bluuebunny/crossref_metadata_2025 huggingface dataset:
Drilling for Coalbed Methane in the San Juan Basin With Coiled Tubing: Results, Learnings, and a World First
Authors: Noynaert Sam , Pumphrey Dale , Pink Tony , Eiden Tug , Hartensteiner Fred , Nelson Chip
Published: December 2007

The San Juan basin is a prolific natural gas play in northwestern New Mexico and southwestern Colorado. It contains conventional oil and gas resources along with unconventional gas resources in the forms of tight gas and coalbed methane (CBM). Conventionally, drilling operations have been carried out by smaller rotary rigs with double or single derricks. These are usually minimalist, older rigs which fit well into the tight cost structure of the unconventional resources in the San Juan basin.

In 2006, a coiled tubing drilling (CTD) pilot program was initiated in the San Juan basin consisting of seven wells, drilled in order of increasing complexity. The intention was to evaluate the full capabilities of CTD and its potential for use in the San Juan basin as well as the general U.S. onshore area. The drilling program included vertical wellbores, S-shaped wells off of a pad, and a horizontal sidetrack- all targeting the Fruitland Coal. In addition, several vertical and directional deep-set intermediate strings for future drilling of the deeper tight gas in the Mesa Verde and Dakota formations were set with CTD.

The rig used was a new, custom-built, coiled tubing/rotary hybrid rig setup for use with large-diameter coiled tubing (3.5 in. and 2.875 in. OD). In addition, it had a single-sized derrick, rotary table and top-drive. This allowed the rig to drill with jointed pipe, handle and make-up bottomhole assemblies (BHA), and run liner and casing.

Problems were encountered in areas such as fluid and additive selection, bit selection, hole stability issues, and crew training and rig limitations. In addition, CTD in this format was new to the San Juan basin and its personnel. Further issues that added difficulty included maintaining stringent standards of safety and environmental compliance, as well as conducting world-first operations such as running a rotary-steerable system (RSS) on coiled tubing. The end result was seven successfully drilled wells that are producing at the same or at better rates than offsets drilled with conventional rotary technology.
Study on Gelation and Freezing Phenomena of Synthetic Drilling Fluids in Ultradeepwater Environments
Authors: Gandelman R. A. , Leal R. A. F , Gonçalves J. T. , Aragão A. F. L. , Lomba R. F. , Martins A. L.
Published: December 2007

Fast and non-progressive drilling fluid gelation is desired to prevent drilled solids sedimentation during pumps-off, while avoiding excessive pressure peaks when circulation is resumed. Gelation tendencies are normally higher at low temperatures typical of deepwater risers. Excessive pressure peaks can cause detrimental effects when fracture pressure is reached.

Besides gelation issues, excessive pressures and/or difficulties to resume circulation have been observed during drilling operations in water depths greater than 1.800 m. The problem happened especially with the fluid volume filling the control lines, at the time of circulation restart. Two field cases of fluid freezing in choke and kill lines have been reported which led to riser and BOP removal to unplug the lines, with significant non productive time and high costs.

The paper shows the results of an experimental study carried out to evaluate the rheological behavior and gelation properties of non aqueous drilling muds under low temperatures (bellow 4° C) and high pressures (up to 5.000 psi). The study aimed to quantify pressure effects on freezing temperatures and to develop representative methodologies for the evaluation of thyxotropic properties of such fluids. Experiments included steady state and transient shear and oscillatory tests at cone-plate geometries. The final goals are to design additives and drilling fluid formulations with flow point lower than 0° C at pressures higher than 2.500 psi and taylor made gelation profiles. Additionally modeling work was carried on to represent the time dependent behavior of relevant rheological properties at different temperatures and pressures. Such models were used to predict pressure peaks and compare them with real PWD data from ultra deepwater wells.
Are Preflushes Really Contributing to Mud Displacement During Primary Cementing?
Authors: Guillot D. J. , Desroches J. , Frigaard I.
Published: December 2007

During a primary cementing operation, it is most of the time necessary to prevent direct contact between the drilling mud and the cement slurry that is to be placed in the wellbore. The reason is that these two fluids are usually incompatible. This incompatibility can manifest itself either as an accelerating effect, the drilling mud/cement mixtures having a shorter thickening time than the cement itself, which is obviously not acceptable, or as a viscosifying effect, the drilling mud/cement mixtures being more or much more viscous than any of the two uncontaminated fluids, which can be detrimental to the displacement process.

To keep the drilling fluid and the cement slurry separated, low density and low viscosity fluids, that will be referred to as preflushes, are often pumped ahead of the cement slurry. Examples of such fluids are water, oil, or more advanced formulations which are usually called chemical wash. It was recognized relatively early that, to be efficient, preflushes should be in turbulent flow in the annulus for a minimum amount of time. In the early 90s the criteria for turbulence was refined by taking into account the eccentricity of the annulus on the flow regime.

