bluuebunny/crossref_metadata_2025 huggingface dataset:
Understanding Post-Expansion Properties of Solid Expandable Tubulars
Authors: Butterfield Chuck , Flaming Sarah , Lebedz Rodger , Thigpen Michael , Hill Rick
Published: December 2007

As an enabling technology, solid expandable tubulars continue to revolutionize the design and construction of oil and gas wells. Although solid expandable systems are now widely accepted as a viable casing alternative, some operators do not apply the technology in their wells. Limited information regarding the tubulars' post-expansion performance properties creates uncertainty in the application of solid expandable tubulars. A better understanding of how the pipe properties are affected by the expansion process is imperative to optimizing the benefits of system application.

Using American Petroleum Institute (API) performance equations on post-expanded tubulars do not clearly identify the limits of the pipe. Testing is underway to create accurate predictive models for expansion force and post-expansion collapse. These full-scale laboratory tests, using API methods where applicable, determine how the expansion process changes collapse resistance and residual stress. Pre and post expansion mechanical and material properties are analyzed using American Society for Testing and Materials (ASTM) methods. Testing for H2S and CO2 environments employ the NACE methods.

This paper describes the testing procedures and results of the post-expansion performance property testing. These findings will be compared and contrasted to API standards for conventional pipe. In addition, the paper will discuss industry implications for determining solid expandable tubular standards.
What Software Do We Expect? An Engineering View vs. IT View
Authors: Wang Sharon , Woo George , Chen Zhongming
Published: December 2007

In today's modern computing era, computer applications have become indispensable for engineers to do their work. Some software works well, meeting technical requirements and expectations, while others are not very effective because of their instability, unfriendly user interface, or difficulty to use. Since computing is a typical skill of engineers and the engineers also know the solutions for the particular problems, it is common for them to write programs for their own needs. However, as a project and application grow bigger and more sophisticated, the problems related to application software design and architecture, which impact software extensibility without degrading the software performance, become apparent. When a program is written without concern for overall design, the maintenance of the software becomes more costly and difficult. Alternatively, a program developed by an individual who lacks the necessary technical background, may not be intuitive to use or may not address all technical needs of the engineer. A good program not only must meet the business requirements and specifications necessary to provide engineering solutions, but also must be user-friendly, and intuitive for users to learn and use easily. Thus, the users can focus on their specific job instead of struggling with a confusing manual, or trying to avoid causing a software crash. Understanding the business domain and prospective user's practice helps developers create more useful tools.

This paper discusses the cause of the problems in software quality from the perspective of both the user and IT professional on complexity and facilitation, extensibility and adaptability of software. The paper also proposes some suggestions for IT professionals to develop quality, favorable application software for users. It also provides guidelines for engineer users and project managers to evaluate and purchase software.
Using Ultrasonic Techniques to Accurately Examine Seal Surface Contact Stress in Premium Connections
Authors: Hamilton Kirk , Wagg Brian , Roth Tim
Published: December 2007

One of the most important functions of a tubular connection is sealability. This is especially the case for premium connections which are commonly used in the demanding conditions of HPHT and Thermal Well applications. Sealability therefore also is one of the most important criteria used during connection qualification in which the capability of the connection is verified for the characteristics of the application. During qualification tests it has been found that breakdown in connection sealability can be traced to damage on the primary seal surface, which can eventually develop into a leak-path.

Ultrasonic inspection technology can be used to provide a means to obtain non-intrusive measurements of contact stress between two mating metal surfaces separated by a thin lubricating film. While the technology has a wide scope of potential applications in this respect, the technology has been specifically developed to measure seal surface contact stresses inside oilfield tubular premium connections.

This application of ultrasonic technology has been used numerous times during connection qualification programs to assess the quality of the contact stress band in premium connections. During these analyses the technology has been able to detect scratches, galling, pock-marks, and other types of seal surface damage in a wide array of premium connection designs. Most of these flaws cannot be detected on the torqueturn curves generated during connection makeup. Moreover, mechanical separation of mating premium connection seal surfaces under tensile and compressive loads has been observed using this technology.

This paper will cover the basic concepts of premium connection design, as well as some of the issues that can affect the sealability of premium connections. As well, this paper will include an overview of the use of ultrasonic technology as a technique to assess the contact stress along the metal-to-metal seal band of a premium connection, and methods used to monitor changes in the contact stress profile induced by many installation and service loads.
Extreme Temperature ESP Development
Authors: Tetzlaff Steve , Wonitoy Kelvin , Ward Brad , Burleigh Lawrence , Dodds Adrian
Published: December 2007

Efforts to develop electrical submersible pumping (ESP) system technology for harsh environment applications has resulted in equipment designed and developed specifically for applications in higher temperature wells. This paper will discuss the development evolution of this equipment through Centrilift's state-of-the-art high temperature test facility "hot loop" and continuing development by field operations in Canadian SAGD applications.

