bluuebunny/crossref_metadata_2025 huggingface dataset:
Effect of Fracture Conductivity on Effective Fracture Length
Authors: Lolon Elyezer P. , McVay Duane A. , Schubarth Stephen K.
Published: December 2007

Fracturing fluid that remains in the fracture and formation after a hydraulic fracture treatment can decrease the productivity of a gas well by reducing the relative permeability to gas in the region invaded by this fluid. This fluid can block the gas flow into the fracture, thus reducing the effective fracture length. Pressure transient tests performed on hydraulically fractured wells often reveal that the effective fracture half-lengths are substantially less than the designed length from fracture stimulation.

In this work we used reservoir simulation to determine the relationship between fracture fluid production, effective fracture length, and gas productivity. While the effective fracture length is affected by such factors as non-Darcy flow, it is related directly to fracture cleanup, and increases with time. From this study we found that the rate of fracture fluid production is affected significantly by the conductivity of the fracture. Greater dimensionless fracture conductivity results in more effective well cleanup, longer effective fracture lengths versus time, and greater effective stimulation of the well.

The results of this study provide a better understanding of the gas production behavior from wells hydraulically fractured using water-based fracturing fluids. The relationships between fracture conductivity, effective fracture length, and gas productivity presented in this paper can be used in economic calculations to balance the costs of higher fracture conductivity against the additional revenue resulting from longer effective fracture lengths. Results presented will allow operators to better design optimal fracture lengths for typical gas reservoirs.
Prediction of Gas Hydrates Formation With DSC Technique
Authors: Dalmazzone C. , Herzhaft B. , Rousseau L. , Le Parlouer P. , Dalmazzone D.
Published: December 2007

With the increasing number of deep offshore drilling operations, operators and service companies are now faced with new problems related to the possible formation of gas hydrates in drilling muds. Actually, the appearance of gas hydrate crystals in drilling fluids can lead to dreadful effects and safety problems, like modification of mud rheological properties, interruption of the drilling operations due to plugging and even destruction of rig equipment when gas hydrates dissociate. Propulsion of gas hydrate plugs at very high velocity is also a great risk. To prevent these problems, formulations of drilling muds (WBM or OBM) have to be optimized with thermodynamic inhibitors of hydrate formation (salts and glycols), which cause important problems of density adjustment, corrosion and toxicity.

In previous papers (SPE 62962, 71379), an innovative calorimetric technique (DSC) was presented to characterize hydrate formation in drilling mud up to 100 bar. This rapid, easy and reliable technique was applied to fluids of increasing complexity, from solutions and emulsions to complete oil-base and water-base muds. Results were validated from classical PVT measurements.

In this study, this work was continued on thermodynamic properties of hydrate formation in complex solutions. The main objective was to establish phase diagrams of ternary and quaternary mixtures (water-CH4-salt and water-CH4-salt-glycol) and also to understand the mechanisms that govern hydrate formation in such mixtures.

In parallel, a new microcalorimeter was developed, that allows measurements on gas hydrates up to 400 bar, whatever the mud composition (WBM or OBM). This apparatus can analyze complete muds, in presence of solids, and is designed to be implemented on drilling platforms. Hence, it will be possible to follow the risk for hydrates formation as a function of drilling conditions on site. Furthermore, this apparatus will allow the establishment of a database on different muds. A coupling of this database with a software that calculates the thermal profile along the riser should give birth to a predictive method for gas hydrate formation risks.
Brine Imbibition Damage in the Colville River Field, Alaska
Authors: Erwin M. D. , Pierson C. R. , Bennion D. B.
Published: December 2007

Early exploration well tests in the Colville River Field (also known as Alpine) drilled with water-based mud systems exhibited unexplainably high near-wellbore residual skin damage documented by pressure build-up testing. Typical formation damage mechanisms including clay reactions, mechanical damage, and gas trapping could not explain the damage.

Between March 1998 and July 2001, laboratory testing determined imbibition-induced water trapping to be the primary formation damage mechanism. Insitu water saturation is significantly lower than the residual or connate water saturation, a condition rarely encountered in the field. Lab tests quantified impacts and identified methods to minimize or eliminate formation damage. This paper documents how successful identification of a unique damage mechanism improved drilling results in a low permeability sandstone.
Even Optimists Should Optimize
Authors: Bratvold Reidar B. , Begg Steve H. , Campbell John M.
Published: December 2007

The industries interest in formal Decision and Risk Assessment (D&RA), including portfolio optimization, over the last few years has been quite amazing and somewhat surprising. Overcoming the barriers to adoption of these methods, including cultural change, continue to amaze even the most devout practitioners. Whether the drivers for accepting change emanate from the changing business climate that has been motivating recent mergers, political risks, a historical record of underperformance or just continued evolution of business practices, the desired objective remains the same - making good investment decisions.

