, shale and chert, which create great challenges for directional drilling applications. Historically, using conventional tungsten carbide insert (TCI) rollercone drill bits to drill a directionally placed wellbore trajectory has resulted in low penetration rates and short runs due to the impact of high cyclic loading and damaging hole-wall contact on the bits. With WOB being preferentially loaded on the heel and adjacent heel area of the roller cone cutting structure during directional drilling, cutting structure breakdown is accelerated and seal failures occur. Additionally, rigorous hole-wall contact increases gauge and shirttail wear.

Extensive research, testing, and development have produced TCI rollercone bit designs that have addressed these major challenges. A multitude of design iterations have resulted in a new TCI rollercone drill bit that includes innovative cutting structures for improved durability and ROP, enhanced OD and leg protection to ensure bearing integrity and gauge-holding ability, and stronger materials and processes to withstand high cyclic loading of directional drilling. Drill bits designed with these features have been successful in increasing average footage per run by 121% while improving penetration rates modestly vs. offset drill bit runs in the western Canadian regions, which include Saskatchewan, Alberta, and British Columbia. Additionally, one-bit runs, as opposed to two or three, are now possible in builds to horizontal in many applications, thus reducing overall drilling time by over 25%, and significantly reducing drilling costs.

This paper will detail the directional TCI rollercone drill bit design features and technologies used as well as field results and case studies from Canadian-specific markets.
Fishing MWD Tools in Horizontal Wells Without Fluid Circulation
Authors: Frasure Gregg , Travis Deck , Montgomery Billy
Published: June 2008

The boom in horizontal drilling presents new problems that require innovative solutions. Typical drilling problems such as stuck drill pipe have only become more acute with the emergence of horizontal drilling. Formation instability, improper hole cleaning and break-out debris in the hole wedged beside the drill string can cause drill pipe to become stuck resulting in costly pipe recovery operations.

A new application of the electric wireline Well Tractor® has made possible the efficient recovery of MWD (Measurement While Drilling) tools and other stuck assemblies in horizontal and highly deviated wells.

This paper presents an alternative to conventional fishing methods by utilizing Well Tractor® Technology. In today's market, Operators face challenges in the conveyance of pipe recovery tools in the lateral section of a well if circulation is lost during the drilling process. This leaves the operator with few options, all of which are time consuming and expensive. In some cases, abandoning the hole and side tracking is required. In addition to drill pipe recovery services such as free point and back-off operations, MWD tools can be fished in highly deviated and horizontal wells, reducing overall operational and replacement costs of these exceptionally high priced MWD tools. With rising rig costs, it is crucial that fishing operations are conducted in the most efficient manner possible.

The Well Tractor® has fished MWD tools successfully at various well depths, inclinations, mud weights and different drilling assemblies. The Well Tractor® design is well suited for operation inside drill pipe and completion strings with varying Internal Diameter (ID) such as joint connections, or when going through cross-overs and landing nipples.

An overview of the Well Tractor® technology, used in these fishing operations, is presented. A summary of operational benefits related to this application is included along with case studies showing how the Well Tractor® technology has become a new solution for conveyance of fishing technology to retrieve MWD and other systems in deviated or horizontal pipe recovery operations.