Internal Development

The utilization of a state-of-the-art test facility that can be entered and exited at strictly planned / controlled intervals where temperature, system cycling and system monitoring can be controlled in a safe environment, has been instrumental in advancing the ESP equipment technology to a satisfactory operational level at 200° C – 220° C (392° F – 428° F) environments. This facility allows the equipment component design and materials evaluation to proceed quickly and under controlled procedures, with the end result being a fully tested and evaluated system for field applications. Several equipment modifications based on the test results will be discussed.

Field Testing/Development

The utilization of customer owned producing wellsites for initial application of the extreme temperature equipment is critical for the final ‘live’ well test of the design and tweaking of minor issues that would be difficult to detect under cleaner and controlled lab type environments. Further equipment design focus beyond 250°C will be dependent upon SAGD operators' targets and requirements.
Case Study: Drillstring Failure Analysis and New Deep-Well Guidelines Lead to Success
Authors: Bert David R. , Storaune Anders , Zheng Nanjiu
Published: December 2007

Three drillstring fatigue failures occurred while drilling two deep wells below 16,500 ft true-vertical depth (TVD) in the U.S.A. midcontinent region. All the failures occurred across 2°/100 ft to 3°/100 ft dogleg severity intervals from 6,000 ft to 8,000 ft. The well conditions (i.e., pipe condition and directional plan) were not significantly different from other deep wells in the area, which had not failed.

A deep-well drillstring failure study was conducted which included a review of drillstring inspection reports, daily drilling reports, digital data, technical literature, and engineering analysis for the two wells.

A Cumulative Fatigue Analysis (CFA) modeling technique taking into account specific well conditions (i.e., wellbore geometry, rotary speed, rate of penetration, hook load, and drillstring configuration) was applied. The model indicated that drillstring failures would occur across shallow doglegs mainly because of high hang-down loads combined with slow rate of penetration (ROP). The results of the study led to the development of new deep-well design criteria and implementation of new drilling guidelines. The new guidelines included utilization of look-ahead CFA modeling when approaching drillstring endurance limits to minimize drillpipe fatigue failures.

Look-ahead CFA modeling and the new drilling guidelines were used on two subsequent deep wells in the area, leading to successful drilling to total depth (TD) of 18,000 ft TVD without failure. One of the wells had a 1.4°/100 ft dogleg severity (calculated based on 100 ft survey spacing) at 1,500 ft and drillpipe shuffling was required to prevent drillstring failure in the deep hole section. The drillstring fatigue failure prevention guidelines apply to deep wells drilled worldwide.
Acoustic Determination of Pump Intake Pressure in Wells Producing Low-API-Gravity Crude
Authors: McCoy J. N. , Rowlan O. L. , Podio A. L. , Brunings Carlos A. , Riviere Armando
Published: December 2007

The acoustic determination of the pump intake pressure in wells producing viscous low API gravity crude is presented in this paper. These wells have liquid above the pump and the pump is set above the formation and gas flowing upward through the gaseous liquid column. The method to determine the pump intake pressure involves the acoustic measurement of the liquid level and the casing-pressure buildup rate when the casing head valve is closed. When these data are used with this paper's new empirically derived correlation for viscous crudes, then an accurate gradient of the gaseous liquid column in the annulus is obtained. This new correlation provides a more accurate correction of the gaseous gradient of the fluid above the pump intake for wells producing viscous crudes.

Results are presented from field testing of numerous wells where the actual gradients of gaseous liquid columns were measured is wells having a variety of gas flow rates and an oil gravity in the range of 10 degrees API. A back pressure valve is used to increase and stabilize the casing head pressure and the valve is used to depress and to stabilize the liquid level at different depths while the well is produced at a constant rate. Over a period of many days the acoustic measurements to the stabilized liquid levels are acquired. The gradient of the gaseous liquid column is then calculated and the pressures are extrapolated to the pump intake depth. Development of a new correlation from the analysis of this field data improves the accuracy of pump intake pressure determination in wells producing viscous low API gravity crude.
Modeling the Mechanical and Phase-Change Stability of Wellbores Drilled in Gas Hydrates by the Joint Industry Participation Program (JIPP) Gas Hydrates Project, Phase II
Authors: Birchwood R. A. , Noeth S. , Tjengdrawira M. A. , Kisra S. M. , Elisabeth F. L. , Sayers C. M. , Singh R. , Hooyman P. J. , Plumb R. A. , Jones E. , Bloys J. B.
Published: December 2007

In April 2005, the Chevron Joint Industry Participation Project (JIP) on Gas Hydrates organized a drilling and coring expedition to potential gas hydrate sites in Atwater Valley and Keathley Canyon in the Gulf of Mexico. In support of these activities, methods were developed to predict the mechanical and phase change stability of boreholes drilled in sediments containing gas hydrates.

