bluuebunny/crossref_metadata_2025 huggingface dataset:
Fractured-Well-Test Design and Analysis in the Presence of Non-Darcy Flow
Authors: Gil J. A. , Ozkan E. , Raghavan R.
Published: December 2007

The objective of this paper is to discuss the design and analysis of fractured-gas-well tests to account for fracture non-Darcy flow. The results and discussions are based on a semi-analytical model. Guidelines and correlations are presented to design fractured-well tests with tolerable influence of fracture non-Darcy flow. The effect of non-Darcy flow skin (or rate dependent skin) is discussed in detail. A method is also presented to analyze fractured-well tests under non-Darcy flow conditions to estimate the non-Darcy flow coefficient, fracture conductivity, and the reservoir properties. Unlike the conventional methods, this method does not require two tests at different production rates.
Measurement of Vertical Permeability Using a Dual Lateral Well in a Layered Reservoir
Authors: Gill Harmohan S. , Al-Thawad Faisal , Thuwaini Jamil S.
Published: December 2007

This paper presents a case study of a vertical interference test conducted in a single well. The investigation in this dual lateral completion was conducted to determine the effective vertical permeability between the pulsing horizontal lateral and the lower section of the vertical wellbore used for observation.

This case study showed the presence of a thin layer with extremely high permeability, which intersected both the horizontal lateral and the vertical wellbore (also referred to as a stratiform Super-K). Simulations along with geological and production log data indicated that the Super-K layer was not aerially extensive. Because of the layered nature of the reservoir, presence of a Super-K layer and the multiphase conditions, a numerical well test simulator was used to analyze the horizontal well buildup and the vertical interference test.

The test was designed to be able to analyze the horizontal well pressure data in conjunction with the pulse interference data for better reservoir characterization. The paper details the steps followed in this successful integration of all sources of data in the test analysis.
Analysis of Pressure Transient Test of Non-Newtonian Fluids in Infinite Reservoir and in the Presence of a Single Linear Boundary by the Direct Synthesis Technique
Authors: Katime-Meindl Irina , Tiab Djebbar
Published: December 2007

Non-Newtonian fluids are very common during drilling, fracture operations and enhanced oil recovery processes. When a reservoir contains a non-Newtonian fluid such as those injected during polymer flood or the production of heavy oil, well test data cannot be interpreted using Newtonian fluid flow models. The resulting analysis would be erroneous because non-Newtonian fluids behave rather differently.

These results suggest the need for a thorough study of the behavior of non-Newtonian fluids in the reservoir and also a new look at the flow of those fluids in porous media.

This study presents an interpretation technique for pressure behavior of non-Newtonian fluid flow in a homogeneous reservoir without type-curve Matching. The inclusion of a no-flow and/or a constant pressure line is also investigated.

First, the TSD (Tiab’s Direct Synthesis) technique was applied for analyzing the pressure behavior of a well located in (1) an infinite reservoir and, (2) near a linear boundary where wellbore storage and skin effects were considered. The analysis required the generation of type-curve sets for different wellbore storage and skin values.

A step-by-step procedure is presented for the calculation of the reservoir parameters: the permeability/viscosity ratio, wellbore storage coefficient, skin factor and the distance to the nearest boundary without the use of type-curve Matching. The procedure is illustrated by an example.
An Investigation of Horizontal Well Completions Using a Two-Phase Model Coupling Reservoir and Horizontal Well Flow Dynamics
Authors: Vicente Ronaldo , Sarica Cem , Ertekin Turgay
Published: December 2007

A fully implicit, three-dimensional simulator with local hybrid grid refinement around the wellbore solving reservoir and horizontal well flow equations simultaneously for liquid-gas flow systems is used to investigate the effects of permeability, gas saturation, well length, well diameter, reservoir anisotropy and perforation/slot phase angle on the well productivity behavior. In addition, the effect of the coil-tubing diameter on the two-phase production logging measurements is studied. The model implements the conservation of mass equations in the reservoir and conservation of mass and momentum in the wellbore for isothermal conditions. The establishment of the continuity of pressure and preservation of mass balance at the sandface satisfy the coupling requirements between the two computational domains. The hydrodynamic model for the wellbore is based on the homogeneous flow assumption.

