bluuebunny/crossref_metadata_2025 huggingface dataset:
Downhole Impulse vs.Downhole Impacts Improve Recovery of Stuck Retrievable Packers
Authors: Haughton David B. , DeGeare Joe P.
Published: December 2007

Stuck retrievable packers are most often fished out of the hole with a jarring string. Essentially, this is a hammer that is used to beat the packer out. The jarring operation proceeds until either the jars quit or the mandrel is jarred out of the packer. In either case, a milling assembly must be run, which can take more than one trip to complete. Experience has shown that recovery of stuck packers by conventional means is very difficult and time consuming. On some deepwater floating rigs with day rates from $200,000 to $500,000, a stuck packer that takes days to recover can have a catastrophic cost.

Recent downhole vibration and impulse studies have shown that downhole impulses could be considerably more effective than jarring in retrieving packers and other point-stuck equipment. By imparting - impulses downhole to the stuck object, there is no need for a high-strength work string. The chances of pulling the mandrel out of the packer or sticking the packer tighter in the wellbore are greatly reduced.

Impulses work independently from overpull, so it is ideal for horizontal or high-angle wellbores. Another advantage is that the work string does not have to be reciprocated as much as with a jarring string. When pulling out of a wellbore, a packer can get hung up on restrictions such as casing collars. Jarring strings cannot be reset unless the packer can be set down, which allows the jars to close and reset. A downhole impulse tool works only on fluid pumped through the tool, so it can be activated at any time by rigging up a pump line. There is no need to set down the string. This new method has been shown to be an effective alternative to conventional jarring tools. Cost savings can be substantial.

This paper focuses on the development, operation, and applications of this technology. Case histories are examined in detail showing advantages over conventional means.
A Fresh Look At Stimulating Unconsolidated Sands With Proppant-Laden Fluids
Authors: Di Lullo Gino , Curtis James , Gomez Julio
Published: December 2007

Can unconsolidated sands, with no intergranular cohesion forces, really be hydraulically fractured? Does conventional hydraulic fracturing theory adequately explain treatment behavior and production results? If the unconsolidated formation is considered to be a fluidized sand bed, is the classical linear-elastic two-wing hydraulic frac assumption still valid? Alternative proppant stimulation mechanisms may better describe the process, including squeezing or forcing by viscous fingering of the high-permeability proppant slurry into the formation. In this scenario, traditional fracturing design parameters such as pad volume, pump rate, proppant concentration and especially fluid viscosity will have new and significantly different effects on the treatment outcome.

This paper explores these concepts and shows how they can explain both treating behavior and production responses of so-called "frac jobs" or "sand-oil-squeezes". Alternative treatment and fluid design criteria are proposed to achieve more consistent and predictable production responses, based on field performance.
Changing Safety Paradigms in the Oil and Gas Industry
Authors: Ratliff Matt
Published: December 2007

The oil and gas industry boasts a hard-earned reputation of being able to get the job done anytime, anywhere. Unfortunately, this distinction has also produced an inherent attitude that too often puts the job first, regardless of personal safety. To confront the ongoing stigma of poor safety practices, the industry began promoting a "safety first" approach. As admirable as this goal is, many health, safety, and environmental (HSE) professionals found that deeply ingrained attitudes and practices are difficult to change. HSE personnel often fail to convey their message effectively because they lack not just a formal program but also a willing audience.

Talking "safety first" is merely the first step to promoting a successful HSE culture within the industry. The next key step requires the development of an HSE management system that allows all HSE professionals to promote a consistent message to the industry. Proven success stories provide models to replicate and encouragement for the industry to change.

This paper will discuss some of the practices currently engrained in the industry and outline methods to help shift current HSE patterns to consider safety first. Leadership practices that supervisors can implement to define and shape employee behavior will also be detailed. To conclude, this paper will discuss the characteristics of a program that produced a successful HSE culture and convey steps others can take to modify the existing industry paradigm.
New Technologies Combine to Reduce Drilling Costs in Ultradeepwater Applications
Authors: Touboul Nicolas , Womble Lee , Kotrla John , Keith Neal
Published: December 2007

As the oil and gas industry matures, so does its technology and equipment. As a drilling rig gets older, it becomes increasingly challenging to use it to explore for untapped deep reserves. Offshore rig builders are constantly manufacturing rigs with new, sophisticated capabilities, thereby widening the technology gap between the new rigs and the aging ones. As a result, many operators of older rigs are modifying their rigs to compete with newer ones.