Models of mechanical failure and downhole temperature were constructed from seismic and log data for the wells in Atwater Valley and Keathley Canyon. Model results were compared with LWD caliper, image, and temperature logs in three boreholes. LWD logs were also used to assess drilling performance.

Mechanical failure models compared favorably with deformation features observed in image logs in all three wells. An excellent match was also obtained between the modeled and measured downhole temperatures in Atwater Valley. However, for reasons that remain unknown, temperatures observed in the Keathley Canyon wellbore were generally lower than those predicted by the model.

Time-lapse analysis of LWD data revealed that the equivalent circulating density (ECD) in Atwater Valley became abnormally high and coarse-grained solids were falling into the BHA annulus from uphole causing packoffs. These packoffs eventually caused the rotary to stall. Some evidence that the packoffs were caused by shallow water flows discharging large quantities of sand into the wellbore was found.

Post-drill temperature simulations indicated that the LWD boreholes in Atwater Valley and Keathley Canyon were sufficiently cool to prevent hydrate from dissociating, owing in part to successful management of circulation rates in the borehole. It was also shown that loop currents at Atwater Valley helped to reduce the risk of dissociation.
Use of Advanced Optimization Techniques To Manage a Complex Drilling Schedule
Authors: Irgens Morten , Lavenue William Lashar
Published: December 2007

Description of the Material

Rig schedules are major components of operating plans and a main connection point between reservoir management and operations. It is therefore of importance that rig scheduling is done well.

As the number of drilling and workover rigs in use at Saudi Aramco has increased, the challenge of scheduling their use and transportation has grown exponentially. Ensuring that the right rig is in the right place at the right time, while minimizing rig movements and costs, is practically unmanageable using a manual approach. Consequently, Saudi Aramco has implemented an automated schedule optimization application. This interactive application supports schedulers in their daily work, and re-optimizes rig schedules as operational changes render previous plans invalid.

Application

Recent advances in optimization technology address complex, dynamic situations, and show the tangible value of operational decision-making in real time. Saudi Aramco has developed a software application where the rig schedule is optimized against multiple objectives, disruptions to the schedule is quick and easily managed, the impact of scheduling decisions on user-defined key performance indicators is immediately displayed, and schedule optimization is supported by a sophisticated user interface enabling direct schedule manipulation in response to changing needs.

Saudi Aramco has used this project to investigate how recent technological advances can turn rig scheduling into a continuous operational task that improves the alignment of daily decisions with long-term strategic objectives. The deployed rig scheduling system is thus designed for both planning and operations and allows for managing the rig fleet while optimizing on both operational and strategic objectives,. It also allows for rapid rescheduling when changes and disruptions occur.

Results, Observations and Conclusions

Early results are convincing and show showed reduced planning time, reduced response time, improved work processes, reduction in scheduling errors, improved "what-if" abilities and decision-making, reduction in transportation cost, and increased expected production. Laboratory experiments indicated an improvement in travel cost of 35% and in production of 25% over common schedule construction methods.

Significant New Contributions

The new application brings near real-time automation to a previously manual process, and applies optimization technology to dynamic, mission-critical operations, offering tangible benefits.
New Analytical Techniques To Help Improve Our Understanding of Hydraulically Induced Microseismicity and Fracture Propagation
Authors: Eisner Leo , Fischer Tomas , Jechumtálová Zuzana , Le Calvez Joel , Hainzl Sebastian , Boušková Alena
Published: December 2007

A multistage hydraulic fracture treatment was performed on a producing well in a mature tight gas field in West Texas and induced microseismic activity was monitored from a nearby observation well. The objective of this microseismic monitoring campaign was to determine the overall geometry of the hydraulically induced fractures in the Canyon sandstone formation. Information and results initially derived from the microseismic interpretation were used to provide the operator with recommendations for reservoir management such as drilling patterns, new well placement, and completion practices.

Microseismic events were located with a newly developed location technique based on S-wave back-azimuth. While originally a couple of hundreds of induced events per stage were mapped, this new processing technique leads to the detection and location of several thousands of events per stage. This increase of mapped microseismic events provides following insights into reservoir management.

First, initial gaps in located seismicity appear to be artifacts owing to the monitoring geometry, not shear shadow as commonly interpreted. The additional located microseismic events show greater fracture system length and height, thus confirming the effectiveness of the treatment. We also show that the upward component of the vertical propagation is more developed than the downward component, resulting in vertical connection of the first three stages of the stimulation.

Second, the high density of located microseismic events allows us to define the velocity of the fracture system propagation along both the horizontal and the vertical directions. On average, the fracture system propagates horizontally at 12–15 ft/min eastward. The observed hydraulic fracture systems propagated slower toward the west, resulting in an asymmetric fracture with twice shorter western wing. Vertical propagation speed of fracture propagation is similar in sandstone layers, however it slowdown in the vicinity of shale barriers as expected.