The growing popularity of D&RA - as indicated by the number of SPE sponsored forums and ATWs, alliances and industry courses on the subject and the general uptake of the language, like P10 and P90 - support the increasing awareness of D&RA methods as a mechanism for improving industry performance. The underperformance of petroleum stocks relative to the entire stock market has been cited by several to justify the even greater adoption of D&RA methods. Though artificial bubbles in telecommunications, dotcoms, and energy trading certainly explains part of the underperformance of traditional industry stocks, like petroleum, serious questions remain about the industries' ability to actually achieve the performance in its investments that is promises in its evaluations. The gap between the promises and performances and possible causes for the gap form the foundation of this paper.

As demonstrated by Campbell, Bratvold and Begg,1trying to address complex portfolio issues with approximations may significantly overstate returns and mislead investors into selecting projects and portfolios that fail to deliver the promised performance. In this paper we are extending this work by pursuing the basic question of the impact of individual and corporate risk attitudes in the context of portfolio selections.

We begin by briefly reviewing the basic approach to efficient frontier optimization for portfolio selection. The concept of utility is introduced and it's application for portfolio level decision is discussed. We then introduce the concept of indifference curves which, in combination with efficient frontier optimization, provides an elegant approach for identifying the optimal portfolio for a risk averse corporation.

As in Campbell et al,1 we are addressing the portfolio selection issue with the intent of emphasizing that trying to address complex issues with a na ve or poor understanding of the impact of individual or corporate reaction to risk, may lead to overoptimistic expectations and subsequent failures to deliver on commitments.
Assessing the Kinetics and Capacity of Gas Adsorption in Coals by a Combined Adsorption/ Diffusion Method
Authors: Siemons Nikolai , Busch Andreas , Bruining Hans , Krooss Bernd , Gensterblum Yves
Published: December 2007

Storage of carbon dioxide in geological formations is for many countries the only option to reduce greenhouse gas emissions and thus to satisfy the Kyoto agreements. The CO2 storage in unminable coal seams has the advantage that it can sequestrate CO2 emissions from industrial processes and be used to enhance coal bed methane recovery (CO2-ECBM). For this purpose, the storage capacity of coal is an important economical parameter.

An experimental set-up has been developed to determine the rate of adsorption of gases such as carbon dioxide and methane in coal. Sorption kinetic experiments were carried out at various pressures and on coal particles with varying grain sizes (40μm-2mm diameter). The particles were considered to consist of aromatic aggregates embedded in amorphous aliphatic coal, intersected by cleats. The characteristic time of adsorption increases with increasing pressure and increasing particle diameter. However the characteristic time increases only for very small particles. This is attributed to the presence of cleats inside the larger particles. From the experiments it appears that water inhibits diffusion due to its presence in the small particles or in the small cleats. The results of the diffusion experiments can be described by an upscaled diffusion -adsorption model. Based on this model and the experiments an accurate assessment of the storage capacity can be achieved.
Liquid Management on Canyon Express
Authors: Cooley C. , Wallace B. K. , Gudimetla R.
Published: December 2007

The Canyon Express (operated by Total E&P USA Inc.) subsea development consists of 10 subsea wells each tied into one of two 57 mile, 12" flowlines, that extend from the deepest wells at 7250 foot water depth to a shallow water host platform at 300 foot water depth. Although the production is a relatively dry gas, there exists some volume of liquid that returns to the platform with the gas as a result of produced liquids and return of methanol injected for hydrate remediation. Because of the extreme lengths and depths of the Canyon Express flowlines liquid management has been a significant concern with extensive transient and steady state analysis being performed throughout the project design phase to evaluate the behavior of the liquid in the flowlines. Complex transient flow models, including flow line and topside facilities characteristics, were developed and numerous simulations executed to determine the optimal and feasible operation for the multiphase fluid Canyon Express flowlines under various conditions during field life. During start up and the early operation of the Canyon Express system the actual results for liquid holdup and flow were documented for various well ramp-up scenarios. The purpose of this paper is to compare results from the design phase for liquid management on Canyon Express with actual operating conditions and summarize the evolution of the current operating philosophy. The original transient and steady state analysis will be compared to the actual conditions experienced in the operation highlighting lessons learned in flow modeling and other assumptions made. This paper will demonstrate the usefulness of extensive transient and steady state analysis on projects with complex flow conditions and the importance of incorporating the conclusions of the analysis into implementation plans that can be subsequently adjusted to reflect the actual field conditions.
Measuring Interactions of Dynamic Fluid Mixing and Heterogeneity for Gas EOR Processes
Authors: Lee Sheng-Tai , Moulds Tim P. , Solano Reinel , Lin C. Y. , Ballin Paulo R.
Published: December 2007

Sweep efficiency is a key subsurface parameter that determines the economic viability of miscible-injectant (MI) EOR project. It is controlled by interactions of fluid mixing and heterogeneity on the reservoir scale. We propose a method to measure the sweep efficiency for MI EOR projects. Our method involves using fine-grid two-component miscible reservoir simulation, combined with a one-dimension convection-diffusion model, to determine effective parameters that control reservoir-scale mixing.