Using a modified second-generation semi-submersible rig in Indonesia, Total was able to reach target depth in an ultra-deepwater well by deploying a combination of surface stack drilling technology, a subsea shut-off device known as an environmental safe guard (ESG), and solid expandable tubular technology. If conventional casing had been used, the optimal hole size at total depth (TD) would have been impossible to attain and economically unfeasible without the use of a fourth or fifth generation semi-submersible or drillship.

This paper describes the safe and successful integration of new technologies that enable surface stack drilling with modified second- or third-generation semi-submersible rigs in environmentally less-benign areas, including the Gulf of Mexico. In addition, the paper will discuss the deployment of solid expandable tubular technology from a modified second-generation rig and show how this technology enabled the operator to achieve a sufficient hole size at total depth while maintaining an economically viable operation.
Gulf of Mexico Cement Packer Completions Using Liquid Cement Premix
Authors: Eberhardt J. Todd , Shine Joseph
Published: December 2007

A popular and economical method of re-completing wells in offshore Gulf of Mexico (GOM) involves pumping a "cement packer" across a productive zone which the operator wishes to produce. Recently, the application of Liquid Cement Premix (LCP) technology for cement packer completions has shown many advantages. This paper will summarize the operational and logistical process of pumping a cement packer with conventional cement. In addition, the chemistry and properties of LCP along with the process of performing a cement packer completion using LCP will be detailed. The operational and logistical benefits of using LCP will be discussed, concentrating on its ease of transportation and pumping, minimal equipment requirements, consistent slurry properties, and reduced environmental exposure. Best practices recommendations will also be made for cement packer placements, supported by the evaluation of published literature and previous cement packer completions using LCP.
A Case Study of Uncertainty Management for Developing Fluvial Sedimentary Reservoirs
Authors: Zhou Dengen , Wei Michael , Seguin Ron , Wang Zhiyong , Nan Tian
Published: December 2007

We have developed and implemented an uncertainty management plan (UMP) for developing an offshore heavy oil field. The field is located in shallow waters and the oil API gravity varies from 17° to 21°. The reservoirs are fluvial meandering river systems, where sands are relatively thin and poorly connected. Because of limited appraisal data and the complex nature of the reservoir, uncertainty management was identified to be critical to the success of the field development.

A three-part uncertainty management plan have been developed and implemented, which includes a three-stage drilling program, an optimized completion matrix and a production surveillance program. The three-stage drilling program was designed to obtain critical reservoir/geological information with as low risk as possible by optimizing the drilling sequence. The drilling sequence was defined by classifying the development wells into (1) high confidence (HC) wells, (2) high value of information (HVOI) wells, (3) wells that need relatively certain reservoir information to be successful (horizontal wells) and (4) wells that could be optimized with new information. A mix of HC and HVOI wells were drilled first to validate the appraisal data and obtain critical new reservoir data, which were then used to optimize well placement. The drilling results show that the three-stage drilling program has been successful in capturing the upside reservoir potentials and in avoiding drilling low efficient wells.

The fluvial sedimentary environments of the reservoir create great challenges for reservoir management of heavy oil waterfloods. Based on the best practices and lessons learned in developing similar fields, a well completion strategy matrix was developed to mitigate the risks of multi-water/oil contacts and to avoid excess water production.

A down-hole pressure monitoring system was also installed as part of the surveillance program. The strategies used for selecting the wells to be installed with pressure monitoring gauges were developed based on the well types and the reservoir connectivity. This paper provides a great example of uncertainty management in developing complex reservoirs.
Wireless Measurement Systems for Efficiency Improvements and Desired Management Data
Authors: Lueders Wallace M.
Published: December 2007

This paper describes the important benefits and design considerations of system architecture that will provide a robust, reliable license-free wireless network for industrial sensors in heavy industrial plant environments. The characteristics of commercially available devices and communication protocols are discussed including the benefits of spread spectrum radios compliant with FCC Part 15 rules. Although FHSS provides some measure of protection if a frequency or set of frequencies is noisy, careful network system design and implementation is essential if periodic sensor measurement or control is to be reliably achieved over the lifetime of the installation.

Typically, the electromagnetic environment of industrial sites is not well understood, therefore it is important to survey the area prior to system installation to characterize the conditions and design wireless networks accordingly.

Finally after system installation, continuous self-checking and system monitoring should be carried out to alert of any degradation in performance and to allow for dynamic modification of the radio network as external conditions require.
Sustained Gas Production From Acid Fracture Treatments in the Khuff Carbonates, Saudi Arabia: Will Proppant Fracturing Make Rates Better? Field Example and Analysis
Authors: Zillur Rahim , Petrick Mark
Published: December 2007

Acid fracture treatments in the carbonates are widely applied to enhance well productivity. Some laboratory experiments conducted on actual core specimens under in-situ conditions illustrate that the etched conductivity can reduce with time and eventually close the fracture. In some 100+ wells that have been fractured thus far in the Saudi Arabian Khuff gas reservoirs, long-term sustainability of fracture lengths and conductivity has been demonstrated through fracture and production diagnostics. The phenomena of fracture closure observed in the laboratory studies on certain cores may not therefore be generalized to represent all reservoirs and fields. Nevertheless, longer fracture lengths than generally achievable by acid fracturing are often desirable, particularly in gas condensate fields. Proppant fracturing can create longer fractures and has potential for application in such fields.