Analysis of the source mechanisms of induced seismic events reveals that more than 80% of the representative events have a nonshear component of source mechanisms. This observation implies that the induced microseismic events are directly connected with the created fracture and represent movement of the injected fluids.
Inflow Performance Relationship (IPR) For Solution Gas-Drive Reservoirs—Analytical Considerations
Authors: Ilk D. , Camacho-Velázquez R. , Blasingame T. A.
Published: December 2007

This work provides the analytical development of "Vogel"-type Inflow Performance Relation (or IPR) correlations for solution gas-drive reservoir systems using characteristic flow behavior.

Specifically, we provide the following results:

An analytical form of the quadratic (Vogel) IPR correlation: q o q o , max = 1 − v [ p w f p ¯ ] − ( 1 − v ) [ p w f p ¯ ] 2 Where the v-parameter is defined for the solution gas-drive reservoir case using the oil mobility function (i.e., [(ko/(μoBo)]) — this definition is given by: v = 2 [ k o / ( μ o B o ) ] p ¯ = 0 [ k o / ( μ o B o ) ] p ¯ + [ k o / ( μ o B o ) ] p ¯ = 0 The analytical form for a cubic IPR correlation: q o q o , max = 1 − α [ p w f p ¯ ] − β [ p w f p ¯ ] 2 − γ [ p w f p ¯ ] 3 The analytical form for a quartic IPR correlation: q 0 q 0 , max = 1 − ε [ p w f p ¯ ] − σ [ p w f p ¯ ] 2 − η [ p w f p ¯ ] 3 − θ [ p w f p ¯ ] 4

The practical value of this work is that we have proven that an IPR can be written for a given solution gas-drive reservoir system directly from rock-fluid properties and fluid properties.

The "theoretical" value of this work is that we provide a "characteristic" formulation of the oil mobility profile [ko/(μoBo)], which is given as:

[ 1 − [ k o / ( μ o B o ) ] p [ k o / ( μ o B o ) ] p i ] =         1 − ζ [ p ¯ p i ] + ( 1 − ζ ) [ p ¯ p i ] 2 − 2 ( 1 − ζ ) [ p ¯ p i ] 3 ( ζ ≤ 1 )

This proposed "characteristic" mobility model is validated against numerical simulation results from the literature and from work performed as part of this study. Note that the characteristic mobility is only a function of the characteristic parameter (ζ), the initial and average reservoir pressures (pi and p¯), and the oil-phase mobility evaluated at the initial reservoir pressure [ko/(μoBo)]pi.
Fluid Production and Injection Induced Stress Changes Using Reservoir Volume Changes Inverted From Tiltmeter-Based Surface Deformation Measurements
Authors: Du J. , Maxwell S. C. , Warpinski N. R.
Published: December 2007

Production and injection induced stress changes are in some circumstances, an important issue in field development and reservoir management. Previously, induced poroelastic stresses have been calculated by integrating the center of a dilatation source over a certain reservoir region.1,2 However, this approach has difficulty when the observation points lie inside the reservoir blocks. This paper presents the application of an analytical stress solution due to an initial (eigenstrain or transformation) strain in a cuboid3 to calculate the induced stress changes using the volume changes inverted from the tiltmeter-based surface deformation measurements.4,5 Arbitrary strain volumes can then be constructed from an assemblage of discrete cuboids, allowing stresses both within and outside the strain zone. The stress calculation formulation was applied to a field case study where a warm-up phase of steam injection into a steam assisted gravity drainage (SAGD) well pair was monitored with an array of surface tiltmeters and a downhole microseismic array6. Using a Mohr-Coulomb failure criterion, predicted locations of failure are compared with the actual locations from the microseismic monitoring.
A Predictive Pore-Scale Model for Non-Darcy Flow in Anisotropic Porous Media
Authors: Balhoff Matthew T. , Wheeler Mary F.
Published: December 2007

Non-Darcy flow is often observed near wells and in hydraulic fractures where relatively high velocities occur. In these regions an empirical model, Forchheimer's equation, is used in place of Darcy's law. It includes a quadratic correction to the linear model and has been adequately fit to many experimental data sets, while found to be insufficient in others. Furthermore, a number of numerical and theoretical approaches have shown limitations of the Forchheimer model in the laminar flow regime. It is important to understand the applicability of Forchheimer's equation and to be able to obtain good predictions of macroscopic properties so that nonlinear flow may be properly modeled in reservoir simulators.