We demonstrate the applicability of the proposed method by performing the miscible simulations for 5 type-pattern models (TPM's) of the Prudhoe Bay Miscible Gas Project. The EOR oil recoveries, calculated by fine-grid EOS compositional simulations, for the 5 TPM's are shown to correlate consistently with the effective macro-dispersivity determined through the analytical one-dimension convection-diffusion model. The effective macro-dispersivity, obtained through the proposed method, therefore can be used to measure the effect of heterogeneity on sweep efficiency and to rank reservoirs for EOR applications. The established trend then allows us to investigate different realizations of reservoir description on the EOR oil recovery with substantial saving of time. Our results also indicate that a consistent method must be used to develop reservoir descriptions when comparing and ranking sweep efficiencies for different reservoirs for an EOR project.
Compositional Upscaling in Heterogeneous Reservoirs: Effect of Gravity, Capillary Pressure, and Dispersion
Authors: Ajose D. , Mohanty K. K.
Published: December 2007

Effect of a fractured zone on transport of gas-condensates during lean gas recycling through an otherwise homogeneous medium is studied here. Transport of components is upscaled by the alpha factor method for a single-porosity, coarse-grid model. Fine-grid discrete fracture model is used to simulate primary drainage followed by lean gas recycling. Fracture orientation, gravity and capillarity affect alpha factors significantly. Horizontal fractures have lower alpha factors than vertical fractures. Down dip injection increases alpha factors. Capillarity increases alpha factors. Diffusion does not affect alpha factors at the scale studied. Three-dimensionality of the fine-grid simulation decreases alpha factors over those calculated with two-dimensional simulations.
A Two-Level Optimization Method for Geostatistical Integration of Production Data on Non-Uniform Grids
Authors: Tureyen Omer Inanc , Caers Jef
Published: December 2007

Fine scale heterogeneities can have significant effects on flow performances in subsurface formations. Highly detailed geostatistical realizations are needed to capture the quantitative effects of these heterogeneities on flow simulation results based on high resolution well-log and medium resolution seismic data. These realizations in many cases require number of grid cells on the order of 106-107, hence making it too demanding CPU wise to directly history match geostatistical models. Non-uniformly gridding these models for emphasizing the heterogeneities does not necessarily present a solution since the practice of geostatistics on non-uniform grids is inefficient.

In this paper we provide an entirely new approach to these problems by proposing a solution which is geostatistics based yet having the flexibility to work on non-uniformly gridded models. Hence coupling geostatistics with non-uniformly upscaled models results in an effective history matching technique incorporating all information at their scales. With the proposed approach we mainly target three advantages. Well and seismic data will still be effectively incorporated in the realizations. Flow simulations will be performed on non-uniformly upscaled models hence will be relatively fast. Finally the resulting field which is history matched will include the geology and will be on a non-uniformly gridded model for emphasizing heterogeneities or desired specifications, hence future predictions can be made fast, no posterior upscaling is required. The latter will avoid upscaling errors.

This new approach is based on making a fast non-uniform upscaling technique a part of the history matching process instead of performing upscaling first and then downscaling again. Two levels of optimization are introduced in this technique; one level for history matching (outer loop) and the other for optimizing the non-uniform grids based on the results of a fast but realistic flow response (inner loop). In this paper we show how we benefit from a pre-optimized solution in conditioning reservoir models to production data.
Use of PEBI Grids for a Heavily Faulted Reservoir in the Gulf of Mexico
Authors: Melichar Herbert , Reingruber Alan J. , Shotts Douglas R. , Dobbs Walt C.
Published: December 2007

Creation of a simulation grid that accurately represents the reservoir and enables efficient numerical solutions is often one of the most important steps in constructing a reservoir simulation model. Complex structural settings can present particular challenges in this respect. This paper demonstrates a novel approach to this problem: the use of PEBI grids, which are unstructured and extremely flexible, with a commercial reservoir simulator that was designed primarily for structured Cartesian or corner-point grids.

This unconventional combination of techniques is accomplished without a significant change in workflow. The PEBI grid – a combination of Cartesian and irregular grid blocks – is first built to represent the necessary geologic and well detail. Then the grid is made compatible with a conventional reservoir simulator by treating the irregular parts of the grid as non-standard gridblock connections to their neighboring Cartesian blocks.