This paper provides field cases and evaluates fracture effectiveness from treatment pressure, pressure transient tests, and production data. Initial computation of fracture properties using measured data during treatment and production transients combined with analysis of pressure transient tests performed later during the production life indicate continued presence of induced fracture. Assessment of fracture operations, reservoir flow characteristics, and mechanical properties suggests that the high rate, high volume acid treatments, and formation heterogeneity in terms of layering and permeability variation which helps in uneven acid etching and thus enabling wormholes to stay open contribute to the long-term sustainability of fracture conductivity, half-length, and well performance. The paper evaluates these parameters and provides an assessment on acid fracturing.

Condensate accumulation is occurring in the Khuff reservoirs and this is affecting production rates. Several typical wells are examined to illustrate this point. Liquid dropout is unpreventable, but its effects can be reduced or postponed with longer fractures. Thus the need for proppant fracturing is evident.

Saudi Aramco has started testing the viability of proppant fracturing in the Khuff carbonates. The results obtained so far indicate that careful candidate selection and treatment design are needed to guarantee fracturing success. The selection criteria, treatment design and results of Saudi Aramco's first ever proppant fracturing in a Khuff reservoir are examined in this paper.
Improved Method of Cementing Solid Expandable Tubulars
Authors: Fanguy Charles Joey , Mueller Dan T. , Doherty Dale R.
Published: December 2007

The successful isolation of solid expandable tubulars (SET) with cement presents a considerable engineering challenge. The primary task in slurry design is to maintain "true fluidity" at static downhole conditions. The slurry must remain both fluid and stable after placement until the expansion process is completed. Failure of the slurry to remain fluid and stable after placement can prevent the successful expansion of the SET. This property, of being both stable and fluid, is difficult to achieve with conventional cement technology because conventional slurries tend to settle under downhole conditions after an extended period of quiescence. This instability leads to density segregation and potential formation breakdown in the lower sections of the well.

A second obstacle that must be overcome to successfully cement a SET is inter-particle attraction (gellation) that can occur once the cement slurry is placed. Minimizing inter-particle attraction/gellation reduces the likelihood of forming voids or channels (micro-annuli) in the finished cement sheath, which can jeopardize effective zonal isolation, the essential performance requirement of any well cementing operation.

The test method currently used to evaluate the properties of conventional cement slurries during the anticipated expansion time is the API RP-10B modified hesitation squeeze simulation. Unfortunately, this test method does not simulate accurately the conditions under which the cement will be placed. For example, the test procedure does not allow adequate time for gellation tendencies to occur. Gel strengths are broken every time the consistometer motor is turned on, producing gel strength values that have no more than ten minutes to develop. This test method also does not provide a means to account for any potential delays that may occur during the expansion of the SET.

To enhance accuracy and reliability in SET cementing operations, a test method which incorporates testing storable premixed cement slurries for fluidity time at static conditions as opposed to using the API modified hesitation squeeze procedure has been successfully employed in field applications. This paper will describe the premixed slurry properties and QA/QC procedures that are required for successful expansion of the SET. This paper will also provide test methods and procedures used for fluidity time testing as well as case histories of successful SET cementation.
Getting the Best From the Black-oil Approach for Complex Reservoir Fluids
Authors: Montel François , Quettier Lisette
Published: December 2007

First, this paper presents a novel method used to derive accurate black-oil properties from a detailed EOS model. This entails the selection of the fluid sample, the choice of the simulated experiment and the representation of the composition gradient. In the case of significant compositional grading with a critical or close to critical transition within the reservoir fluid column, the table should be a compromise between (a) the in situ properties versus depth, which allows an accurate fluid in place representation and (b) the property change versus pressure during depletion. We then describe three field cases using this approach: ■A miscible gas injection into an oil reservoir. 1D fine grid simulations show that the black-oil model gives the same property profiles as the compositional ones. At the field scale, we take advantage of the lower CPU time in black oil to better represent some heterogeneity as fairways which could be detrimental to gas injection.■A reservoir with a critical transition developed either by gas or water injection. With black-oil simulations both initial fluid in places and flow behaviour is correctly represented. But, even if the results are more stable than in compositional ones, the CPU speed-up is lower than expected.■A black-oil representation for history matching a reservoir with a critical transition allows us to have a finer description of the geological heterogeneities with a run time lower than the work day.