The objective of this paper is to illustrate what fluid displacement modeling is telling us about the efficiency of these preflushes. It will be shown that, in a number of cases, preflushes are not as effective as one would think at preventing direct contact between the drilling fluid and the cement slurry, even when industry accepted rules are used to design them. In such circumstances the cement slurry is actually displacing the drilling fluid, but there are risks associated with this situation as explained above. It is therefore suggested that preflushes should be used with more caution and replaced by weighted spacers, in particular in circumstances where good cement quality is mandatory up to the top of the cement column.
Improvement of Placement Efficiency of BaSO4 and SrSO4 Dissolvers Using Organic Alkalis as pH Controlling Agents
Authors: Lakatos Istvan , Lakatos-Szabo Julianna , Toth Janos , Bodi Tibor
Published: December 2007

The research program is based on earlier evaluation of seven different polyamino carboxylic acids (NTA, EDTA, DCTA, DTPA, DOCTA, HEDTA and TTHA). The flow tests comprised the study of NaOH, KOH, Na2CO3 and K2CO3 solutions with and without dissolvers. Low molecular weight amines (mono-, di- and trimethyl and –ethylamines) served also as pH controlling agents. Comparison of inorganic and organic additives was made through their effect on effective permeability in artificially consolidated sandstone cores.

Based on the experimental findings it was concluded that solutions containing inorganic alkalis deteriorate the permeability independently of the fact that they were chelate containing or chelate-free. Similar results were obtained for all ethylamines. The methylamines, however, proved to be excellent pH controlling agents: permeability of the porous media remained unchanged, or even improved through extensive injection period; meanwhile the dissolution capacity of dissolvers was preserved or slightly increased.

It was clearly proved that selection of the best dissolver should be made by compromising the different technical aspects: not the chelating agent and the dissolution capacity is important, but also to the type of alkali compounds. Using organic alkalis the detrimental side effect of conventional inorganic alkaline compounds can be eliminated improving the flow characteristic and placement efficiency of dissolvers.
Assessing the Accuracy of History-Match Predictions and the Impact of Time-Lapse Seismic Data: A Case Study for the Harding Reservoir
Authors: Walker Greg J. , Lane H. Scott
Published: December 2007

The oil industry benefits from reservoir models that are accurate predictors of future performance, but a "good" match to historical well data doesn't guarantee a "good" prediction. This paper presents a case study from the Harding field in the North Sea, illustrating that we can greatly improve our chances of getting "good" predictions from our reservoir models by including time-lapse (4D) seismic data as part of the history matching process. The value of the surveillance is also discussed in the light of its use in improving reservoir performance prediction.

The first part of the case study addresses the accuracy of prediction. The Harding field (Figure 1) started production in 1996, with the first time-lapse seismic survey being acquired in 2000. Using computer-assisted history matching techniques,1 multiple alternative reservoir models were generated that matched the well surveillance to 2000. In a blind test of predictive capability, forward predictions from these alternative models were compared with the subsequent production data from 2000 to 2003, allowing us to compare quantitatively the prediction quality against the history match quality for the selected cases. The time-lapse seismic data from 2000 was then included in the history matching process and the impact on the resulting prediction quality through 2003 was evaluated. Addition of the 4D seismic data enabled the selection of a subset of reservoir models which better predicted the (known) future of the field.

The best hypotheses are those that make predictions that can be tested. If 4D seismic information is effective in reducing uncertainty, then there should be a way of making a quantitative estimate of the value of a future seismic survey. The impact and value of acquiring a future time lapse seismic survey, and a discussion around the metric for value of surveillance, are discussed in the second part of the case study.
Simultaneous Recording of Hydraulic-Fracture-Induced Microseisms in the Treatment Well and in a Remote Well
Authors: Mahrer K. D. , Zinno R. J. , Bailey J. R.
Published: December 2007

In June 2006, in a production well in a tight sandstone shale sequence, on-shore USA, two borehole seismic arrays were deployed in separate wells during a proppant-baring hydraulic fracture treatment. The intent was to delineate the treatment-generated fracture network by recording the microseisms triggered by the treatment, map the microseism source locations, and then use the map as an overlay to delineate the fracture network. The treatment was one facet of a proprietary, multi-faceted injection strategy with microseismic mapping used to determine if neighboring fracture networks overlap. In addition to mapping the network, the objective of this facet was to compare maps from the two arrays. One array was in a remote well, the other in the treatment well. The remote array was offset ~700 ft from the treatment well and at the injection depth. This array was ~500 ft long; self-locking; contained 15, 3-component motion sensors; and operates on a fiber-optic cable. The treatment-well array, the "TABS" or TriAxial Borehole Seismic array (licensed by ExxonMobil Upstream Research), is ~75 ft long; self-locking; operates on a standard, 7-conductor wireline; and includes (1) 3, 3-component motion sensors, (2) an ambient fluid pressure sensor, and (3) a gyroscopic, sensor orientation package. During the treatment, a 45-minute injection immediately followed by a 1-1/2-hour well shut-in, the remote array failed to detect any discernable treatment-triggered, microseisms. However, TABS, which recorded microseismicity only during the shut-in, recorded ~400 microseisms. During the operation, the remote array maintained one position; TABS was unlocked, repositioned, and relocked twice; Moving TABS allowed different perspectives for recording the microseismicity, improving the accuracy of mapping and enhancing additional characteristics extractable from the microseismic waveforms.
Innovative Ultralightweight Spacer for Cementing Jobs Without Nitrogen or Diesel
Authors: Rafael Zepeda G. , Antonio Martínez R. José , Maldonado Reinaldo , José Luis Bustillos G.
Published: December 2007