In this paper, we show that the indiscriminate use of single-phase flow models to predict the productivity of horizontal wells producing under multi-phase flow conditions can lead to significant errors and the magnitude of the discrepancy increases with reservoir permeability and gas saturation. Also, for multiphase flow conditions, pressure drop along the wellbore plays a crucial role in the asymmetrical flux distribution profile and should not be ignored. The seriousness of the problem is considerably aggravated in long wells, slim holes, high permeabilities and high gas saturation systems. In some completion designs, the simulations have shown that 70% of the production comes from the first 1/6 of the total well length. In other examples, the last third of the well length contributes with less then 2% of the total production. It has been shown that in anisotropic systems, a more uniform flux distribution is obtained with openings aligned orthogonal to the larger permeability direction. Regarding to production logging applications, a significant deviation on the measurements and actual behavior can be observed, depending especially on the ratio between well and coil tubing diameter. The proposed model can be a useful tool in generating the appropriate corrections for the undesirable effects of the coil tubing on production logging measurements.
Numerical Simulation of Water Injection in 2D Fractured Media Using Discrete-Fracture Model
Authors: Karimi-Fard M. , Firoozabadi A.
Published: December 2007

Numerical simulation of water injection in discrete fractured media with capillary pressure is a challenge. Dual-porosity models in view of their strength and simplicity can be mainly used for sugar-cube representation of fractured media. In such a representation, the transfer function between the fracture and the matrix block can be readily calculated for water-wet media. For a mixed-wet system, the evaluation of the transfer function becomes complicated due to the effect of gravity.

In this work, we use a discrete-fracture model in which the fractures are discretized as one dimensional entities to account for fracture thickness by an integral form of the flow equations. This simple step greatly improves the numerical solution. Then the discrete-fracture model is implemented using a Galerkin finite element method. The robustness and the accuracy of the approach are shown through several examples. First we consider a single fracture in a rock matrix and compare the results of the discrete-fracture model with a single-porosity model. Then, we use the discrete-fracture model in more complex configurations. Numerical simulations are carried out in water-wet media as well as in mixed-wet media to study the effect of matrix and fracture capillary pressures.
Assessing Uncertainty in Channelized Reservoirs Using Experimental Designs
Authors: Friedmann F. , Chawathé A. , Larue D. K.
Published: December 2007

It is well established that uncertainty exists in simulated recovery forecasts due to the ambiguity in the measurement and representation of the reservoir and geologic parameters. This is especially true for immature projects, such as deep-water reservoirs, where the high cost of data limits the information that is available to build reservoir models. We present two strategies, based on Experimental Design, to quantitatively assess this uncertainty in recovery predictions for primary and waterflood processes.

We apply the Experimental Design methodology to channelized sandstone systems because of their relevance to many deep-water projects. We choose to study synthetic geological analogs of channelized systems that are built from panoply of relevant parameters while taking into account the uncertainty that exists in the estimation of their ranges. We use the results of this study to generate type curves with neural networks. The trained neural networks can be used to rapidly predict reservoir performance where field data is very limited. We discuss applications of this methodology on field cases from western Africa.
Real-Time Fracture Mapping from the "Live" Treatment Well
Authors: Wright C. A. , Davis E. J. , Ward J. F. , Griffin L. G. , Fisher M. K. , Lehman L. V. , Fulton D. D. , Podowski J. , Grieser W. V. , Special J. F.
Published: December 2007

The recent and dramatic increase in direct fracture mapping has profoundly altered our understanding of how fractures really do grow. New fracture-mapping technologies have allowed us to often directly measure what we could previously only model or assume. However, perhaps the greatest limitation of these new direct fracture-mapping technologies (tilt and microseismic) is the need for a nearby offset well in which to deploy instruments. In many environments, most notably offshore, there is often no feasible way to employ an offset observation well. Treatment well tilt mapping uses the fracture (injection) well itself as the "observation" well. The goal, quite simply, is to expand the range of environments where direct fracture mapping can be performed.

The concept is simple: if fracture-induced deformation can be measured thousands of feet away at the surface or in offset wells, then it most certainly can be measured in the fracture well itself. The measurement of fracture-induced tilt versus time and depth (via an array of 4 to 20 tiltmeters) can allow robust real-time mapping of fracture height and width. Fracture length is then "modeled" based on observed height and width, and inferred fracture fluid efficiency. Treatment well tilt measurements can also provide direct measurement of mechanical fracture closure aiding, among other things, the estimation of formation closure stress.

Mapping from the treatment well brings its own set of limitations and challenges. One is conducting minute wellbore movement measurements in the midst of a highvelocity flow stream. We have solved this challenge. Field data shows that the fracture-induced tilt signals in the treatment well are several orders of magnitude higher than those measured in offset wells, and they are much greater than the fluid-motion noise. The trickier challenge is deploying tools in a well during the pumping of proppant. So far we have performed real-time treatment well mapping only on fractures with clean fluid (i.e., no proppant), however, efforts are underway to overcome the difficulties with proppant. This paper provides an overview of the basic concepts, shows some real-data from treatment well applications, and presents one brief case study.
Proper Use of Proppant Slugs and Viscous Gel Slugs can Improve Proppant Placement During Hydraulic Fracturing Applications
Authors: McDaniel B. W. , McMechan D. E. , Stegent N. A.
Published: December 2007

When using hydraulic fracturing techniques to stimulate production from an oil or gas well, successful job placement is often jeopardized by near-wellbore (NWB) problems. Many times, these problems are specifically related to the perforation entry or to the width of the fracture near the wellbore. A likely conclusion is that insufficient width generation in the NWB region is the result of a tortuous (rapidly turning or twisted) path for the first few inches or feet of the fracture. Within this near-wellbore region, such fractures must overcome rock stresses greater than the least principle stress. In other instances, the inadequate width problem may result from the generation of a large number of independent near-wellbore fracture planes (starter fractures) instead of only one fracture (or at least only a few). Additionally, the hydraulic fracture may initiate from a fluid-filled microannulus rather than the perforations, which can lead to significant proppant-pumping limitations.