Finally, we propose improvements of our methodology based on the lessons learned from the simulations of the previous cases.
Dual Permeability Approach to Modeling Fluvial Reservoirs in the Costa Bolivar Region of Venezuela
Authors: Gomez Hector , Herring Todd
Published: December 2007

This paper builds on the results of previous work related to determining the drive mechanisms of the Mene Grande field. Various studies have been performed recently which all have indicated that the dominant water production mechanisms is depletion of the reservoir mustones or shales. This revelation has allowed both old and new data to be viewed in a new context which has led to a greater understanding of the reservoir bahviour.

Both the long term, data and recent transient analysis strongly indicate the presence of dynamic system behaving as two separate systems. These two systems can roughly be classified as oil filled sandstone, and water filled mudstone. The permeability and volumetric differences are sufficient to induce a typical layered reservoir response. The field data and supporting studies for this drive mechanism have been reported previously.

In this paper we describe the reservoir simulation methodology adopted in order to best represent this heterogeneus system. A dual permeability model has been used with the mudstone acting as the "matrix" and the sandstone as the "fracture". The matrix-fracture transfer function acts as a very efficient history match parameter both for pressure and water cut.

The results of both conceptual and well by well history matches are presented confirming that the methodology is well suited for modeling such systems. The quality of the water cut match even during the early stages of the work is quite remarkable.

This paper will be focused mainly toward the dynamic model, since the geological model was explained in a previous work (See reference 1 for further details).
Reservoir Study of the Largest Oil Field in Argentina - A Two Reservoir 2200 Well Simulation Model
Authors: Fonseca Claudio Marcelo , Firincioglu Tuba , Fernandez Gustavo , Ozgen Chet , Albertoni Alejandro
Published: December 2007

This paper describes the processes incorporated during the simulation study of the Chihuido de la Sierra Negra Field in Argentina, which is presently the largest oil field in the country. The field was discovered in 1968, and an aggressive water injection program was started in 1995. So far the oil production from this field is 65 million cubic meters and the water injection is 158 million cubic meters.

The field has two separate stacked reservoirs that are structurally complex with different fault systems and fluids. Both reservoirs are highly compartmentalized with each compartment having different water-oil contact. The upper reservoir is composed of 6 isolated geologic layers, with each being different depositional environments (sand bars, dunes, fluvial channels, etc.). The presence of unconformities and volcanic intrusions further complicate the reservoir communication and plays an important role in flow behavior.

Currently, the field has 734 production wells with commingled production from both reservoirs and the isolated zones with in the upper reservoir. Approximately 1250 injection strings are currently injecting water.

The purpose of this study was to provide a detailed reservoir characterization to optimize recovery and to create a simulation model with predictive capability that can be used in improving field management. To achieve this purpose a 900,000 cell simulation model was constructed.

This paper will discuss some of the challenges encountered during the history matching of the field model. The identification of the compartment boundaries and their associated water oil contacts (57 contacts) required the development of a new consistent approach. This method provided significant accuracy and time savings over the traditional approach of iterating between history matching and reservoir characterization. The overwhelming volume of data and the volume of simulation results for 2200 well strings required special considerations for pre- and post-processing. New tools were needed to quickly modify the simulation arrays and review all the wells in an efficient and timely manner. As the history matching progressed many additional practical tools were developed. This paper will discuss the significance of these innovations and tools to achieve a successful history match in a timely manner.
Lightweight Cement Formulations for Deep Water Cementing: Fact and Fiction
Authors: Rae Phil , Di Lullo Gino
Published: December 2007

In the past few years, oil companies have ventured more frequently into deepwater areas in the search for hydrocarbons. This trend is likely to continue, or even accelerate, in the next few years and, if anything, we are likely to see ever-greater water depths.

There are several aspects of deepwater wells that make them particularly challenging, from an engineering perspective, through all phases of the process – construction, production, intervention and abandonment. This paper, however, focuses on the issues surrounding deepwater well cementing, primarily during the well construction phase.

This has been an area of intense interest in recent years, due to industry realisation that the deepwater environment had one or two surprises for drillers. Most notable amongst these is the problem of shallow water flows that can easily wash out the weak, unconsolidated sediments, resulting in seabed subsidence and loss of the hole. Other issues include the presence of shallow gas and gas hydrates, strong subsea currents and extremely low fracture gradients, with the ever-present risk of lost circulation or wellbore collapse. The low seabed temperature, which can be below freezing, also depresses the normal geothermal gradient to a variable depth, depending on the thermal properties of the strata.