In the oilfield industry, many resources have been allocated to develop lightweight slurries that will reduce the equivalent hydrostatic pressure against low-pressure formations and achieve successful zonal isolation while performing a cementing job. However, to comply with the standard recommended practices for cementing operations, it is crucial to maintain a progressive rheological and density trend from the spacer up to the tail slurry. Centralization and friction pressure play another very important role in achieving a suitable design and have to be considered during the design stage as well.

This paper describes how a lightweight spacer with 0.88 g/cm3 (7.3 lbm/gal) density was developed and its important contribution while performing a cementing job in a depleted zone.

One of the main contributions is the possibility for decreasing the hydrostatic pressure and the equivalent circulation pressure by increasing the spacer column length. By increasing the column length, additional mud can be returned to the surface, which would represent an important cost savings in cases where the mud is expensive and could be reused.

Not using nitrogen to reduce the hydrostatic pressure also contributes to savings in operational costs and facilitates the job execution and logistics. Eliminating the use of diesel in the spacer to reduce its density minimizes the possibility of having incompatibility and contamination problems with the cement slurry. The reduction of the ecological impact is also an issue to consider.

Finally, we might be able to evaluate features and benefits of this technology as well as its future applications in the industry.
3D Porosity Estimation Using Multiattribute Analysis Methods in One of the Persian Gulf Oil Fields
Authors: Khoshdel H. , Riahi M. A.
Published: December 2007

This study focuses on one of Persian Gulf oil fields. The major reservoir unit in the interested area is composed of alternation of thin dolomite with anhydrite layers. In the available 3D seismic data, these layers are not resolved and generate a composite detectable seismic response, making reservoir characterization difficult through conventional seismic attribute analysis (using single attribute transforms).

In addition to resolving the major reservoir units the main aim of this study is porosity prediction and making 3D porosity cube for detailed reservoir characterization. For this purpose firstly the 3D seismic volume was inverted to obtain an acoustic impedance cube using three different inversion algorithms. Inversion improves the vertical resolution and resolving the interested reservoir layers. Among the different inversion methods applied, according to cross-validation results, acoustic impedance derived from model-based inversion has been selected as the main seismic attribute.

In the next step of this study, acoustic impedance attribute beside other attributes extracted from seismic volume were analyzed using single attribute, multiple attribute regression (with stepwise regression for attribute selection) and neural networks (PNN and MLFN). These linear or non-linear combinations of attribute for porosity prediction result in the improved match between the derived porosity and predicted one.

To estimate the reliability of the derived multi attribute transforms, cross validation is used;

According to results it's found that cross correlation between actual porosity and estimated one has increased from 80% in single attribute prediction to 88% using multiple regression transform. Also neural networks provide higher cross correlation values rather than both. Finally according to cross validation results, multiple regression transform is used for porosity prediction.

Using implemented technique slices prepared which have higher consistency with log data and could lower risk in field development.
A General Unstructured Grid, EOS-Based, Fully-Implicit Thermal Simulator for Complex Reservoir Processes
Authors: Liu K. , Subramanian G. , Dratler D. I. , Lebel J. P. , Yerian J. A.
Published: December 2007

This paper describes a general unstructured grid, EOS-based, fully-implicit thermal simulator for complex reservoir processes. Under the unstructured grid framework, the simulator uses Newton's method to solve component material balance equations, energy balance equation and volume balance equation for component moles, energy and pressure, where chemical reactions and/or external heat sources/sinks are treated in source terms. Because of the similarity among component material balance equations and the energy balance equation, energy is treated as a "component" to achieve a uniform formulation with common code for all simulations (black oil, compositional and thermal).

The thermal simulator was validated using analytical models as well as other thermal simulators. Application of the thermal simulator includes studies of grid-orientation problems and to design and optimise Cold Lake heavy oil development.
Data Management in Reservoir Simulation
Authors: Gencer S. C. , Ketcherside B. P. , Morrell G. O. , Mulkay E. L. , Wiegand K. D.
Published: December 2007

Data from a wide variety of sources are required for reservoir simulation. Simulation itself produces large quantities of data. Yet, good data management practices for reservoir simulation data are typically neither well-understood nor widely investigated. This paper presents a specific architecture to manage reservoir simulation data, discusses experiences from six years of global use, explains adjustments to support changing workflows and outlines challenges that lie ahead.