During the early 1990's, the oil industry began to consider these NWB problems more seriously. Procedures to help identify the problems were developed, and techniques involving proppant slugs and viscous gel slugs were used to mitigate such problems before or during a fracture-stimulation treatment. Alterations of the well completion plan proved to be a major part of successfully reducing the occurrence of similar problems in future wells in that reservoir. This paper discusses this technology and its evolution through recent years, as well as current applications of these techniques.
Experience in Acid Diversion in High Permeability Deep Water Formations Using Visco-Elastic-Surfactant
Authors: Chang F. F. , Acock A. M. , Geoghagan A. , Huckabee P. T.
Published: December 2007

It is a great challenge to divert acid into untreated zones in a thick, heterogeneous, and high permeability sandstone formation. The heterogeneity can be created by hydraulic fracturing, acidizing, or the nature of the reservoir. Common diverting agents do not work well in these situations. In high permeability porous media, foam has the tendency to segregate, gaseous phase will occupy smaller pores while the aqueous phase occupies the larger pores1. Due to the relative permeability effect, the higher permeability streaks becomes the preferable path for acid treatment fluids2. Therefore, limited effective diversion can be achieved by foam. Other diverting agents rely on particulate matter or polymer solution to plug off thief zones temporarily. However, the invasion of the undissolved particles and polymer residue can cause further formation damage.

Owing to its rheological properties, and its lack of solids, Visco-Elastic-Surfactant diverting agents (VESDA) have been proven to be effective for acid diversion in carbonate formations3, where large flow channels are generated due to acid-rock reaction. This current study extends the application into diversion in high permeability, highly heterogeneous sandstone formations. Throughout this paper, the term VESDA is used to refer to the VES diverting agent. Laboratory tests have shown that VES is capable of increasing the flow resistance in the high permeability rock (simulated by a proppant pack) and will divert treatment fluid into the low permeability sandstone matrix. The process was more efficient if multiple stages of alternating VES and acid were used. Field case histories in Gulf of Mexico are also presented in this study to demonstrate the effectiveness of the VES material for acid diversion in the highly permeable and heterogeneous sandstone reservoirs.
Effect of Resistive Invasion on Resistivity Logs
Authors: Crary Steve , Jacobsen Scott , Rasmus John C. , Spaeth Rob
Published: December 2007

One of the more difficult decisions facing the petrophysicist is deciding which resistivity tool to use. Induction tools are best suited for low-resistivity formations drilled with fresh or nonconductive mud. Laterolog or resistivity tools are best in the opposite conditions. An important effect to consider when choosing the tool is the contrast of flushed zone resistivity (Rxo) to true formation resistivity (Rt). Laterolog tools have a difficult time estimating true formation resistivity when Rxo is greater than Rt. This effect, though well known, still seems to catch petrophysicists by surprise and can cause serious errors in the formation analysis. In this paper we demonstrate the potential problems by examining three case studies where both induction and laterolog tools were run. Comparing measured tool response to forward modeling results helps explain the measurements.

The first case study could be considered a classic case of resistive invasion. The mud resistivity was 0.78 ohm-m at bottom hole temperature. In a wet sand, the deep laterolog resistivity measurement is affected by the higher flushed zone resistivity and consequently reads much higher than the deep induction measurement. The resistive invasion is clearly seen on either the laterolog resistivity or induction measurements and can therefore be detected, although it is easier to estimate Rt with the induction. Resistive invasion effects are much more difficult to see on our second case study. A fractured carbonate with high formation resistivity of around 100 ohm-m was drilled with fresh mud. The fresh mud invasion in a wet zone results in Rxo greater than Rt, and the deep laterolog resistivity was consequently higher than the deep induction by almost one decade. However, the natural fractures resulted in the deep laterolog resistivity reading being greater than the shallow resistivity, which is typical of pay zones, and made detection of the shallow resistive invasion difficult using only a deep and shallow laterolog resistivity. Forward modeling suggests that the deep induction provides the best estimate of Rt in wet zones, while the deep laterolog resistivity measurement is best in hydrocarbon intervals. The final case study demonstrates this effect on a laterolog resistivity measurement made while drilling. The measurement was to be used to stop drilling at the top of a water leg. Unfortunately, the fresh mud filtrate and rapid mud spurt losses resulted in a flushed zone resistivity higher than formation resistivity in the water leg. Comparison between the laterolog bit resistivity (earliest measurement on the tool) and later measurements provided an indication of the effect. However, the difference is subtle and difficult to see on the field logs. Comparisons with the induction data clearly demonstrate the effects of resistive invasion on laterolog measurement in this environment.
New Processing Techniques to Meet Challenges of LWD Acoustic Logging
Authors: Market Jennifer , Barnett Craig , Deady Ron , Althoff Gary , Varsamis Georgios L. , Blanch Joakim
Published: December 2007

