bluuebunny/crossref_metadata_2025 huggingface dataset:
Evaluation of Technologies to Treat Oil Field Produced Water to Drinking Water or Reuse Quality
Authors: Doran Glenn F. , Carini Frank H. , Fruth Darrell A. , Drago Joseph A. , Leong Lawrence Y. C.
Published: December 2007

Treatment technologies for reclaiming oil field produced water for beneficial reuse were evaluated, including thermal and membrane processes for salinity removal. Warm precipitative softening and high-pH reverse osmosis were selected for pilot testing based on a literature review of treatment technologies and results from bench-scale softening tests that indicated hardness, boron and silica removal could be simultaneously optimized.
EOS Simulation and GRNN Modeling of the Behavior of Retrograde-Gas Condensate Reservoirs
Authors: Elsharkawy Adel M. , Foda Salah G.
Published: December 2007

Currently, two approaches are being used to predict the changes in retrograde gas condensate composition and estimate the pressure depletion behavior of gas condensate reservoirs. The first approach uses the equation of states whereas the second uses empirical correlations. Equations of states (EOS) are poor predictive tools for complex hydrocarbon systems. The EOS needs adjustment against phase behavior data of reservoir fluid of known composition. The empirical correlation does not involve numerous numerical computations but their accuracy is limited.

This study presents two general regression neural network (GRNN) models. The first model, GRNNM1 is developed to predict dew point pressure and gas compressibility at dew point using initial composition of numerous samples while the second model, GRNNM2, is developed to predict the changes in well stream effluent composition at any stages of pressure depletion. GRNNM2 can also be used to determine the initial reservoir fluid composition using dew point pressure, gas compressibility at dew point and reservoir temperature. These models are based on analysis of 142 sample of laboratory studies of constant volume depletion (CVD) for gas condensate systems forming a total of 1082 depletion stages. The data base represents a wide range of gas condensate systems obtained worldwide.

The performance of the GRNN models has been compared to simulation results of the equation of state. The study shows that the proposed general regression neural network models are accurate, valid and reliable. These models can be used to forecast CVD data needed for many reservoir engineering calculations in case laboratory data is unavailable. The GRNN models save computer time involved in EOS calculations. The study also shows that once these models are properly trained they can be used to cut expenses of frequent sampling and laborious experimental CVD tests required for gas condensate reservoirs.
Application of Material Balance to Determine Ultimate Recovery of a San Juan Fruitland Coal Well
Authors: Zahner Bob
Published: December 2007

Volumetric methods to determine original-gas-in-place (OGIP) of coal bed methane reservoirs (CBM) are well established and documented. These methods differ from those used for conventional reservoirs in that they incorporate initial adsorbed gas content and/or methane isotherms to account for the fact that gas is adsorbed on the coal surface.

In practice, there are a number of factors which combine to create a great deal of uncertainty in volumetric calculations. Specifically, they are:Measurement of initial gas content is subject to several errors and frequently shows a wide variation within a given well. In many cases the only source of initial gas content measurement is from drill cuttings, which are known to give inaccurate results.Gas content may be derived from methane isotherms, but they require core and are typically available for only a limited number of intervals in a limited number of wells. There is often a wide variation in the character of these isotherms.Net pay is highly dependent on coal density. While density can be measured with logs, there is disagreement within the industry on what density cutoff should be used to determine net pay.In San Juan Fruitland Coal, CO2 content is often a high fraction of total adsorbed gas's and much greater than the produced CO2 fraction. Methane isotherms can be adjusted to account for CO2, but a pure CO2 isotherm is required, something which is difficult and expensive to obtain.

A material balance procedure proposed by G.R. King for coal seam reservoirs can be used to get independent OGIP estimates and can be programmed using a Lotus spreadsheet. If abandonment pressure is known, it provides a practical means for determining estimated ultimate recovery (EUR). Moreover, sensitivities can quickly be run to find the critical variables. An example of this process is presented for a well producing from the San Juan Fruitland Coal, including analyses of pressure transient tests to determine reservoir pressure. A cumulative frequency distribution of methane isotherms from San Juan Fruitland Coal is also presented. The results are compared to a history match with an Eclipse reservoir simulator.