In this work non-Darcy flow is modeled using a physically-representative1 pore-scale network model. Quantitative and predictive results are obtained using both computer-generated porous media and real sandstones digitized through x-ray computed microtomography (XMT). The permeability and non-Darcy coefficient, β, are determined for these isotropic and anisotropic media where Forchheimer's equation is applicable. The numerical model is compared to existing experimental data and good agreement is found. Furthermore, limitations to Forchheimer's equation at both low and high velocities are determined and discussed.
Detection of Fracture Corridors from Openhole Logs in Horizontal Wells
Authors: Ozkaya Sait. I.
Published: December 2007

Fracture corridors are sub-vertical tabular bodies of fracture swarms which traverse vertically entire reservoir thickness and extend laterally for several tens to hundreds of meters. Fracture corridors are genetically related to faults or incipient faults and are the main building blocks of fracture systems in many reservoirs in the Middle East. Fracture corridors are best identified from horizontal borehole image logs, but the number of wells with image logs is often limited and it is necessary to use indirect means to detect fracture corridors. Fracture corridors manifest themselves as spikes in horizontal well openhole logs. In fields with water injection, fracture corridors can be identified as water saturation spikes with no corresponding change in porosity. Fracture corridors with cemented walls have bulk density spikes. In many cases fracture corridors are associated with caliper enlargement and lost circulation. In some Middle East carbonate reservoirs fracture corridors appear as gamma ray spikes.

Fracture corridors are not the only cause of openhole log spikes. It is necessary to validate and determine fracture corridor signatures in openhole logs by comparing open hole and image logs first. If a diagnostic signature can be recognized, openhole logs, in combination with lost circulation data, can be used to locate fracture corridors in other horizontal wells with no image logs. If there are a sufficient number of image logs from horizontal wells with fracture corridors, it is possible to correlate spikes with actual fracture corridors and determine the probability to correctly identify a fracture corridor.
Identification of Pay Zones Using Compressional Wave Velocity and Shear Wave Velocity Data in Sandstone Reservoirs
Authors: Hamada G. M.
Published: December 2007

Sonic travel time of compressional wave is generally used as porosity tool for given lithology. Introducing shear wave travel time is very helpful in determining mechanical rock properties. It is found that compressional wave is sensitive to the saturating fluid type. The use of the ratio of compressional wave velocity to shear wave velocity "Vp/Vs" is a good tool in identifying fluid type. The fact that compressional wave velocity decreases and shear wave velocity increases with the increase of light hydrocarbon saturation, makes the ratio of Vp/Vs more sensitive to change of fluid type than the use of Vp or Vs separately. Field examples are given to identify fluids type (water, oil and gas) using the Vp/Vs ratio. Field examples have shown that shear travel time decreases while compressional travel time increases when the water saturated points become gas or light oil saturated points in the studied sections. The decrease of shear travel time (increase of shear wave velocity) is due to the decrease of density and the absorption of deformation by free gas in pores. The increase of compressional travel time (decrease of compressional wave velocity) is due to the decrease of bulk modulus of reservoir rocks which compensates the decrease of rock density.
Neural Network Identification of Hydrocarbon Potential of Shaly Sand Reservoirs
Authors: Elshafei Moustafa , Hamada Gharib M.
Published: December 2007

Hydrocarbon potential evaluation of shaly sand layers requires the adoption of certain shaly water model and also the selection of suitable conventional logging suite. The main target is how to get the accurate porosity and how to convert the apparent water saturation to true water saturation for given shaly sand layer. In this paper neural network approach is presented to replace the conventional interpretation of well logging data to better determine formation porosity and water saturation and to identify hydrocarbon potential of clean and shaly sand layers.

Two neural networks were constructed, one for prediction of porosity using six well logging data inputs: GR, LLD, RHOB, NPHI, PEF and t); and water saturation using 5 well logging data inputs: GR, LLD, RHOB, NPHI and PEF. Shale volume was defined from GR data. Four wells were used in this study. The core data from two wells are used to train and validate the neural networks for prediction of the formation porosity and water saturation. Network outputs have shown good matching with core data and the reference calculated petrophysical parameters. A hydrocarbon potential index is then defined based on cutoff values of porosity, water saturation, and shale volume. The trained neural networks together with the hydrocarbon potential index were used to predict possible pay zones in the four wells. The developed network approach has successfully deduced porosity, water saturation and defined pay zones in the four wells
Asphaltene Cleanout Using VibraBlaster Tool
Authors: Al-Ghazi A. S. , Lawson Justin
Published: December 2007

Remediation of heavy organic deposits of asphaltene in the course of oil production has been a costly process and it has hampered the production activities. Well 1 was initially put in production on December 14, 2005, but it failed to flow against the flow line pressure of 260 psig and later against a reduced HPTT pressure of 50 psig. Heavy asphaltene emulsion solids were found to be completely obstructing the tubing, which could not be subsequently displaced or cleaned out by bullheading either water or Xylene.