None of this is good news for cement, which is required to have short thickening time, rapid development of mechanical properties, a fast liquid:solid transition and low permeability to provide casing support, cope with the risk of influx and provide a long term hydraulic seal, amongst other things. This has driven the development and marketing of a host of proprietary cementing systems that claim to address some, or all, of these problems.

This paper reviews the deepwater cementing issues, in detail, and examines the physical and mechanical properties of various cement systems to assess which parameters are truly critical to success. It combines laboratory data with field case histories and working practices in several parts of the world, to help engineers decide on the best formulations for cementing deepwater wells.
Solving Well Construction Challenges Without Downsizing the Well, Using Solid Expandable Liners
Authors: York Patrick , Ring Lev , Terry Jim , Slater Keith , Innes Gareth , Stephenson David
Published: December 2007

In the pursuit of profitable well construction, operators are challenged to drill cost-effective wells while being prepared for the unexpected. Flows, lost zones, sloughing shales, and over-pressured zones are typical examples of unplanned well events that occur while drilling through troublesome formations.

Using conventional remedial methods, such as drilling fluid additives or lost-circulation pills, can prolong non-productive periods and dramatically increase drilling costs. Setting a drilling liner earlier than planned creates the risk of introducing an expensive sidetrack or losing the well altogether.

Solid expandable casing solutions, applied historically as a last-resort effort to save the hole section or even the well, typically carry with them a reduction of hole size, while the use of cement in conjunction with expandable slotted products has been used successfully without loss of hole size; however, for the most severe challenges, solid expandable products are needed.

This paper describes an alternative solid expandable liner system that can address a wide variety of well construction challenges without the need for downsizing a well section.

Openhole expandable "full-bore" liners that use proven cement-less formation-to-casing sealing elements can be used to address troublesome formations during drilling operations, allowing continued drilling of the well with the same size bit post remediation. Additional expandable openhole full-bore liners can be installed below the first if other trouble formations are encountered.

Typically, these solid expandable full-bore liners need only remediate short wellbore sections and therefore can become very cost efficient compared to long solid expandable liners. The tiedback expandable openhole liner (OHL), which must be tied back to the previous casing string, dictates that the next hole section be reduced in size. Applying these full-bore systems immediately on encountering well challenges can significantly reduce the flat time on the drilling curve.

The monobore well is under development, but the expandable full-bore system could be commercially available in the near term. This new openhole wellbore remediation tool can offer immediate and significant financial benefits to well construction. As a contingency solution, the system can be used to downsize wells, reducing well construction costs at the well or field level.
Impacts of Petrophysical Cut-Offs in Reservoir Models
Authors: Lalanne Bruno JP. , Massonnat Gérard J.
Published: December 2007

Petrophysical cut-offs are commonly applied so as to discard non-producing pay, yet, several aspects must be balanced one against the other in the process.

On one hand, considering present hardware and grid size limitations, one of the main benefit of cut-offs is that the relationships between petrophysical parameters are better preserved at the upscaled model grid scale. Otherwise, some bias between porosity, permeability and water saturation distributions may result from the upscaling process, due to the non-linear dependences between those parameters.

Conversely, applying cut-offs may tend to downgrade volumetrics and reservoir connectivity, and alter the actual reservoirs dynamics.

The overall process must therefore aim at defining an optimized set of cut-offs providing the simplest yet accurate upscaled model. This set must be basically adapted to both rock-type and recovery mechanism.

Some case studies are shown to illustrate how cut-offs can limit upscaling bias.

The benefits of both "total" and "effective" porosity – saturation approaches are briefly reviewed. We illustrate how "rock-types" characteristics differ in effective and total domains, and how cut-offs must therefore be tuned in each case.

Impacts of cut-offs on static volumetrics must be quantified. This can be conveniently achieved by visualizing the whole cumulative curve of "net hydrocarbon volume" vs. cut-offs values for each rock-type.

We present a handy way of testing and visualizing multiple combinations of nested cut-offs, which allows to distinguish critical from redundant or secondary cut-offs.
Web-Based Hosting of Multiassets and Multiusers Production Workflows
Authors: Theuveny B. , Nieten J. , Kosmala A. , Sagar R. , Donovan M. , Cosad C.
Published: December 2007

Real Time production workflows introduce significant changes to the production management practices. The introduction of new technologies such as affordable satellite communication, local field area networks, global connectivity to the internet, collaborative workspace (both virtual and actual war room concepts) and data mining agents have all contributed a number of enhancements in the production arena. Although the early gains obtained during the implementation of real time workflows can be as large as increase of 50% of production in some assets, the long term gains are typically in the order of 3 to 8 %. The paper provides a number of approaches to quantify the value of enabling traditional production processes with real time information and activities.