LWD acoustic logging presents several challenges beyond those faced in wireline logging: the LWD environment is inherently noisier, the drill collar supports additional propagation modes, the data are obtained at irregular depth intervals, and tool centralization is generally poor. Furthermore, it is difficult to achieve a pure monopole or pure dipole transmitter mode in LWD tool configurations; this complicates slow shear measurements based on flexural or Stoneley interface modes. These factors often result in a greater number of coherent arrivals being detected at the receiver arrays, and prohibits the effective use of some conventional techniques such as data stacking and dipole receiver subtraction, raising the challenge of properly identifying the various coherent modes of interest in determining formation compressional and shear velocities.

To address the added complications of LWD sonic logging, new processing and analysis techniques have been developed for use with a second-generation LWD sonic tool. In addition to the standard slowness vs. arrival time coherence computation, the frequency, energy, delay, and attenuation of each coherent arrival is also computed. These properties can be examined at each acquisition to determine the properties of the desired compressional, refracted shear, and interface modes. A new and innovative graphical user interface then allows the processing analyst to employ all of the relevant properties of the various coherent arrivals when producing the final compressional and shear slowness logs.

Field examples from various formation and borehole environments illustrate the application of the multi-parameter analysis approach to LWD sonic log processing. Examples include the identification and elimination of various types of residual tool modes and spatial aliasing. Examples are drawn from both fast and slow formations.
Advanced Forward Modeling Helps Planning and Interpreting NMR Logs
Authors: Bonnie Ron J. M. , Marschall Dave M. , Fam Maged Y. , Siess Charles P.
Published: December 2007

Nuclear Magnetic Resonance (NMR) logging has gained its position in the industry as stand-alone interpretation or as an additional source of information to conventional log data. There are a wide variety of examples where NMR logging has disclosed secrets of the well that were not discovered by conventional logs, e.g. low resistivity pay zones identified by NMR logs but completely overlooked or viewed as not economically viable by conventional log interpretation. In some complex environments, NMR logging may even be the only alternative available to assess critical formation parameters.

The interplay of rock and fluid properties, reservoir parameters, and NMR tool characteristics and settings shape the recorded NMR signals. Pre-job planning is critical for the success of the logging run especially now that NMR technology has gained more general acceptance and is being applied in complex environments. Integration of known parameters and estimated in situ properties may reduce the acquisition time, demonstrate the feasibility of a proposed logging run, and provide a handle to optimize the acquisition cycle. A priori knowledge will ultimately lead to better data and results in less time.

We have built a state of the art, multi-fluid, forward model to simulate NMR responses under given conditions. The latest understanding of NMR physics is incorporated in the model, including free and restricted diffusion. The model is a versatile planning tool, linked to a very user-friendly graphical user interface, which offers easy input and great flexibility.

Specifics of all currently available MRIL® tools and a broad range of rock and fluid properties are directly accessible through embedded database files. The user, however, has the flexibility to alter these values or to incorporate specific, regional knowledge. Polarization curves, composite transverse relaxation time (T2) spectra, and differential spectra are displayed. Computed fluid volumes, saturation levels, and relevant, mean T2 values are tabulated. The Planner is also being used more and more as an interpretation aid: geologists and petroleum engineers are testing their hypotheses by comparing computed NMR signals to actual logging data.
Permeability and Anisotropy Determination in a Retrograde Gas Field to Assess Horizontal Well Performance
Authors: Ayan Cosan , Donovan Michael , Pitts Alan S.
Published: December 2007

Uncertainty in permeability anisotropy proved to be one of the key factors while evaluating the performance of horizontal/deviated wells in the field under study. This gas condensate field, located in the UKCS of the North Sea, has sands of varying quality. All wells are producing below the dew point with a liquid condensate bank developing early in the life of the well, affecting productivity. Drilling horizontal and highly deviated wells to increase PI was considered a viable approach. However, the performance of such wells depends highly on permeability anisotropy; data was scarce and available only from core, limiting the scale of investigation.

This paper describes the investigation of permeability anisotropy in selected layers in the reservoir. Open hole vertical interference tests were conducted at five reservoir zones with a wireline formation tester using multiple probes.