The architecture consists of a Database Management System (DBMS) and files in managed file directories, called Reservoir Input Output System (RIOS). All simulation input data and results are maintained by a Data Management System (DMS). The reservoir simulator reads input files written from the DBMS to RIOS and writes results to files in RIOS. DBMS, RIOS and integrated management tools (DMS) make up the data management environment.

The environment has been in use inside ExxonMobil since late 2000 and now supports close to 500 users (85% of reservoir engineers). There are over 30 individual databases containing 2TB of online data and about 6TB of online RIOS data. The environment itself introduces some additional work. Support staff is required for maintenance of databases, RIOS areas and problem resolution. Direct user manipulation of data is not permitted and additional tools are required to access and interpret data.

The environment provides many benefits. While it insures data integrity, security and consistency, it also automatically updates defaults, limits, associations, types, etc. This allows running of older simulations and generation of aggregate statistics and usage audit trails.

The architecture and experiences presented in this paper may be unique in the industry. The DMS was designed, developed and deployed over a ten year period. It is a successful software story and is viewed, along with the simulator, as a key enabling technology for success with reservoir simulation within ExxonMobil.
A Compositional Streamline Formulation With Compressibility Effects
Authors: Osako Ichiro , Datta-Gupta Akhil
Published: December 2007

Streamline simulators are gaining increasing acceptance because of their computational advantage, intuitive appeal and ability to visualize the flow patterns in 3D. Much of the current industry experience has been limited to black oil simulation, specifically two phase water-oil displacements under incompressible or slightly compressible conditions. However, given the favorable computational scaling properties of streamline models, the potential advantage for compositional simulation can be even more compelling. Although several papers have discussed compositional streamline formulation, they all suffer from a major limitation, particularly for compressible flow. The decoupling of the compositional pressure and transport equations, which form the basis for streamline simulation, has been accomplished under severely restrictive assumptions.

In this paper, we examine the implications of these assumptions on the accuracy of compositional streamline simulation using a novel and rigorous treatment of compressibility. Our compositional streamline formulation builds on the recent work of Cheng et at.1 and uses the concept of effective density to redefine the bi-streamfunctions and decouple the 3D conservation equations to 1D transport equations for overall compositions along streamlines. The effective density accounts for volume changes with pressure and can be conveniently traced along streamlines. The streamline equations are solved using a third order TVD scheme to minimize numerical dispersion. The phase compositions and saturations are obtained via thermodynamic flash calculations.

We propose a novel ‘optimal’ gridding strategy for efficient solution of the 1D compositional equations along streamlines. The approach is based on a bias-variance trade-off of ‘slowness’ along streamlines and adaptively coarsens the grid for the 1D solution without compromising accuracy. This significantly reduces the number of flash calculations during the 1D solutions. We compare the results from our proposed formulation with finite difference simulation and also, existing compositional streamline formulations in the literature to highlight the importance of the rigorous treatment of compressibility effects. Finally, we examine the scaling behavior of the streamline and finite difference models for compositional simulation to identify potential computational advantages for large-scale field applications.
Efficient History Matching through Production Data Selection
Authors: Liu B. , Kelkar M. G. , Gang T. , Dixon T. N.
Published: December 2007

Reservoir characterization and forecasting require construction of reliable and history matched reservoir models. In gradient-based automatic history matching procedure, most of the CPU time is spent on the sensitivity calculation. When the adjoint algorithm is used to calculate the sensitivity, the CPU time is approximately proportional to the magnitude of observed data. If we can identify observed data with most information content, we can minimize the history matching time using adjoint method and hence make the history matching faster.

A methodology has been developed in this work to identify the important production data and discard those "less useful" data in the automatic history matching procedure. This enables us to save significant computational time without sacrificing much of the history matching result. Our approach ensures that the selected observed data contains little redundancy, and gives similar inverted result based on the contents of all the observed data set.

The method is validated by conducting history matches for synthetic data sets. The comparisons of computational time and the quality of the inverted results indicate that this method is promising and practical for the automatic history matching. Using this approach, computational effort can be reduced by as much as ten times without sacrificing the quality of the results.
Real-Time Microseismic Monitoring of Hydraulic Fracture Treatment: A Tool to Improve Completion and Reservoir Management
Authors: Le Calvez J. H. , Klem R. C. , Bennett L. , Erwemi A. , Craven M. , Palacio J. C.
Published: December 2007

A considerable amount of gas is currently produced from unconventional Mississippian organic-rich shale gas fields such as the Barnett, the Fayetteville or the Bakken formations. Several tight-gas sand formations (e.g., Bossier, Cotton Valley, Lobo, Vicksburg, etc.) also provide valuable resources to be exploited.