This paper also presents some inroads and lessons learnt in terms of the deployment of a new breed of real time services offered to support daily production management activities. These Activities include: Electrical Submersible Pump (ESP) monitoring and surveillance, real time productivity monitoring based on interpretation of downhole sensors and multiphase flowmeters. The analysis of over 600 installations worldwide provide insights of solutions and opportunities in varying environments covering a wide range of challenges such as North American cost sensitive context to Colombian security conscious field operations and harsh environment deployments.

Among the main challenges of the real time infrastructure for the production world, is the infamous management of legacy systems (old and aging SCADA systems, archaic instrumentation, challenging production sharing agreement financial terms). The paper offers a number of recommendations, and establishes a methodology to the deployment of workflows power by real time information.

A short discussion of the relative benefits of hosted services versus fully integrated solutions housed within the asset IT infrastructure provides key elements to operators to decide what would be the long term cost effective solution to be selected for a given asset.
Transport of Ethane-Rich Gases Using an Extensive Gas Pipeline System
Authors: Zarei Raed , Alvarez Carlos
Published: December 2007

The paper discusses a field case involving the transportation of ethane-rich gas streams. The streams were re-routed using an extensive pipeline network system with the objective of increasing ethane recovery. The changes presented significant operational challenges for managing large amounts of liquids accumulated in the pipeline system and delivering production smoothly to process.

Prior to re-routing the gas streams, transient multiphase flow simulations were performed to establish pipeline liquid accumulation, minimum and maximum allowable rates, pressure losses, and pipe scraping operations at different velocities. A later comparison between calculations and actual field performance showed a good match.

Dropping the planned refrigeration system for the gas pipeline system achieved significant capital savings. Ultimately, re-routing of the ethane rich gas allowed additional recovery equivalent to approximately 20 mmscfd with no additional capital investment.

A modern transient multiphase flow simulator proved useful in testing and setting up field operational changes prior to implementation, and managing extensive pipeline systems with severe liquid accumulation.
Methodology For Manipulation Of Wellhead Pressure Control For The Purpose Of Recovering Gas To Process In Underbalanced Drilling Applications
Authors: Graham R. A. , Culen M. S.
Published: December 2007

An updated approach to underbalanced well design has been developed with a view to enhancing the ability to recover gas to process (pipeline, gas plant, offset well, temporary storage, etc.). With the growing trend towards reducing greenhouse gas emissions, this technique evaluates the range of anticipated operating conditions (gas inflow and wellhead pressures) as a function of liquid and gas injection rates and the productivity index of the reservoir.

Typically, underbalanced drilling projects have been designed to minimize gas injection requirements down the drill string or annulus (concentric injection or parasite injection) for equipment efficiency and erosional considerations. This means that wellhead pressure is typically kept to a minimum, maintaining sufficient pressure to aid in shipping liquids from the separator. An exception to this is where elevated wellhead pressures may be desired to increase bottom hole pressure and reduce inflow from the reservoir, however, the objective in this instance is to control bottom hole pressure.

The typical approach to designing for underbalanced drilling parameters is normally based upon a graph of bottom hole pressure on the y-axis as a function of gas rate on the x-axis. It is usual to overlay the hole cleaning parameters – based upon minimum annular liquid velocity – and minimum and maximum equivalent flow rates through the motor. In addition, the target bottom hole circulating pressure limitations (usually derived as a function of reservoir pressure) define the operating window from which the required liquid and gas injection rates can be determined.

This updated approach addresses many issues such as equipment sizing and expected production rates while drilling through to effective pressure management at surface to aid in well stability. Furthermore, the approach lays down the fundamental groundwork for future underbalanced control algorithms.
Applying Advanced Fracture Diagnostics to Optimize Fracture Stimulation in Coalbed Methane Reservoirs: Case History of Two Fields in the Rocky Mountains
Authors: Wolhart S. L. , Stutz H. L. , Mayerhofer M. J.
Published: December 2007

Coalbed methane development continues to increase accounting for 8% of U.S. gas production in 2002. Many coalbed methane wells must be stimulated by hydraulic fracturing in order to achieve economic production rates. However, optimizing hydraulic fracture treatments in coalbed methane is difficult and advanced diagnostics can aid in the process. This paper discusses completion optimization for two coalbed methane reservoirs in the Rocky Mountains. Hydraulic fracture mapping was performed with treatment well tiltmeters on several wells in each reservoir. Treatment well tiltmeter fracture mapping is an emerging technology to optimize development of low permeability reservoirs. The fracture height measured with the treatment well tools was used to calibrate a fracture model for each field. The fracture mapping, calibrated model and on-site diagnostics were used to modify completion and stimulation strategy in these fields.