The tests were analyzed using an analytical model, which simulates the pressure response at an observation probe vertically displaced from the active probe. Four tests showed a clear response where horizontal and vertical permeabilities were computed. The favorable anisotropy figures obtained from analyzing the Modular Formation Dynamics Tester (MDT)† data gave increased confidence about associated PI improvements from highly deviated wells. With this information, highly deviated wells were incorporated within the near term drilling program.
How Should We Measure Residual-Oil Saturation?
Authors: Wyman R.E.
Published: December 2007

1978 Rocky Mountain Regional Cody Wyoming May 17–19, 1978

Abstract;

A review of the advantages and limitations of methods to measure residual oil show that reasonable accuracy can be obtained from both open hole and cased hole techniques. Especially accurate methods for open hole include the nuclear magnetism log-inject-log technique and the pressure core barrel. In cased hole the pulsed neutron log-inject-log technique and the backflow tracer has been successfully tested. Other ideas of how to measure residual oil include use of reservoir performance, conventional cores, resistivity logs, carbon-oxygen logs, gamma radiation logs and dielectric logs.
Super-Critical Rate Based on Economic Recovery in Water and Gas Coning by using Vertical and Horizontal Well Performance
Authors: Recham R.
Published: December 2007

The purpose of this work is to develop a new method suitable for hand calculation. Simulation is shown to be a cumbersome process to investigate and predict optimum oil rate based on maximizing economic recovery, and breakthrough time for both vertical and horizontal wells.

Since the early days, several experiments and mathematical analyses were conducted to solve coning problems, since the production of water and gas increase the cost of producing operations, reduce the efficiency of the depletion mechanism, and the overall recovery. One of the basic conclusions of many analyses was if oil is produced at a sufficiently low rate, coning of water and gas can be avoided, and only oil is produced. This low rate is called critical oil rate.

These different theoretical correlations are conflicting and give different answers, probably due to the different assumptions each of them involves, and many times the critical rates are too low, and for economic reasons, a well is frequently produced in field operations at a rate above critical rate. This results in production of water, gas as well as oil, which could results in a low economic recovery.

To overcome this problem, an extensive parametric sensitivity analysis of the various reservoir and fluid properties on water and gas coning was investigated and performed using numerical simulation to provide input data for developing a new predictive correlation needed to calculate breakthrough time and optimum oil rate based on maximizing economic recovery for both vertical and horizontal wells. The parameters were grouped based on the regression analysis.

The new method is more robust, where the developed empirical correlations were tested and found to be reliable and closely accurate in estimating optimum oil rate to be used for a well in field operations. These correlations are illustrated with several field examples from Hassi R’mel field, Algeria, where calculated and observed, show satisfactory agreement of correlations with production data.
Efficient 2-Phase Upscaling in 2D
Authors: Virnovsky G. A. , Lohne A.
Published: December 2007

In heterogeneous reservoir containing 2 liquid phases, e.g., oil and water, the flow rate in combination with small to medium scale heterogeneities in both absolute permeability and capillarity defines dynamic capillary entrapment of oil and water. Since those effects involving both viscous and capillary forces happen on the lengths of cm to meters scale a simulator can only capture them if the grid is sufficiently refined. With typical size of the reservoir model grid blocks of the order of 100m in horizontal directions, and of the order of meters in the vertical direction, the small-scale heterogeneities have to be accounted for through the so-called effective absolute and relative permeabilities.

Generally, the effective relative permeabilities are rate-dependent[17],[13],[8],[3]. We have developed a software package which computes the effective absolute and also relative permeabilities in 2D in 2 "easy" cases, at capillary limit (which is also called capillary-gravity equilibrium), i.e., at low rate, and at viscous limit, i.e. high rate limit. Both ensuing effective properties, the absolute and the relative permeabilities, are generally full tensors. The computational procedure includes numerical finite difference solution of the elliptic equation with periodic or classic boundary conditions.

We present solutions of the problem for a number of simple heterogeneities and compare it with solutions obtained by other numerical and analytical procedures including the so-called self-consistent approach. The comparison reveals quantitative estimates of the accuracy and the computational efficiency of the developed software. In addition, a number of realistic heterogeneities are considered when only numerical upscaling is feasible.
Viscous-Elastic Fluids Can Mobilize Oil Remaining after Water-Flood by Force Parallel to the Oil-Water Interface
Authors: Wang Demin , Cheng Jiecheng , Xia Huifen , Li Qun , Shi Jingping
Published: December 2007

Residual oil after water flooding appears in three types: oil drops, films and clusters. Work performed using Newtonian fluids shows that to mobilize the residual oil remaining after water flooding, the driving forces, on condition of oil-water IFT (interfacial tension) being constant, need to be increased by one thousand to ten thousand times over that of water-flooding before the capillary forces retaining the residual oil can be overcome[1]. Viscous forces cannot be increased by such a large magnitude in the field.

Polyacrylamide (PAM) solutions have little effect on the oil-water IFT. However, results in the laboratory and field show that after flooding by polymer fluids, all types of microscopic scale residual oil in porous media are lowered[2]. The amount that is lowered is related to the elasticity of the fluids. Other conditions being the same, the higher the elasticity, the lower the residual oil saturation.