To break up the asphaltene and restore the productivity of Well 1, the following options were considered: bullheading water, xylene wash, rotating nozzle CT, workover and using the VibraBlaster™ tool. In January 2006, water bullheading was first attempted with no success. In March 2006, xylene wash was attempted, again with no success. In August 2006, the VibraBlaster™ tool was deployed with coil tubing and attempted to remove the emulsions using the tool's vibration and reciprocation, combined with its high velocity jetting. The VibraBlaster™ tool succeeded in breaking up the solid asphaltene accumulations on the Christmas tree and the first 1900‘ of tubing, restoring the well's production with a current oil rate of 10.7 MBOD and 0% water cut at 26/64" choke setting. Close subsequent observation of the well confirms that it is behaving like a normal GOR well, while crude samples also indicated normal levels of asphaltene (2–3%).
Understanding Stress Dependant Permeability of Matrix, Natural Fractures, and Hydraulic Fractures in Carbonate Formations
Authors: Abass H. H. , Ortiz I. , Khan M. R. , Beresky J. K. , Sierra L.
Published: December 2007

Most carbonate reservoirs behave as dual porosity-permeability systems in which the rock matrix and both natural and created hydraulic fractures contribute to the hydrocarbon transport in a very complex manner. Understanding the behavior of the permeability of the matrix frame, natural fractures, and created hydraulic fractures, as a function of reservoir depletion, is vital to designing optimum stimulation treatments and to maximize the carbonate formation's exploitation.

Core samples were selected from a carbonate reservoir and a testing procedure was applied to determine the stress dependant permeability as a function of various combinations of effective stresses. A tensile natural fracture was simulated by splitting a whole core by failing it under tension using a Brazilian test procedure. The stress dependant permeability was evaluated under varied effective stresses simulating a reservoir depletion scenario. A shear fractured core was selected from a given carbonate formation and a stress dependant permeability was established. The tensile fractured core was then propped with a low concentration of small mesh proppants and the permeability of the simulated propped fracture was determined. Using a new reservoir simulator the testing results and selective functions were used to predict the production performance of a carbonate reservoir under the effect of the stress dependant permeability.

The experimental results indicate that the tensile fractures are much less conductive than shear fractures and the shear fractures are less conductive than propped fractures. The concept of effective stress within the rock matrix is totally different than that of natural fractures; therefore, the effective stress function for both matrix and natural fractures should be separately evaluated to obtain representative functions for any simulation study. The tensile fractures lose conductivity at very early stages of reservoir depletion. Recommendations to manage these tensile fractures for optimum hydrocarbon recovery are suggested.

Practical outputs of this work are: 1) Understand how natural fractures are controlled to efficiently contribute to well productivity, 2) Quantify the effective stress concept in the matrix and fracture systems, 3) Provide stress-dependant correlations for simulation studies.
Production –Log base Model for Effective Carbonate Management, Case Study Miocene Carbonate, the Gulf of Suez, Egypt
Authors: Fadel Sayed , Shalaby S. , Khattab H. , Attia A. M. , Desokey S.
Published: December 2007

Carbonate rock are characterized by complicity of pore system. Variety of pore types associate with Variety of flow characteristics. The main characteristics affected by varying rock pore types are; Porosity-permeability relationship, Capillary pressure and relative permeability, and Archie cementation factor (m).

Many pore systems could be existed in heterogeneous carbonate. Discriminate the different pore types in vertical and lateral directions through heterogeneous carbonate are a difficult task but essential for reliable evaluation and effective management of carbonate reservoirs. Conventional log response and traditional log interpretations do not have the ability to discriminate the different pore types. So, discriminating rock pore type and flow units through heterogeneous carbonate, require integration for all available data. There are no universal applicable techniques to integrate the available data for recognizing the different pore type and flow units through heterogeneous rock.

This paper introduces an approach to correlate the conventional log data with the production results of the old wells which were completed on heterogeneous Miocene carbonate reservoirs. A series of cross plots for the perforated intervals of highest and lowest productivity wells were constructed. These cross plot show a relationship between the well productivity and the position of log data on such cross plots. Based on this observation a relation between rock quality or productivity and conventional log data was established. The recently drilled wells data such as mobility from Modular dynamic tester (MDT), pressure transient analyses and core data confirm this relation.

This approach enhances understating the Miocene carbonate behavior and improves reservoir managements by:

Accurate reservoir evaluation and select perforated intervals Effective well completion and stimulation Effective managements the Miocene carbonate gas injection projects.

On other hand, Layering simulation models for the Miocene carbonate reservoirs based on flow characteristic enhance the model reliability and prediction of the reservoirs behavior under different depletion schema.
Using Pressure Gradient Survey as a Cost-Effective Diagnostic and Decision-Making Tool
Authors: Al-Mousa T. S. , Mohammad S. K. , Dashash A. A. , Al-Mubairik A. J.
Published: December 2007

Locating the water entries in an oil producer is critical for the success of remedial work, such as acid stimulation and water shut off, to prolong the life of the well and enhance production. Different logging tools are successfully used to obtain this information such as PLT. Practicality of using these logging tools can be limited. A good example of these limitations is a well that can not flow or sustain flow to surface (dead well).

Therefore, in addition to the historical data, previous PLTs, water drive mechanisms for such wells, along with the well performance history, the pressure gradient survey approach is used to come up with best estimate of static OWC in vertical or slightly deviated wellbores.