The completion strategy for both fields was fairly similar early on. Fracture mapping showed height growth through several coal stringers in both areas. There was some degree of containment in the laminated lithology bounding the pay packages but one field was more prone to height growth at higher pumping rates. Job size and injection rate were drastically reduced in this field because of the height growth tendencies and the presence of nearby water sands. This paper shows how the application of fracture diagnostics and engineering can reduce costs and help avoid costly errors. One example is shown with advanced diagnostics applied early in the development of a field and another example is shown with diagnostics applied after some development has already occurred. The differences in hydraulic fracture geometry that can occur between areas are also shown and how they create changes in completion strategy.
Economics for Enhanced Coalbed Methane (ECBM) and CO2 Sequestration with Horizontal Wells
Authors: Jikich Sinisha A. , Bromhal Grant S. , Sams W. Neal , Gorucu F. Burcu , Ertekin Turgay , Smith Duane H.
Published: December 2007

Injection of carbon dioxide into unmineable coal seams is a promising technology for reducing anthropogenic gas emissions and increasing ultimate recovery of coalbed methane. The combination of incremental methane produced and possible tax incentives might compensate for the costs associated with CO2 injection.

Currently the U.S. Department of Energy (DOE) is co-funding a pilot CO2 sequestration and enhanced coalbed methane (ECBM) project in the Appalachian Basin, in a thin coal seam. Horizontal wells have been drilled in the seam to increase CO2 injectivity and methane production rate. Previously, the reservoir simulations we performed for the planned pilot pattern indicated an optimum length for the horizontal injectors to maximize methane recovery and CO2 storage. By varying operational parameters such as time of primary production, injector length, injection pressure, injection timing, and production well pressure, we can evaluate different production alternatives to determine possible tradeoffs between optimum recovery of methane and CO2 sequestration, as defined by the amounts of the gases injected or produced.

The economics of an ECMB/sequestration project using horizontal wells are sensitive to the design parameters. In commercial practice it is necessary to select a design that maximizes the economic return. In the work presented here, net present value (NPV) was used to optimize the economics of the project. The evaluation used actual design parameters, current costs to equip the field for CO2 injection, and operating costs in the actual price range of ongoing projects: coalbed methane (CBM) and CO2 enhanced oil recovery. Methane recovery and CO2 injection data were obtained from our reservoir simulations. The economic impact of tax incentives was also considered in the analysis.

The analysis demonstrates the significance of reservoir size, proper design and implementation, and tax incentives for economic viability of projects for enhanced coalbed methane production and coalseam sequestration.
Modeling of Experiments on Water Vaporization for Gas Injection
Authors: Zuluaga Elizabeth , Lake Larry W.
Published: December 2007

Dry gas injected into wells will vaporize water from the near wellbore zone. The vaporization starts from the well and proceeds outward. Gas flowing to producers is in equilibrium with the reservoir brine, but water will be vaporized because the pressure drop that occurs toward the wellbore increases the ability of the gas to contain water. Thus, there are different mechanisms for injection and production.

For both injection and production, vaporization concentrates solids in the brine. When sufficiently concentrated, minerals will precipitate into the formation. This paper reports on a combined experimental and theoretical analysis on the vaporization portion of this problem for dry gas injection.

Experiments have been performed previously to determine the rate of water vaporization from Berea core samples at uniform initial water saturation (Zuluaga and Monsalve, 2003). The experiments were performed by injecting dry methane into core samples that contained immobile water. This would represent water vaporization in a gas injector.

Effluent water concentration curves showed two vaporization periods: A constant rate period and a falling rate period. The existence of a constant rate period means that the mass transfer within the core is occurring at conditions of local equilibrium. We interpret the falling rate period as the result of a moving capillary transition zone in which the amount of water vaporized decreases slowly because of capillary pressure effects.

We interpret the vaporization results with two traveling wave solutions. The first, which can be solved analytically, assumes that the capillary diffusion coefficient, D, the volume fraction of water in the gas phase, Cwg, and the volume fraction of water in the water phase Cww are constant. For this case, the results of the traveling wave are optimized with the capillary diffusion coefficient D to match the laboratory experiments. The second traveling wave solution must be solved through numerical integration. In this case, the capillary pressure and relative permeability scaling exponents are fitted to match the laboratory experiments. The fitting provides insights into the nature of wetting phase flow at small saturation.
Internal Repair of Pipeline Leaks Using Pressure-Activated Sealant
Authors: Rusch David W. , Romano Michael
Published: December 2007

A cost-effective method of internally repairing pipeline leaks has been developed that – in many instances – eliminates the need for expensive and risky external mechanical repairs.