The business example comes from a development study of a highly faulted reservoir group located in the Gulf of Mexico. Associated structural complexity includes steeply dipping beds, sloping, directional wells cutting through faults, and interbedded shale layers. A comparison of simulation results from PEBI and conventional rectangular and curvilinear grid-based models illuminates the advantages of PEBI grids for this project: a more accurate representation of geologic detail with less effort, more computational stability, and reduced cycle times for model updates following geologic model revisions.
Identification of Tidal Signal in Well Test Pressure Data
Authors: Levitan Michael M. , Phan Vinh
Published: December 2007

The bottomhole pressure measurements acquired during well tests sometimes contain oscillating components associated with tides. When present in well test data, tidal pressure oscillations may mask reservoir related transient pressure behavior. Hence, from pressure transient analysis point of view the tidal signal is a parasitic feature that has to be identified and removed from the test pressure data. At the same time, the tidal signal itself depends on formation properties. For example, amplitude of tidal oscillations depends on formation compressibility. Therefore, identification of tidal signal in downhole pressure data provides a means for monitoring the reservoir compressibility changes associated with reservoir fluid movements and long-term production.

Compared to the pressure variation during a well test, the amplitude of the tidal pressure signal is normally very small. This makes it very difficult to identify the tidal signal in the test pressure data. In this paper, we present a special algorithm for identification of tidal signal in downhole test pressure data.
Horizontal and Deviated Wells Water Disposal Injection Experiences in a Venezuelan Heavy Oil Reservoir in the Orinoco Belt and Future Injection Practices
Authors: Briceño M. C. , Peralta J. A. , Silva R. J. , Rismyhr O. , Zerpa L. B. , Ehlig-Economides C. A.
Published: December 2007

Data acquired from permanent pressure gauges over 2 years in a water disposal wells in the Zuata Field, Orinoco Heavy Oil Belt, has revealed significant injectivity declines. Pressure transient analysis over the entire period on a flow period by flow period basis is complicated by severe fluctuations in the injection rate during injection flow periods and rarely analyzable falloff periods. Injectivity is inhibited by large skin at all times. A very strong correlation between injectivity index and skin was determined from pressure transient analysis, which also provides a very high value for the rock permeability thereby quantifying the very high theoretical injectivity expected in the wells.

Several hypotheses are considered in order to explain the steep decline in injectivity decline. One of the hypotheses was sanding because it occurred in one injection well when it was shut in quickly and/or under severe fluctuations in rate. Another hypothesis is formation plugging. One possible cause for formation plugging may be a salinity contrast between the injection water and the original formation water, which could activate clay swelling. A second possible cause is formation damage caused by solids and/or organic contaminants in the injection water.

In addition to investigations to evaluate the various hypotheses to explain the injectivity decline, a decision was taken to try horizontal injection wells, also equipped with permanent pressure gauges, and in addition, distributed temperature surveillance via fiber optic installed along the entire drilled length of the well.

The data from the various wells equipped with permanent pressure gauges and distributed temperature surveillance was augmented by core analysis and laboratory studies of the injection water. The analysis has indicated which the main causes of the injectivity decline are, and measures are being taken to correct the problem.
Using Multiple Reservoir Measurements to Improve Subsurface Description in Deepwater Gulf of Mexico: King Field
Authors: Haddad Sammy , Simms Gerard , Clerk Colin
Published: December 2007

King Field is located in the Deepwater Gulf of Mexico (GOM) about 110 miles SE of Venice, Louisiana in Mississippi Canyon blocks 84, 85, 128, and 129 (Fig. 1). The main sand, the Upper Miocene 70 (UM 70), is an undersaturated oil reservoir. The sands were deposited by gravity flow processes within an intraslope basin. The formation is highly porous and permeable (31%, 1000md). Lateral and vertical heterogeneities identified by seismic amplitudes and Amplitude Versus Offset attribute analyses have been confirmed by, and calibrated to, well logs, cores and flow tests. Sedimentary facies studies have shown that at least two different styles of deposition are present; lower massive sheet sand, and an upper sand which is more variable and probably channelized. The trap is a three-way antiformal closure against a major fault with a hydrocarbon column of 1400 ft. Fig. 1King field location map.

Permeability and pressure data were obtained from core, nuclear magnetic resonance (NMR) measurement, MDT* Modular Formation Dynamic Tester, closed chamber, flowback and recent permanent gauge data. This paper compares and demonstrates the utilization of results from each source of measurement on different wells. Differences and agreements of these data are discussed.1

This work demonstrates the use of these data to define a geologic model and better predict well productivity and reservoir continuity. Lessons learned from integrating these multiple sources are summarized.
Comparison of Two Low-Permeability Horizontal Devonian Projects in the Permian Basin with Competing Completion Techniques
Authors: Edgeman J. R. , Walser D. W.
Published: December 2007

Detailed production data from 32 horizontal Devonian wells in the Permian Basin was studied to determine if the impact of various completion methods might be distinguished from an existing reservoir overprint. Flowing transient pressure analysis was utilized to determine effective permeabilities, contributing lateral lengths, and respective drainage radii. Production and economic performance on each well were normalized for permeability, productive zone height, porosity, and initial static reservoir pressure, so that examinations into various completion processes would be more meaningful. Multiple physical parameters and controllable process variables were then plotted versus normalized net present value.