The results of lab tests (including microscopic visualization cores) show that viscoelastic fluid flooding can lower the residual oil saturation in cores of different wettabilities. The main forces to mobilize the residual oil by viscoelastic fluids are not entirely the same as that of Newtonian fluids. It is not only a force perpendicular to the oil-water interface overcoming the restraining capillary force, but also a viscous dragging force parallel to the oil-water interface that mobilizes the residual oil.
Field Performance of Propellant / Perforating Technologies to Enhance Placement of Proppant on High Risk Sand Control Completions
Authors: Folse Kent C. , Dupont Richard L. , Coats Catherine G. , Finley Doug , Nasse David B.
Published: December 2007

The combined use of propellants and perforating for production enhancement is not new to the petroleum industry, especially for natural completions in competent formations. When used together, the propellant is shaped in the form of a cylindrical sleeve that is positioned over a scalloped perforating carrier to combine the perforating and stimulation processes into one step. The perforating event is performed in either an under-balanced or balanced condition, followed immediately with the extreme over-balance or rapid-gas pulse generated from the propellant burn. This technique provides an effective method to ensure that all perforations are sufficiently broken down from the fracturing to accept either produced or injected fluids.

This paper will review a new application for the combined propellant / perforating technique that has been successfully used in unconsolidated formations in the Gulf of Mexico.

The propellant / perforating technique was used to enhance the placement of proppant during frac-and-pack and gravel pack treatments while perforating in a balanced condition. The propellant / perforating technique was used on several formation types; i.e., long intervals, highly deviated, and highly laminated with extreme permeability contrasts, that would traditionally be deemed as high risk for proper sand placement.

In performing this technique, the propellant sleeves are positioned across the lower quality portions of the intervals with low permeability and resistivity to ensure that the perforations in these intervals would be broken down to accept fracturing fluids and proppant during the fracturing treatment consistent with the entire treated interval.

Case histories from Gulf-of-Mexico operators have shown that this technique is effective in both underbalanced and overbalanced perforating situations. With the trend in the industry to reduce cycle time, the elimination of the underbalance/surge process to ensure clean perforations and all the associated rig time in obtaining control of the well following the surge are seen as significant opportunities for rig-time savings.

It has also been proven that combining propellant/ perforating in a balanced scenario can offer a cost efficient and safe method when used as a near wellbore clean-up tool for pre-frac preparation or high rate water packing.
Multilateral Work-Overs: A New Possibility with Coiled Tubing
Authors: Ravensbergen John
Published: December 2007

The number of fields that are being developed, or redeveloped, using multi-lateral wells to enhance the effective drainage from minimal surface facilities is increasing. Some of these types of wells have complex Level 3, or higher, junctions but the vast majority are still Level 1 junctions.

Often drilling and other damage can be imposed on the various exposed leg well bores, as in the case of a Level 1 junction, while the other branches of the well are being drilled. This formation near well bore damage can, in the extreme, lead to a re-evaluation of the field development strategy as there has been no intervention method available to enter the various branches and perform effective stimulation or clean-up and, therefore, achieve the full production potential from the well.

This paper describes a new Bottom Hole Assembly (BHA), enabling a new method to workover multilateral wells using coiled tubing. The BHA and its method of navigating through multi-lateral wells makes the assumption a smart and/or selective entry completion is not installed in the well. Therefore, the onus is on the BHA to intelligently navigate through a junction(s) whether it is an open hole or cased hole. The BHA's operational success however, is dependent on the geometry of the junctions.

Examples from case studies performed in Canada Venezuela will be used to explain how the geometry is critical for successful operation of the tool. In addition, these case studies will explain what type of workovers have been tested and proven and what further possibilities exist.
The Application of PEM Drilling Fluid System in Environmentally Sensitivity Area
Authors: Shaocheng Xu , Jin Xiaojian , Zili Li , Xiang Xinjing
Published: December 2007

The PEM water-base polymer mud system was developed to provide an environmentally acceptable drilling fluid that approaches the inhibitive performance of an invert oil emulsion fluid.

PEM is engineered with a specially formulated PF-JLX additive for maximum shale inhibition and designed to drill high-angle wells in reactive formations, normally reserved for an oil-base mud. The primary functions of the PF-JLX in the system are to improve shale stability and the lubricity of the fluid.
Wellbore Hydraulic Optimization With Positive Displacement Motor and Bit
Authors: Samuel G. Robello , McColpin Glenn
Published: December 2007