These formations are extremely low porosity and permeability reservoirs. They must be effectively and efficiently hydraulically fracture stimulated to produce at commercially economic production rates. Understanding the location and geometry of the created fractures and the area of pay affected by the fracture treatment is key to maximizing the value of the completion and reservoir management program.

Technology has progressed to the point that microseismic monitoring of hydraulic fracture stimulation can efficiently provide extensive diagnostic information on fracture development and geometry. Furthermore, an acquisition system coupled to a real-time processing software linked to a fit-for-purpose visualization package enables true real-time microseismic monitoring of hydraulic fracture treatments.

Firstly, this paper briefly discusses critical elements of a typical microseismic monitoring system including both hardware (e.g., quality of the downhole geophones, coupling to formation) and processing (e.g., velocity modeling, anisotropy).

Secondly, we highlight some of the issues associated with manual picking of microseismic events and discuss an automatic processing technique that enables real-time determination of microseismic event locations.

Thirdly, we discuss the value of real-time microseismic monitoring and the benefits it represents as an additional tool available to the stimulation engineer fracture analysis (e.g., hydraulic fracture containment, stage overlapping).
Small-Scale Fracture Conductivity Created by Modern Acid-Fracture Fluids
Authors: Pournik M. , Zou C. , Nieto Malagon , Melendez M. G. , Zhu D. , Weng X.
Published: December 2007

The effects of acid solutions injected into hydraulic fractures created in carbonate formations can be assessed at the laboratory scale in acid fracture conductivity tests that mimic the conditions in an actual acid fracture treatment. We conducted a series of acid fracture conductivity tests using a protocol that mimics the fluxes in a hydraulic fracture, both in the main flow direction along the fracture, and in the fluid loss direction. In our tests, the injection rate into the fracture is much higher than in many previous tests, and the fluid loss flux is controlled to match field fluid loss rates. We studied three commonly used acid fracturing fluids—an acid viscosified with polymer, an emulsified acid system, and an acid viscosified with surfactants—at elevated temperatures of 200°F and 275°F. The acid fracture conductivity apparatus is similar to a standard API fracture conductivity cell, but with a capacity to hold core samples that are 3 in. long in the leakoff direction. The long cores allow for better control of leakoff as the acid creates wormholes into the core samples.

In these tests, acid was pumped through the fracture for contact times ranging from 15 to 60 minutes. After the fracture surfaces were carefully characterized with a surface profilometer, the fracture conductivity was measured at increments of closure stress, up to a maximum closure stress of 6,000 psi.

In this paper, we present the results obtained from a series of experiments with these fluids using Indiana limestone and dolomite core samples. Among the findings:

The fracture conductivity created did not show a general increase with acid contact time, and in fact decreased at higher contact times with some fluid systems. This suggests that optimal times of acid exposure in acid fracturing treatments exist.

There were large differences in the conductivity created with the three acid systems tested. At 200°F, the acids viscosified with polymer or surfactants created much higher conductivity than the emulsified acid system.

The laboratory-scale acid fracture conductivities measured in these experiments do not agree with the predictions of the Nierode-Kruk correlation.
Application of a Multidisciplinary Workflow in a Mature Oil Field, Mann Field, Myanmar
Authors: Miskimins J. L. , Graves R. M. , Mu S. L. , Anderson D. S.
Published: December 2007

Mann Field is located in the Salin sub-basin of the central basin of Myanmar (Burma) in Southeast Asia. The field began producing in 1970 predominately from the Oligocene reservoirs. More than 650 wells have been drilled and completed, 106 million stock tank barrels of oil produced, with over 100 million barrels of water injected in an early secondary recovery project. Reservoir management and redevelopment became the focus in 1998. With this redevelopment effort and due to the incredible complexity of the reservoir system (~20 producing intervals in a tectonically active area), the need for a complete multidisciplinary integrated characterization of the field became necessary to maximize economic reserve recovery.

The first step into systematically developing a multidisciplinary workflow is to inventory various data. A significant amount of 3D seismic had been run across the field, likewise core and outcrop information was available. A variety of engineering data including production, injection, drilling, completions, etc, was also available. However, little of the data was integrated into a full reservoir picture and significant amounts were not being used to their full potential.