A fully coupled three-dimensional reservoir and wellbore simulator was employed to match historical results and extrapolate conclusions beyond the narrow confines of the two projects.

Some wells in the study were completed with cemented liners, and others completed with pre-drilled uncemented liners. A direct comparison is made between the two completion styles.
Case History of Hydraulic Fracture Performance in a Channel Reservoir
Authors: Liu Xinghui , Cipolla Craig L. , Mayerhofer Mike
Published: December 2007

This paper presents a detailed case history of hydraulic fracture performance in exploratory gas wells in the Hanoi Trough, Vietnam. The target formations are stacked fluvial channel deposits that occur at depths of 10,000 to 12,000 ft. The target D14 interval consists of low permeability, over-pressured gas reservoirs. The wells were fracture stimulated in an attempt to improve deliverability. This paper provides a brief summary of previous fracture treatments, but focuses on the fracture design, execution, fracture modeling, and post-treatment reservoir & production analysis from the most recent fracture treatment. A comprehensive data set of logs, pre- and post-fracture pressure buildup tests (PBU's), and detailed fracture modeling was utilized to understand fracture performance in this complex channel reservoir environment. This paper documents how an integrated study can be used to identify channel reservoir shape/size, understand fracture performance, and optimize fracturing treatments & reservoir development.
Operation of Ultra-Deepwater Gas Wells With Failed Down Hole Gauges
Authors: Sutton Robert P. , Guillory Terry L. , Cox Stuart A.
Published: December 2007

This paper provides a case study of Marathon's Camden Hills gas field, located in world record water depth of over 7,200', in Mississippi Canyon Block 348. Two wells were completed and tested during late 2001 and the first half of 2002. The down hole pressure/temperature gauges failed in one of the wells as it was being unloaded and tested, only providing a static bottom hole pressure. The other well was unloaded and tested, and the down hole gauges provided valuable information about reservoir and completion performance parameters. Prior to production startup in the fourth quarter of 2002, the second well's down hole gauges failed.

Prior to production start-up, well performance models were constructed for each well utilizing the limited data obtained prior to downhole pressure and temperature gauge failure. Operational procedures were developed to provide a methodology for acquiring data necessary to quantify well performance. The master MCS for the subsea system, located at the host platform gathers electronic data received from the wellhead pressure/temperature sensors and the multiphase flow meter. This data is transmitted into an internet web site allowing all participants access to real time data. This data is then input into the prediction models so performance can be monitored and updated. The Gas Production Analysis (GPA) technique was utilized as a further check of reservoir and well performance. Successful implementation allowed the well's performance metrics to be monitored and adjusted to maximize withdrawals while minimizing the potential for premature failure.
A Novel Low-Temperature, Forced Precipitation Phosphonate Squeeze for Water Sensitive, Non-Carbonate Bearing Formations
Authors: Lynn Jack D. , Nasr-El-Din H. A.
Published: December 2007

A novel carbonate/sulfate scale squeeze treatment specifically targeted to low temperature, low pressure clastic formations was developed, and successfully applied to Saudi Arabian formation, designated H-A.

A number of different remediation techniques were reviewed. They ranged from adsorption and precipitation squeezes to encapsulated treatments. Due to the low temperature of the field (<160 °F), and the low pressure of the formations, a non-traditional scale squeeze was required. Adsorption squeezes are well documented, but have short return lives and would have required retreating every-6–8 months. Encapsulated squeezes delivered a very short life.

Naturally induced precipitation squeezes using organophosphonates (ATMP, ADMP) have been used to treat Saudi Arabian carbonates since 1986. Unfortunately, the H-A formation is a siliceous clastic reservoir (quartz > 98 wt. %) with little natural carbonates, and a natural precipitation squeeze would not be possible. It was decided that a forced precipitation would be used. A forced precipitation must contain the organophosphonate, a source of di-valent cations (usually, but not confined to Ca++), and a method of either raising or lowering the pH to change the solubility of the Ca-phosphonate derivative, and force precipitation. The change in pH required is a function of the phosphonate used, and a large number of options have been developed. Most however, require temperatures above 180°F to be successful.

This innovative method employs a multiple staged treatment using a diesel emulsified inhibitor/di-valent cation stage injected with pH control stages. The two aqueous stages cannot come into contact with each other until the emulsion breaks. The breaking time of the emulsion is controlled by the adsorption of the emulsifier onto the formation rock, and is not temperature dependent, as are urea-based systems. The formulation contains a clay stabilization chemical.