Over the last few years, use of downhole motors have increased dramatically to meet the challenges of horizontal wells and in particular, extended reach drilling, deep and ultra-deep water wells. With these wells pushing the limits of rigs and equipment it is imperative that motors be utilized optimally in the system. More often downhole motor pressure loss calculations are not explicitly included in the overall hydraulic optimization and bit nozzle selection with the available pump power. Generally a motor pressure loss is specified in the optimization calculation and the optimized nozzle sizes are selected. To enhance the method of optimization and make the system more effective, hydraulic optimization is required by taking into consideration various motor and drilling parameters. The key to an improved drilling system is a unified system approach that encompasses motor and bit. This paper presents a new approach to hydraulic optimization by including both the motor and bit. It enables us not only to calculate the optimal flowrate and optimal horsepower of the motor as a function of configuration of the motor but also to select the correct motor configuration. In addition, calculations are made for hydraulic horsepower per square inch encompassing bit and motor. The practical usefulness of the theory, backed by the fundamental and optimal analysis is demonstrated with numerical examples.
Use of Spreadsheet and Analytical Models to Simulate Solid, Water, Oil and Gas Flow in Underbalanced Drilling
Authors: Guo Boyun
Published: December 2007

Underbalanced drilling (UBD) technology is widely used in oil and gas industry for multiple purposes including minimizing formation damage and controlling lost circulation. One of the important tasks in UBD design is to predict bottom hole pressure under given drilling conditions. This task is very difficult when aerated liquids are utilized. Sophisticated computer programs are often required for this task. However, reliable computer programs are not always available for engineers who are in charge of UBD designs and executions. It is highly desirable to have spreadsheet programs that can accurately perform such predictions.

This paper presents three analytical models that are coded in a spreadsheet program for UBD hydraulics calculations. These three models cover multiphase flow of commonly used drilling fluids in three categories: 1) air, gas, mist, and unstable foam; 2) stable foam; and 3) aerated liquid. Comparisons of these models with field measurements indicated that these analytical models are accurate enough for UBD design.
Multi Year Gas Storage Deliverability Results Using a Proppant Surface Modification Agent
Authors: Kozera Gregory A. , Willis Stanley F. , Shaw J. Stanley
Published: December 2007

This paper presents post-fracture deliverability results for 56 gas-storage wells over a two- to five-year period. Of the wells studied, 32 had a surface modification agent (SMA) applied to the proppant during the hydraulic fracturing treatment. The other 24 wells included in this study had no additives applied to the proppant for sand flowback control.

The deliverability results from actual flow tests are used to evaluate how absolute open flows (AOF) held up over multiple injection and withdrawal cycles involving significant pressure differentials. The results are compared for the large data sets of wells that did and did not include the SMA in the fracture treatment. In general, the data set for wells that did not include an SMA have been through four or five complete pressure cycles. After some operational problems, the need for proppant flowback control became apparent, and later frac treatments usually included the SMA. The wells that included a SMA have been through two or three complete pressure cycles.

This study was completed to alleviate the operators concern about the long-term impact of the SMA on the well performance. While the SMA effectively achieved the short-term goal of proppant-flowback control, the operator was concerned that the fracture might be more prone to a reduction in conductivity or simple clogging.

Typically, a new product or process gets a lot of attention and study. Many times the well results are tracked only for a year or less and the product or process becomes common or discarded. Longer-term studies on a product or process are less common, perhaps due to time, manpower, cost constraints, personnel changes, and a variety of other reasons. Over time, information can easily get buried in a sea of data. Wells using the once-new product or process are forgotten unless a serious problem occurs. The reason the product or process was first used may even be forgotten if it solved the problem.

While results may vary from formation to formation, this longer-term look at the results of SMA, injected with the proppant, should help fracture treatment designers convince the skeptics that proppant-flowback control can achieve its immediate objective and match or exceed long-term performance expectations.
Evaluation of Laminated Formations Using Nuclear Magnetic Resonance and Resistivity Anisotropy Measurements
Authors: Shray Frank , Borbas Tim
Published: December 2007

Laminated formations create two major evaluation problems for petrophysicists. First is the classic low resistivity pay problem as seen in vertical wells. Layers of fine-grained sand, silt, and clay distributed within a hydrocarbon bearing sand will significantly reduce the apparent resistivity measured by an induction or propagation tool. The fine-grained layers hold high volumes of irreducible water, the sand will produce water-free oil or gas, yet the oil company may not even attempt to complete the zone. Second is the high angle well evaluation problem. The same laminated formation, when measured by an induction or propagation tool at moderate-to-high relative dip, will exhibit an increase in apparent resistivity beyond that which was measured in the vertical well. Again, the accurate calculation of water saturation and hydrocarbon volume eludes the petrophysicist. Both of these classic problems can be solved with a common methodology that combines nuclear magnetic resonance (NMR) and resistivity anisotropy measurements.