This paper will answer the questions of when, and why conduct a pressure gradient survey and the optimum running procedure by discussing the utilization of the pressure gradient survey as a diagnostic and decision-making tool in a few case histories from the Ghawar filed in Saudi Arabia will be discussed.
Experimental and Statistical Analysis of Shaly-Sand Evaluation Using CEC-Dependent Parameters
Authors: Kurniawan B. , White C. D. , Bassiouni Z.
Published: December 2007

A new CEC shaly sand model incorporates two cementation exponents to represent the tortuosity of two distinct conductive paths in the free- and clay-bound-water of shaly sandstone reservoirs. The validity of the model was experimentally tested. Laboratory resistivity measurements were performed on three rock types, clean sand, shaly sand and pure shale with varying water salinity. The cementation exponents were determined from clean and pure shale samples and used in the calculation of shaly sand conductivity. The most critical case of low water salinity shaly sands received particular attention.

Monte Carlo simulation evaluated the uncertainty of water saturation estimates, assuming both correlated and uncorrelated conductivity and porosity. Correlation structure was preserved using the Cholesky factor of the parameter covariance matrix. The uncorrelated simulation yielded sensitivity estimates that were statistically insignificant, whereas the correlated analysis revealed a strong sensitivity of water saturation to rock conductivity. Because parameters such as rock conductivity and porosity are commonly strongly correlated, naive uncorrelated Monte Carlo simulation may understate the sensitivity of water saturation to rock conductivity (in this case, by a factor of almost six).

The new model substantially reduces the estimation error of conductivity of low salinity shaly sand samples (by 10 to 15 percent) compared to a single cementation exponent model. The calculated water saturation was validated with production and special core analysis data in a zone with low formation water salinity. The validity of the model was also tested using field data. The water saturation estimated for actual field cases were more representative of the hydrocarbon potential in the subject reservoirs derived from production and special core analysis data.
Composite-Fracturing Plug Reduces Cycle-Time in a Coalbed Methane Project
Authors: Rodvelt G. D. , Oestreich R. G.
Published: December 2007

Shallow coalbed methane (CBM) projects can have multiple pay zones available for completion. Cased-hole completions allow zonal isolation to direct treatments, but re-establishing a connection to a coalseam through drilling and cementing damage may require high breakdown pressures even with an acid spearhead. Isolating individual zones to help ensure completion effectiveness is paramount to a successful completion.

This paper details the use of composite epoxy-glass fracturing plugs to reduce time to complete, drill out, and clean up wells drilled in the Southern Illinois Basin (SIB) project. Over 80 wells have been completed in multiple stages using as many as three composite frac plugs to isolate four coals. Accurate placement of plugs by electric line to allow staging as close as 10 ft was accomplished without communication. These four-stage frac completions were accomplished in less than 8 hours before flowing back frac fluids from all zones. Less than a single day was required to drill out all the plugs, go to bottom, circulate clean, and prepare the wells to begin pumping. The authors compare this technique with the cost and time required to do completions with alternative isolation methods.
Petrophysical Parameters that Govern Hydrocarbon Production from a Low-Permeability Carbonate Formation at the Wattenberg Field in the Denver-Julesburg Basin
Authors: Yang Yuanhai , O'Connell Wally , Birmingham Thomas
Published: December 2007

In carbonate reservoirs, it has been commonly reported that natural fracture is the primary factor that governing hydrocarbon production. By a renewed investigation into the Niobrara low permeability carbonate at the Wattenberg field in the Denver-Julesburg basin (DJ), the authors have observed a series of petrophysical factors that can be reflected by well logs affect well performance. The conventional well logs have been used to calculated or estimated these petrophysical parameters, which include irreducible water saturation calculated by the resistivity and porosity; solution gas oil ratio computed from the neutron and density; pore structure connectivity reflected by the spontaneous potential; the proximity to faults inferred from the density correction log; and original high reservoir pressure determined from changes in resistivity and neutron of overlying shale.
CO2 Restimulation in the Michigan Basin: A Second Chance for the Prairie Du Chien
Authors: Edwards J. T. , Crafton J. W.
Published: December 2007

The Michigan Basin is widely viewed as having only mature reservoirs with limited availability for new treatment designs. The latest re-stimulation program using CO2 might give rise to the opportunity of enhanced production in Michigan as well as benefit new completions.

The Prairie Du Chien (a.k.a. PDC) is a sandstone formation with depths that vary from 8,000 to 11,000 feet and formation thicknesses ranging from 50 to 200 feet. Stimulation treatment designs over the past two decades since the PDC's initial drilling have been marked by vast differences in natural gas production numbers from wells within the same field. Re-stimulation treatments have included cross-linked fluid or nitrogen foam, providing mixed success rates. Problems such as excessive surface treating pressure, limited down-hole sand concentration, early screen outs, and water retention have been experienced in these stimulations. Many existing wells within established PDC fields have declining production numbers despite reasonable reservoir pressure still present.