The treatment has been successfully applied to 25 wells, the first, H-53 nearly 36 months ago. This well has current returns nearly 0.1 mg /L organophosphonate, and has a projected treatment life of 2-3 years.
Estimating a Relationship between Pore Pressure and Natural Fracture Permeability for Highly Stressed Reservoirs
Authors: Kasap E. , Bush E. S.
Published: December 2007

A better understanding of production from fractured reservoirs that exhibit permeability reduction with lower bottomhole pressure (BHP) is required. A pore pressure versus permeability relationship, which is essential for optimizing field development scenarios, is also required.

In this study, several sets of well-test data from a naturally fractured reservoir were studied to quantify permeability reduction from pore-pressure drop with lower BHP. The tests indicated lower production rates with lower BHP. Various analyzing techniques were employed to determine the true reservoir characteristics. Regression analyses for naturally fractured and hydraulically fractured models were conducted, and reservoir rock properties were estimated.

The solution of the partial differential equation (PDE) formulating transient pressure solution for a 1D, infinite-acting fracture was superimposed for multiple rates to estimate initial fracture permeability. The deviations from conventional analysis results were investigated and used for generating a pore pressure versus effective fracture permeability relationship. The relationship developed was used in a numerical model in pressure-dependent permeability mode to simulate well test behavior. Transient pressure and rate data from the numerical model with pore-pressure-dependent permeability were compared with data from the field to verify the developed analysis technique. The numerical model satisfactorily predicted the field-test data.
Improved Water Injector Performance in a Gulf of Mexico Deepwater Development Using an Openhole Frac Pack Completion and Downhole Filter System: Case History
Authors: Shumbera David A. , Ritter David W. , Ellis Richard C. , Jannise Richard C. , Lochte Glen
Published: December 2007

A Gulf of Mexico deepwater subsea development project required seawater injection for pressure maintenance of the producing reservoir. Typical water injector performance in the Gulf of Mexico has been characterized by rapidly declining injectivities that could be partially restored by frequent acid treatments. This type of performance was unacceptable for this field development plan, which required one subsea water injector capable of injecting up to 25,000 BWPD continuously for up to five years.

Two changes to typical Gulf of Mexico water injector completion design were incorporated: 1) an openhole frac pack completion, and 2) a unique downhole filter system. These changes resulted in improved water injector performance compared with that typically experienced in the Gulf of Mexico. Initial injectivity was excellent and remained so over the entire injection period. No acid stimulations were required to either initiate or maintain injection.

This paper presents the design and installation aspects as well as the actual performance results for this water injector.
Well Perforation Using High-Power Lasers
Authors: Batarseh S. , Gahan B. C. , Graves R. M. , Parker R. A.
Published: December 2007

Conventional wellbore perforation techniques are designed to establish flow from the hydrocarbon-bearing reservoir through the cemented casing into the wellbore. The explosive force of shaped charges is focused and intensified into a small-diameter jet that penetrates the casing and cement into the reservoir rock. This process reduces reservoir rock porosity and permeability as metal and carbon debris are forced into the perforation tunnel, while very fine grain particles plug or reduce the pore throat size. As a result, it is necessary to perform time-consuming and costly post-perforation operations to minimize flow restrictions into the wellbore. Developing alternative perforation methods that reduce or eliminate formation damage could significantly boost production rates, cumulative production and overall economic returns.

The research team led by Gas Technology Institute (GTI) has demonstrated, through the application of high-energy lasers to rock samples, that damage to permeability and porosity of the adjacent zones cannot only be reduced, but that near-hole permeability in a reservoir sandstone can be increased up to 171%. By applying this technique downhole, perforations and other directionally controlled completion and stimulation methods could be employed without damaging the reservoir.

This paper presents the experimental methods and results of exposing sandstone, limestone, and shale rock samples to high-power laser beams. A grid pattern was applied to the rock samples from which acoustic velocity and permeability measurements in and near the perforated tunnel where taken. In addition, rock mineralogy and rock properties were analyzed before and after the test.
Pilot Tests in the Illinois and Western Interior Basins to Determine Commercial Productivity from Pennsylvanian Aged Coals
Authors: Green T. W. , Wolfe S. R. , Tedesco S. A.
Published: December 2007

Coalbed methane production is viewed as an attractive source for the growing US natural gas demand. Undeveloped resources of coalbed methane in the United States have been estimated at 60 Tcf1. A majority of the coal in the USA is accessible at shallow depths, making well drilling and completion inexpensive. Finding costs are also low since methane occurs in coal deposits, and the location of the nation's coal resources are well known.

Millions of acres of potential coalbed methane gas production identified in the Illinois and Western Interior Basins are currently being evaluated with multi-well pilot projects. The coals of interest vary from 300 to 2,300 feet in depth, have moderate to high ash content, low moisture content, and are High Volatile C to Medium Volatile in rank. The coal seams range in thickness from one to five feet and have gas contents of 1 to 325 scf/ton, with measured permeabilities on the order of .1 to 100 mD.