Case study wells are used to demonstrate two versions of this method. In the first version, horizontal resistivity (Rh) and vertical resistivity (Rv) are the initial inputs. With an assumption of the resistivity value of the silt-clay layers, we solve for the resistivity of the hydrocarbon bearing layers and the volume fraction of each layer. Water saturation (Sw) of each layer is calculated independently. Bulk volume hydrocarbon (BVH) of the entire formation is the sum of the products of the layer volume fractions and their respective BVH. The second version of the method uses the measurement of bound fluid volume from the NMR tool to determine the volume fraction of each layer. We then solve for the resistivities of both the silt-clay layers and the hydrocarbon bearing layers. The solution of BVH for the formation then proceeds as in the first method.
Wireline-Conveyed Through-Casing Formation Tester Preserves Casing Integrity
Authors: Burgess K. A. , MacDougall T. D. , Siegfried R. W. , Fields T. G.
Published: December 2007

Advances in formation tester technology and a novel electro-mechanical drilling technique have provided the oil industry with a new modular through-casing formation tester. The wireline-conveyed tester, which determines formation pressure and fluid content behind casing, has been developed in a joint project conducted by the Gas Research Institute and Schlumberger. More than 200 Tcf in gas resources are estimated to exist behind casing in the United States alone. To facilitate evaluation of these potential reserves, the tool was designed to make a hole through the casing, measure formation pressure, take fluid samples and then reseal the hole. This paper describes the tool features, applications and field test results.

Primary applications include detection of bypassed hydrocarbons, evaluation of potential pay prior to well abandonment, and formation testing under conditions where openhole testing and sampling are not feasible. Reservoir management applications include production monitoring, especially waterfloods and CO2 floods, and economic evaluation for selling and booking reserves. Secondary applications include detecting gas-collector zones in gas storage wells, and injecting or producing through a few small drilled holes (i.e., limited-entry steam injection).

The tool uses a flexible drill shaft to drill holes several inches deep through casing, cement and formation. Pretests, involving pressure drawdown and buildup flow periods, are performed as pressure is measured with both a crystal quartz gauge and a strain gauge. If desired, a formation fluid sample can also be taken at this time. A reliable mechanical plug seals the drilled hole in the casing, creating an effective seal to at least 10,000 psi of differential pressure (either direction). This service was introduced in October 2000 and is now completing field trials. This novel technique for measuring pressure and taking samples through casing provides the ability to assess pay without perforating the well and facing costly and often problematic cement squeeze jobs.
Multiseam Coal Stimulation Using Coiled-Tubing Fracturing and a Unique Bottomhole Packer Assembly
Authors: Rodvelt G. , Toothman R. , Willis S. , Mullins D.
Published: December 2007

In Virginia, coalbed methane (CBM) production can occur from as many as 25 seams with thicknesses from 0.5 to 6 ft. Fracture stimulations have evolved from single-stage, limited-entry designs to multiple stage treatments with corresponding increases in gas production as additional staging was added. For mechanical and economical reasons, three to five stages have been typical. With the introduction of an integrated coiled-tubing (CT) rig and a specially designed bottomhole packer assembly (BHPA), additional staging to cover individual coal seams is possible.

A five-well project in Buchanan County, Virginia was chosen for coiled-tubing fracturing (CTF). Job designs that use current fluid and proppant loading were modified for the injection rates and pressures expected in treating down 3,800 ft of 2 ⅜-in. coiled tubing. Treatment procedures, fluid systems, and treatment graphs are presented illustrating job designs used to treat 11 to 19 different stages in each of the five wells. Economics are presented for accessing additional productive coal footage and the resulting net present value (NPV) gained. Lessons learned and recommendations for improving the efficiency of CTF in the Appalachian Basin are included.
Proppants: Is Bigger Better or is Placement the Key?
Authors: Mack David J. , Myers Roger R.
Published: December 2007

Historically, 20-40 mesh frac sand has been used in fracture stimulation treatments in the low permeability Devonian Sands of the Appalachian Basin. Carrier fluids have ranged from straight water to gelled water to water-based foams to crosslinked gelled water and even to crosslinked foams.

Recent work in the very low permeability (<0.1 md) Cotton Valley formation in East Texas has shown that the conventional wisdom of 20-40 mesh sand and high gel loading crosslinked fluids may not necessarily be the most effective treatment. 40-70 mesh frac sand and low gel loadings have proven beneficial. Although the Devonian Sands are not an exact match to the Cotton Valley, the very low permeability and low reservoir pressure make these sandstones a candidate for this type of treatment.

Using an industry accepted well productivity calculator and the parameters of a Devonian reservoir, the well production characteristics of various sand mesh sizes is investigated. This is only a small piece of the puzzle. Where proppant is placed in relationship to the productive interval(s) and effective fracture length are critical factors in the productivity of this type of reservoir.

A 3-dimensional fracture simulator is employed to demonstrate the improved efficiency attained in the placement of small mesh sand (40-70). Various carrier fluids are employed to place the sand. These results are then run through the well productivity calculator demonstrating the importance of proppant placement.

Although pound for pound a large mesh proppant will have improved conductivity, the deeper placement attained with smaller mesh proppants improves well potential. This paper presents this data and develops a case justifying a change in conventional Devonian Sand fracture stimulation philosophy.