This paper describes the development of a field management philosophy for a mature (brown) field that incorporates the enormous amount of available data in this field with significant remaining reserves. The company management philosophy includes all areas of development from the utilization of the strong technical staff through the full exploitation of the available data set. The use of outside consulting and training is included to take advantage of technological advancements since the field was originally developed. The need to breakdown the traditional barriers between disciplines is also demonstrated. Building trust, communication, and a working knowledge of all involved disciplines is critical for exploiting Mann Field to its full potential.
Determining Realistic Fracture Conductivity and Understanding Its Impact on Well Performance—Theory and Field Examples
Authors: Palisch Terrence , Duenckel Robert , Bazan Lucas , Heidt Harmon J. , Turk George
Published: December 2007

To hydraulically fracture a well requires large investments in equipment, horsepower, materials and manpower. An engineer can be overwhelmed with the selection of completion fluids, perforation strategy and treatment size, as well as coordination of frac crews. In the end, however, the primary characteristic of the treatment that provides any economic benefit is a conductive fracture that economically increases well production.

Although the primary goal of a hydraulic fracture is to create a highly conductive flowpath, it is often the most poorly understood parameter in the treatment, with pressure transient and rate transient testing frequently indicating disappointingly short fractures of limited conductivity. In order to design an optimized fracture treatment, it is imperative that numerous factors be understood, including proppant embedment, formation spalling, temperature degradation, conductivity loss over time, non-Darcy flow, multiphase flow, non-uniform proppant distribution, cyclic stress, gel damage, fines migration, and other effects.

This paper introduces many of these factors and describes their individual impacts on fluid flow within propped hydraulic fractures. It will also demonstrate the cumulative effect of many of these factors upon fracture conductivity and calculate the corresponding impact on well performance. A fracture treatment optimized to accommodate these damage factors will be shown to differ dramatically from treatments in which these phenomena were ignored.

The authors present field data demonstrating that these effects are not only real, but can substantially impact well productivity. A field study in which the operator intentionally designed fractures to better accommodate these effects will be shown to significantly improve conductivity and fracture half length, as well as production and profitability. Readers of this paper will be armed with a more realistic view of fracture conductivity and fluid flow within propped fractures which, when incorporated into fracture designs, will yield more optimal fracture stimulations, improved production rates, and superior economic returns.
A New Correlation for Relating the Physical Properties of Fracturing Slurries to the Minimum Flow Velocity Required for Transport
Authors: Brannon Harold D. , Wood William D. , Wheeler Richard S.
Published: December 2007

Optimization of effective fracture area is among the principal tenets of fracturing design engineering. It is well understood that effective fracture area is a first order driver for well productivity, and that optimization of effective fracture area is often critical to economic exploitation of reservoir assets. Extensive testing in a large-scale slot apparatus was conducted to evaluate the relative effects of various component and treatment parameters on the proppant transport capability of various slurry compositions. The acquired data were utilized to determine the minimum horizontal slurry velocities necessary for proppant transport using the respective slurry compositions.

An ‘index’ to define the physical properties of a given proppant and fluid composition was defined. An empirical model was then derived to determine the minimum horizontal flow velocity required for suspension transport of a given slurry composition based upon its Slurry Properties Index. The minimum suspension transport velocity may then be compared to the flow velocity profiles from fracture design programs to estimate the propped fracture length likely be observed for those conditions.

Utilizing the new model, the most favorable combination of fracturing slurry component properties and pumping parameters can identified and incorporated in fracturing treatment design and applications to optimize effective propped fracture length, and thereby well performance.
Lessons Learnt from Reservoir Studies on Application of Multilateral Wells
Authors: Jalali Y.
Published: December 2007

This paper is based on a collection of studies, partly published partly unpublished, where the performance of multilateral wells is assessed from the viewpoint of reservoir drainage. The underlying studies range from case study of multilateral wells with production history, to feasibility studies of multilateral wells (in land, platform, and subsea fields), to generic studies by numerical methods and optimization techniques on reservoir drainage efficiency of multilateral wells. This paper will not reproduce a full account of those studies, rather it will highlight the key lessons latent in those studies which may serve as useful guiding principles for those contemplating or planning use of such wells. Specifically, the paper addresses how multilateral wells fare against the more conventional or traditional horizontal wells. The key concepts are summarized in four ‘lessons’ pertaining to high-drawdown, low-drawdown, multi-reservoir, and injection applications. Brief mention is made also of aspects other than reservoir drainage (or injection) efficiency that can influence the choice of well architecture.
Avoiding Pitfalls When Upscaling Core Data
Authors: Kennaird T.
Published: December 2007

Core data being considered for upscaling must be evaluated to determine they are reservoir representative.

Some key considerations:

Is the core vertically and laterally representative? Did anything happen to the core during retrieval or subsequent handling which may have caused unrepresentative data to be acquired? Was the core sampled to honour lithological heterogeneity? Were the core analysis methods compatible with petrophysical properties? Did the core analysis method represent not only reservoir conditions such as net overburden pressure, but also such parameters as the anticipated production mechanism?

Core data should be thoroughly screened in this manner to ensure their suitability for upscaling. At this point, the upscaling method must then be judiciciouly considered.