The primary purpose of a pilot test program is to determine gas deliverability potential and initial water production. Well spacing, time to dewater, and ultimately time to reach maximum gas production are crucial to overall project development economics. Secondarily, the pilot programs are designed to confirm gas contents and permeability estimates obtained from initial data wells.

The pilot wells are placed in such a way to maximize well-to-well interference during a reasonably short production test period (4 to 6 months). This paper presents the initial results of several ongoing pilot projects in both basins. Parameters such as full-field well spacing, water disposal requirements and facilities, artificial lift criteria, gas deliverability, and ultimate recoveries can be estimated and asset development economics determined.
Using Visualization Tools to Gain Insight Into Your Data
Authors: Plaisant C. , Chintalapani G. , Lukehart C. , Schiro D. , Ryan J.
Published: December 2007

When the term ‘visualization’ is used in the oil and gas industry, it is usually referring to the viewing of complex geologic structures in three-dimensional space. This paper illustrates insights gained by applying interactive visual environments to petroleum industry data that has traditionally been presented in spreadsheets, line graphs, and bar charts. Two information visualization tools, Treemap and SpaceTree, will be shown applied to a variety of oilfield related data.
Essential Components of an Integrated Data Mining Tool for the Oil & Gas Industry, With an Example Application in the DJ Basin
Authors: Mohaghegh Shahab D.
Published: December 2007

Data Mining seems to be the new buzz word. During the past several years many industries other than ours, have realized the potential benefits of Data Mining and have established sophisticated operations in order to implement this exciting technology in their respective organizations. Data Mining is not new. It has been around for many years. What is new about its current implementation is the incorporation of machine learning techniques. Oil & gas industry has become familiar with machine learning techniques since early 90s. Neural networks, genetic optimization and fuzzy logic have been used in numerous applications from well log interpretations to hydraulic fracturing optimization. Therefore, the new interest in Data Mining in our industry is not surprising. Our industry is at its peak state for benefiting from what Data mining has to offer, thanks to abundance of digital data.

A word of caution is in order, which has been the main motivation behind writing this paper. As with many other new tools and technologies, the term "Data Mining" can be, and is currently being, misused in several occasions. In this paper we attempt to answer questions such as, what is Data Mining. How can it be accomplished? What are the essential components of an integrated Data Mining process? What would be the benefits of such a process?

In addition to answering questions such as those mentioned above, this paper will provide a road map (a set of guidelines) for a successful Data Mining project. Finally the paper is concluded by applying the presented guidelines to a hydraulic fracturing data set in the DJ basin for a Data Mining study.
Development of the Industry's First Slimhole Point-the-Bit Rotary Steerable System
Authors: Stroud D , Russell M , Peach S
Published: December 2007

This paper describes the results of laboratory drilling tests, bottom hole assembly (BHA) software modeling, and field-testing of the industry's first slimhole rotary steerable system (RSS) using point-the-bit technology. The first system field-tested was 4-3/4 in. diameter for use in slimhole drilling with 6-in. bits. Test results show the RSS is controllable and predictable in behavior, and produces superior borehole quality.
Employing Neural Networks to Integrate Seismic and Other Data for the Prediction of Fracture Intensity
Authors: Boerner Sean , Gray Dave , Todorovic-Marinic Dragana , Zellou Abdel M. , Schnerk George
Published: December 2007

A non-subjective technique is presented to combine seismic based fracture detection from shear wave anisotropy with traditional well and structure data to produce a new generation of fracture intensity maps and volumes. Neural networks are easy to use and extremely useful for nonlinear regression where the functional form of the nonlinear equation between the independent and dependent variables are not known. We use a neural network for nonlinearly regressing a number of independent variables to predict fracture intensity within a reservoir. Several of the independent variables are derived from an amplitude versus angle and azimuth (AVAZ) process applied to pre-stack, P-wave seismic data. By examining the changes in reflectivity amplitude with respect to azimuth and incident angle on pre-stack seismic gathers, we can detect the presence of open, near-vertical fractures and their orientation. Seismic data has good lateral coverage, but poor vertical resolution versus well data, which has good vertical resolution, but is sparse laterally. The seismic attributes extracted from the AVAZ process are combined with 3D model attributes, such as porosity and lithology and structural attributes, such as the first and second derivatives of the structural surfaces to predict fracture intensity. Because fracture intensity information is sparse and difficult to obtain, we use expected ultimate recovery (EUR) as a substitute for fracture intensity. The four-month cumulative production provides a good estimate for EUR and is used as the fracture indicator in this study. The attributes are ranked according to their correlation with fracture intensity, and a subset of variables is selected as input into the neural network for the prediction of the fracture indicator. Multiple neural networks are trained on the data providing multiple solutions. These solutions, in the form of 2D maps or 3D volumes, are analyzed statistically to predict the fracture indicator and to high grade prospective drilling locations. In addition, the fracture indicator maps and volumes can be input into discrete fracture modeling tools for further analysis.
Converted Shear-Wave Anisotropy for Fractured-Reservoir Management
Authors: Gaiser James E. , Van Dok Richard R.
Published: December 2007