By delivering a pressure-activated sealant between two pigs to a leak site and pressure activating the sealant to polymerize as a flexible solid within the leak path, it is possible to internally repair pipeline leaks without the need for excavating or replacing defective sections with minor leaks.
Perforating for Injection Wells
Authors: Folse Kent , Dupont Richard , Malbrough Joshua , Chow Christopher
Published: December 2007

Optimizing the design of injection processes in sand control (i.e., conventional gravel pack and frac-pack) and stimulated completions as well as in injection wells has been a primary goal in selecting methods to improve cost and operational efficiency. It is well accepted that perforating with shaped-charge jet explosives has had a large impact on the efficiency of oil and gas completions in cased wells. However, accurate predicting of the impact of different perforating systems or operations can be difficult, as there are many variables in the process that can not be easily quantified; therefore, modeling the detailed physics of the process is complex.

This paper examines perforating as it relates to injection wells and/or injection processes. Experiments using field shaped-charge explosives were conducted under a variety of conditions with different cores to quantify injectivity compared to productivity. Results from the laboratory experiments were then compared to field data for validation. New knowledge and insights are gained to better understand and to optimize the design of injection processes in sand control completions and completion processes in injection wells.
A Coalbed Methane Reservoir Simulator Designed and Developed for the Independent Producers
Authors: Jalali Jalal , Mohaghegh Shahab D.
Published: December 2007

There are many coalbed methane reservoir simulators in the market. The two most important characteristics of these models that, for all practical purposes, put them out of the reach of most of the independent producers are their price and complexity of use. In order to effectively use these commercial simulators, the average CBM producer must have at least one dedicated engineer, preferably with a graduate degree, on the staff that is willing and capable of performing effective modeling and simulation. It seems that the commercial simulation packages have been designed for majors, large independents and consultants. This leaves the majority of independent producers that are in the business of CBM production in a class by themselves. The model that is presented in this paper targets this class of CBM producers.

A new CBM reservoir simulator has been developed at West Virginia University in order to address this specific need of our industry, specifically in the northeast of the United States where new interests in coalbed methane have been growing steadily. The WVU CBM model uses a previously developed legacy code by King and Ertekin at PSU as its point of departure. The nearly twenty year old King & Ertekin's formulation which has been verified and proven to be robust, forms the foundation of WVU CBM model. The WVU CBM model is PC-Windows based and has a user friendly and graphical interface. The PSU model used a commercial solver that if was used in this model it would have made it prohibitively expensive for the independent producers. A new solver was developed and is used in this model. The new WVU CBM model is a single-well radial model with a graphical input interface that includes default values for the Pittsburgh coal for all parameters in case some of the values are unavailable. It generates graphical outputs in form of gas and water production rate vs. time, cumulative production vs. time, pressure, saturation and gas desorption distribution throughout the reservoir. It allows for production scheduling for detail history matching process. It lets the user to plan hundreds of runs in the form of a batch file that can be run over night.

The model has a unique feature that allows user to provide input parameters in the form of probability distribution functions with minimum, maximum, and, if they choose, most likely values instead of crisp numbers. The output in such cases will be probability distribution functions rather than crisp numbers. The WVU CBM model will be available to the industry through our web sites.
New PDC Bit Technology, Improved Drillability Analysis, and Operational Practices Improve Drilling Performance in Hard and Highly Heterogeneous Applications
Authors: Mensa-Wilmot Graham , Douglas Charles , Schell Eddie
Published: December 2007

The application envelopes of PDC bits have conventionally been defined by rock hardness. Although technologies1,2, 3, 4 aimed at improving PDC bit efficiencies in challenging drilling environments continue to be developed, performances in such applications still lack consistency. It has become apparent, from drilling performance evaluations, that formation hardness alone can not be used to categorize PDC bits.

In some instances, PDC bit performances have varied profoundly across given fields, even when formation types and tops, lithologies and hardness have been determined to be comparable. These performance differences, which continue to baffle the industry, amplify with increasing formation heterogeneity especially in hard rock environments.

This paper will present a three part process, which has been developed to address the challenges described above. First a new approach, which characterizes rocks by their drilling difficulty, is used to establish field trends. Considering offsets, or anticipated performance requirements, bit development and/or selection is done with the aid of two new parameters – stress and durability equivalencies. Finally, operational practices aimed at enhancing the effectiveness of this new process are developed and implemented. This paper will quantify and discuss the individual and combined effects of these processes.

Analytical, laboratory and field data, showing the effectiveness of this new methodology, will be presented.