Practical examples illustrating the above points are given throughout the paper.
Data Visualization Challenges for Displaying Laboratory Core and Flow Data in Three-Dimensions
Authors: Siddiqui Shameem , Khamees Aon A.
Published: December 2007

Saudi Aramco made significant progress in the last few years in setting up immersive visualization laboratories for displaying three-dimensional data on its reservoirs, wells and their trajectories. While the 3-D reservoir models using a combination of seismic, geological, well testing and log data make the displays very impressive, the essential building blocks represented by the core data are mostly absent in these visualization efforts. Core descriptions and core photographs, although have been collected for a very long time were not easy to integrate due to their analog nature. Recently progress has been made in collecting core data in digital format through core imaging, digitizing, 360-degree core photography and CT-scanning. CT has been used in Saudi Aramco for more than 10 years to generate non-destructive images of reservoir cores. However, lack of proper three-dimensional image processing software limited its use to two-dimensional image slices only. Saudi Aramco R&D Center recently undertook a project which involved testing the performance of several three dimensional image processing packages in displaying data generated by a CT-scanner. The results were very promising. Some of the software not only displayed the static data on cores but were also able to capture the dynamic sequences from laboratory waterflooding and acidizing experiments. The 3-D visualization added a new dimension to these tests as they allowed the users to evaluate and compare the performances of various treatments before they are actually implemented in the field.
Overview and Dissemination of Case Histories Pertaining to Re-Entry Whipstocks from a Coiled Tubing Deployed Perspective
Authors: Mackenzie Gordon RJ. , Wilson Steve B.
Published: December 2007

This paper will focus on providing the reading audience with a general overview of the practice of utilizing a whipstock methodology with the conveyance method of coiled tubing in order to create a casing / liner window. The overview will discuss general practices, tool selection criteria and provide case history demonstration of such. The case histories demonstrated will be representative of placement of the whipstock with both electric wireline and coiled tubing with actual window milling being performed with coiled tubing and workover motors. The case histories will encompass monobore applications, through tubing re-entry environments, fluid operations and also under balanced nitrogen driven applications.
Planning and Identifying the Best Technologies for Extended Reach Wells
Authors: Gupta Adit
Published: December 2007

This paper on ERD wells focuses on nearly all important aspects of drilling ERD wells. Various case studies have also been taken while discussing various aspects so as to signify the practical experience of ERD wells. The latest technology for drilling ERD wells has been taken up. This paper will discuss the planning of ERD wells, the latest technology for ERD wells, the consideration of drill pipes and drilling fluid design for ERD wells, completion of ERD wells, well control and fishing and workover tools for ERD wells.

At the end, suggestions have been given so as to get better results for ERD wells.
Heavy Oil Displacement by Thermal Recovery Using Different Horizontal/Vertical Wells Configurations
Authors: Alajmi Abdullah F. , Algharaib Meshal , Gharbi Ridha
Published: December 2007

The use of horizontal wells in oil industry has increased rapidly during the last decade. The main reason for this upsurge is that wells provide large contact area with the reservoir and therefore enhance the well productivity or injectivity better than conventional vertical wells. The high productivity coupled with the recent advances in drilling technology for horizontal wells has made their application to be an economically viable option.

The study will investigate by numerical simulation technique the performance of horizontal injection wells with production vertical wells in thermal recovery processes. A high resolution numerical simulator (ECLIPSE) will be used during the course of this research. Extensive three-dimensional, fine-mesh simulation runs will be performed to determine the oil recovery under different operating/reservoir conditions. The purpose will be to study the functional relationship between several design parameters and the oil recovery from horizontal/vertical wells configurations during thermal flooding. These parameters will include: (1) configurations of horizontal and vertical wells, (2) flood patterns, (3) Horizontal well length, (4) Mobility ratio.
Identification of Hydrocarbon Moveability and Type from Resistivity Logs
Authors: Hamada G. M.
Published: December 2007

Resistivity data is normally used to evaluate water saturation using porosity values from porosity logs (neutron and density). Determination of initial oil (gas) in place is based on hydrocarbon saturation, porosity and thickness obtained from openhole logging data for a given drainage area. It is important not only to determine the initial hydrocarbon in place, but also to define the existing hydrocarbon moveability, indicating the recoverable hydrocarbon and its type.

This paper presents a new approach of hydrocarbon moveability factor (HCM). This factor is derived from shallow and deep resistivity data. The relation F = a/ϕm is correct in water saturated zones, in partially saturated zones this relation becomes invalid and it will give the apparent formation resistivity factor (Fa). Based on this idea the hydrocarbon moveability factor (HCM) has been derived. With scale goes from 0.0 to 1.0. It is found that for HCM less than 0.75, hydrocarbon is moveable and for HCM greater than 0.75, the hydrocarbon is immoveable. When HCM is less than 0.25, the moveable hydrocarbon is gas and for HCM greater than 0.25 and less than 0.75, the moveable hydrocarbon is oil. Field examples have been analyzed with the HCM factor. These field examples demonstrated the contribution of HCM in the field of hydrocarbon type identification and determination of hydrocarbon moveability from openhole resistivity logging.
A Case Study: Re-fracturing of High Temperature Deep Well in Carbonate Reservoir
Authors: Wang Yonghui , Zhang Fuxiang , Cheng Xingsheng , Peng Jianxin , Li Yongping , Li Suzhen
Published: December 2007