Fractured reservoirs have been encountered worldwide and in general they are profitably produced, however it is safe to say that none of them have been depleted efficiently. As the petroleum industry focuses less on exploration and in a market of rising costs it is becoming more important to recognize the presence of fractures early in the life of a field for optimal reservoir management. Fractures can significantly complicate the behavior of reservoir porosity and permeability, often resulting in numerous dry wells and higher production costs. A key strategy for fractured reservoir management is a quantitative description of the geology, geophysics and petrophysical attributes obtained from seismic methods during production and development.

3D multicomponent seismic surveys, where compressional waves excite shear-wave reflections (PS-waves), can provide complimentary surface-seismic information to help identify fracture properties early in the production history of a reservoir. Based on measurements of shear-wave azimuthal anisotropy, PS-waves can identify fracture density and strike, and because of their asymmetry they are also sensitive to fracture dip. Examples from both land and marine 3D PS-wave surveys demonstrate the potential of using these attributes to characterize subsurface stress variations that are important for open fracture development. The intermediate-scale seismic anisotropy properties obtained from PS-waves will be critical for solving specific production problems associated with different fractured reservoir types, and could improve reservoir modeling: production-history and pressure-test matching, and fluid-flow simulation. From an economic point of view, if PS-wave surveys acquired over the life of a field can prevent a small fraction of unproductive wells, they are worth the expense.
G·TE Correction for Processing Multigradient, Multiple-TE NMR Log Data
Authors: Chen S. , Hursan G. , Beard D. , Georgi D.
Published: December 2007

We have developed a data processing method that allows a valid integration, in the time domain, of echo trains acquired in different field gradients, G, and different interecho times, TE. The combined echo train can be used to obtain clay bound water (CBW), bulk volume irreducible (BVI), and total porosity information with improved vertical resolution. The same data, in the uncombined form, are used for fluid property estimation. Thus, the data are used more economically.

As an added benefit, the combined echo train allows the use of a single T2cutoff, consistent with the laboratory core-NMR derived T2cutoff. Although using a zero-gradient, laboratory core-NMR derived T2cutoff to "calibrate" NMR logs acquired in a gradient field is a common practice, the discrepancy cannot be ignored for NMR logs acquired with a large G·TE product. With the new method, this discrepancy is minimized. Field examples are provided to show the benefit with the new method.
Liquid Inventory Management Issues in a Dual Large Diameter Long-Distance Subsea Wet Gas Pipeline System
Authors: Harun A. F. , Choate T. G. A. , Cochran S. W.
Published: December 2007

Liquid inventory management is an important subject in a subsea wet gas pipeline system mainly due to long distance (∼ 56 miles), large diameter (20+ inches), and three-phase fluid (gas, water/MEG, and condensate) effects. Using multiphase transient simulation, this paper addresses some issues related to liquid inventory management as a result of transient operations, such as restart and rampup (production increase). This study reveals that gas velocity and a knowledge of liquid holdup during steady state and transient operations at any time and place are key parameters in developing a field operation strategy. Managing pipeline liquid holdup at all times will ensure that liquid surge arriving onshore will be within the slug catcher liquid handling capacity, while the transient operations can be reasonably managed.
Natural Polymer-Based Compositions Designed for Use in Conformance Gel Systems
Authors: Reddy B. R. , Eoff Larry , Dalrymple E. Dwyann , Brown David
Published: December 2007

This paper describes a crosslinking material derived from natural sources. This material can be used with a variety of polymers over a broad temperature range to produce gels for conformance applications.

Delayed cross-linked polymer systems have been used for many years in conformance applications. For the past decade, the most widely used system has been based on chromium (3+) cross-linked polyacrylamide. Organic crosslinkers, such as phenol/formaldehyde and polyethyleneimine have also been used with a variety of polymers. However, these systems are being scrutinized by regulatory agencies and have now been scheduled for phase-out in some countries. Because of these issues, a single, environmentally friendly crosslinker that could be used with a variety of polymers over a broad temperature range was selected for study.

This paper details the laboratory development of an environmentally friendly, natural polyamine crosslinker system. This crosslinker can be used with a variety of polymers, such as polyacrylamide, AMPS/acrylamide, or alkylacrylate polymers. Gels ranging from stiff and "ringing" type to "lipping" gels have been obtained. Recent efforts have targeted designing chitosan-based gel compositions. These efforts included not only using chitosan as the base polymer in combination with a synthetic polymeric cross-linker, but also developing gels derived completely from natural polymers. Results from these studies will be presented.