Formation characteristics and well history will be detailed to shed more light on the current wells and re-stimulations taking place in the PDC. The advantages of the CO2 treatment design marked with increased fluid recovery capabilities by gas assist along with the hydrostatic advantages will be expanded upon. Treatment design details with pressure response along with production results from the first set of wells will be included.

This paper will expand re-stimulation ideas as well as spur a desire for further investigation into the use of CO2 in the Prairie Du Chien. It also hopes to change the perception of the Michigan Basin to one of a viable, rediscovered source of natural gas in the ever tightening world supply.
Modeling Incremental Swelling of Coal Matrix with CO2 Injection in Coalbed Methane Reservoirs
Authors: Mitra A. , Harpalani S.
Published: December 2007

In the enhanced coalbed methane production (ECBM) option involving injection of CO2 in a coal-gas reservoir, the injected CO2 induces incremental swelling of the coal matrix. This is believed to result in a significant reduction in coal permeability, and thus the CO2 injectivity. This paper discusses the results of a study where swelling of the coal matrix was first measured with injection of methane and CO2. This was followed by injecting CO2 in the methane saturated sample, and measuring the incremental swelling for increasing CO2 concentration. The measured swelling with individual gases was then used to model the incremental swelling when CO2 is injected in a CBM reservoir.

The experimental results showed that the amount of swelling produced by CO2 is more than three times that produced by methane. The single-gas swelling data was fitted to a model based on the Langmuir Sorption Theory, and the agreement between the modeled and experimental data was excellent. Finally, the Extended Langmuir (EL) Theory was used to compute the incremental swelling for increasing concentration of CO2. However, the measured and modeled incremental swelling with increasing concentration of CO2 did not match very well. These results are in agreement with the reported finding that the EL Theory fails to accurately predict the sorption behavior of methane/CO2 mixtures. However, the technique serves as a means to estimate incremental swelling until improved methodology is developed to do so.
Integrated Uncertainty Assessment for Unconventional Gas Reservoir Project Development
Authors: Devegowda Deepak , Gao Hui
Published: December 2007

Meeting the gas demand-supply imbalance is crucial in addressing energy requirements for the future. An increasing percentage of the supply of gas will be sourced from unconventional gas reservoirs, for instance, tight sands/shales and coal bed methane reservoirs. However, while unconventional resources contribute an ever increasing fraction of the total gas supply, an integrated analysis and characterization of these reservoirs is often difficult owing to uncertainties associated with various parameters in reservoir and geologic description. Moreover, the high cost of data acquisition limits the amount of information available to build reservoir models.

The main goal of this paper is to provide a methodology for integrated assessment of the petrophysical, geologic and reservoir parameter uncertainties to provide decision makers a rational basis for managing uncertainties leading to improved decisions and resource management. The workflow involves identifying key parameters influencing uncertainties in recovery predictions through an Experimental Design/Response Surface methodology. The need to do a global sensitivity analysis motivates the workflow presented in our study.

The relevant parameters are used to build an emulator or an analog of the reservoir which is then used to rapidly provide performance predictions, taking into account the uncertainties associated with the parameters. The entire framework is applied to a case study to illustrate the cost and time benefits of such an approach. The significant contribution of such an analysis is identifying the effects on reservoir performance due to uncertainties associated with characterizing the reservoir leading to an informed and rational decision making process with significant cost savings and a reduction in computational effort.
Understanding the Effects of Drilling Parameters on Hole Cleaning in Horizontal and Deviated Wellbores Using Computational Fluid Dynamics
Authors: Bilgesu H. I. , Mishra N. , Ameri S.
Published: December 2007

Increased demand for energy resulted in the expansion of drilling activities worldwide. Any improvement in terms of well planning and drilling operation can result in significant savings for the operator. A good plan includes all information from offset wells as well as sound engineering principles and it relies on subsurface characteristics and operating conditions. While formation properties are not controlled by drilling, the operational parameters can be modified to improve the drilling operation on a real time basis. Thus it is important to study the operational factors affecting the performance of a rig. Particularly, understanding the parameters that control wellbore cleaning is beneficial in both horizontal and deviated wells.

In this study, a section of casing-drill pipe annulus section was simulated using Computational Fluid Dynamics (CFD) to determine the effects of different parameters such as fluid velocity, cutting size, rate of penetration, drill pipe rotation and inclination angle in deviated wells. The simulations were conducted at steady state and the results for maximum cutting concentrations in the annulus were analyzed. Formation of cutting beds is noticed near the entry section of the annulus and the transport of the cuttings in the annular section occurred in the form of stratified flow. Fluid flow rate, angle of inclination and rate of penetration have a major impact on cutting concentrations and proper prediction of these parameters are important to avoid formation of cutting beds. It is also noted that drillpipe rotation can enhance cutting transport but it generally has a greater effect on smaller sized particles.