To compare the effect of different stimulation techniques on carbonate reservoir and optimize the techniques, Well T was selected as a case study to test with Mini acid fracturing, cross-linked acid fracturing and hyrraulic fracturing in the same pay zone. The study showed that the effect of cross- linked acid fracturing was better than mini gel acid fracturing, and hydraulic fracturing technique was the best comparing with the others. The new idea and methods for the carbonate reservoir stimulation was gotten from the success of the 3 tests on the well.

Well T is a key wildcat well on some reef foreshore body. The well was an openhole well which was drilled on August 11th, 2004 till the depth of 4925m in Ordovician. The target zone was 4913.52-4935.00m, and the reservoir temperature was 120 °C. show was good in the target zone when drilling, and the well flowed 28936m3/d gas and a little crude oil with 8.825MPa of tubing pressure using 6mm choke without any stimulation.

Mini -acid fracturing was conducted in this well and 102m3 of gel acid was pumped on September 23, 2004. The production of gas and oil were 44270m3/d and 8.26m3/d respectively using 5mm choke at 14.463MPa of tubing pressure after the mini-acid fracturing.

Surface cross-linked acid fracturing technique was conducted on the same target zone on October 17th, 2004. 538m3 of fluid was pumped into the formation including 230m3 of pad fluid, 230m3of cross-linked acid, 56m3 of gel acid and 22m3of flush fluid. The rate was 3.5-5.6m3/min and wellhead pressure was 58-82MPa.The well produced 19906-51485m3 gas and 19.3m3 oil per day with the tubing pressure 14.99-10.03MPa using 5mm choke after the cross-linked acid fracturing.

Hydraulic fracturing was done in the same well on November 9, 2004. A total of 473.1m3 of fluid including 47m3 of proppant was pumped into the wellbore (12.2m3 40-60 mesh and 23.3m3 20-40 meshes). The well produced 33907m3 gas and 28.69m3 oil (crude oil density 0.8575 at 20 °C, no water) per day with the tubing pressure 9.48-10.3MPa using 6mm choke after the treatment. The result was encoursging.
Application and Realization of Fuzzy Method for Selecting Wells and Formations in Fracturing in Putaohua Oilfield: Production And Operations: Diagnostics & Evaluation
Authors: Dinghong Cao , Yuwei Ni , Fei Yao , Dingwei Weng , Fu Guotai
Published: December 2007

As the Putaohua oilfield developing, the fracturing stimulation effect is getting worse gradually, and the low efficient wells are taking a larger and larger proportion. This paper discover the oil stimulation rules of fracturing wells through statistical analyzing 300 wells’ production data before and after fracturing in Putaohua Oilfield. Based on the rules, mathematic model deduced by fuzzy method was used to instruct selecting wells and formations of fracturing wells. The application results show that the method is effective and easy to exercise, so it could be a ground for selecting fracturing wells and formations in Putaohua Oilfield in the future.
Effective Stimulation of Horizontal Wells - A New Completion Method
Authors: Seale Rocky , Themig Dan , Athans James
Published: December 2007

Over the last several years there have been many developments in horizontal completions. These advancements have been designed to better stimulate the entire horizontal interval. The most notable advancement has been used in cased and cemented liner applications, where composite plugs have provided the mechanical diversion that has successfully stimulated the entire horizontal wellbore. However, the process of setting a plug on coiled tubing (CT), perforating, stimulating and then repeating the process for the required number of stages to optimize production and then running back in with CT to remove the plugs is costly and time prohibitive in many cases. In open hole applications, horizontal stimulations have relied almost solely on limited entry or bullheading in attempts to induce multiple fractures. This method has proven very inefficient and unsuccessful.

A new completion system has been developed that addresses all of the prior issues in stimulating horizontal wells. This system uses a series of mechanical open hole packers deployed on the production liner with fracturing or stimulation ports located between the packers that allow for stimulation in each desired interval. Without the requirement of cementing the liner in place, all the problems associated with cementing are eliminated. By placing a liner in the open hole section rather than leaving it barefoot, accessability and production issues are more easily addressed. Additionally, the mechanical packers provide mechanical diversion at high differential pressures. The system has also been designed, so all of the fracturing or stimulation treatments along the horizontal wellbore can be pumped in one continuous operation, thus minimizing all the associated risks and optimizing the efficiencies for both the personnel and equipment. With hundreds of jobs completed, this paper will detail the operational efficiencies and reliability of this completion system, as well as analyze the cost benefits and production increases that have been noted.