Calculation of Original Gas in Place

The volumetric calculation of original gas-in-place (OGIP) for CBM wells is the sum of free gas in the fracture system and adsorbed gas on the coal surface. If initial water saturation is 100%, the volumetric calculation reduces to the following form:

where

OGIP = Original gas-in-place, Mcf

A = Drainage area, acres

h = Coal thickness, feet

Cgi = Initial sorbed gas concentration, scf/ton

d = Pure coal density, g/cm3

fa = Average weight fraction of ash

fm = Average weight fraction of moisture

Currently there are no methods to measure gas content in-situ and it must be inferred from indirect measurements taken from core or drill cuttings.

P. 147^
Three-Phase Relative Permeability in Heterogeneous Formations
Authors: Paterson Lincoln , Lee Ji-Youn , Pinczewski W. Val
Published: December 2007

A percolation model is used to investigate three-phase relative permeability for displacements in porous media with spatial correlations. On a ternary plot, the region where the three fluids have non-zero relative permeabilities is notably larger for spatially correlated properties than for uncorrelated properties. When stratified bedding is introduced, the three-phase region increases when flow is parallel to the bedding, and decreases for flow perpendicular to the bedding. Relative permeabilities increase in a similar manner. These results show that spatial correlations have a significant effect on three-phase relative permeabilities and residual saturations.
Experimental Determination of the Mobility of Hydrocarbon Liquids during Gas Condensate Reservoir Depletion:Three Actual Cases.
Authors: Morel D. C. , Nectoux A. , Danquigny J.
Published: December 2007

The experimental results of three long core, low rate, reservoir condition gas condensate depletion tests are presented in this paper. The three cases exhibited very different PVT and rock properties. Early production of the condensed phase was observed, with CCS in the range of 0 to 6 %. Condensed phase recoveries varied from a few percent to 25% during these experiments.

The three tests were simulated with a compositional reservoir simulation model. Relative permeability needed to be varied with interfacial tension in order to represent the early mobility of the deposited condensed phase. The interfacial tension threshold below which miscible relative permeability begin to change was in the range of 0.5 to l dyne/cm.

The calculation of the inverse of the Bond number, involving rock and fluid properties, was a valuable preliminary tool to evaluate the possible mobility of the condensed phase, when maximum liquid deposit is lower than the black oil residual oil saturation.
Application of Neural Network Parameter Prediction in Reservoir Characterization and Simulation - A Case History: The Rabbit Hills Field
Authors: Ahmed T. , Link C. A. , Porter K. W. , Wideman C. J. , Himmer P. , Braun J.
Published: December 2007

Recent developments in artificial neural networks now make it possible to predict important reservoir parameters from combinations of well log, geologic, and surface seismic data. Our neural network predictions of porosity and permeability make use of high resolution 3-D seismic data and well logs to extrapolate these reservoir properties away from the borehole. These predictions can then be used for further geologic analysis, seismic interpretation, 3-D computer visualization, or input to reservoir simulators.

This methodology of integration of data types of different scales combined with prediction of reservoir parameters provides valuable feedback into the reservoir modeling process. This in turn enhances the capability of the reservoir team to model accurately subsurface detail and those features that are likely to control and influence the displacement processes associated with hydrocarbon production.

The NE Rabbit Hills Field, north-central Montana, USA, is used to demonstrate the use of this integrated reservoir modeling approach. Results of history matching using the neural network derived rock parameters are also presented.
Kick Detection in Floating Drilling Rigs
Authors: Doria M.T. , Morooka C.K.
Published: December 2007

Early detection of fluid influx from the formation into the wellbore during a drilling operation, generally known as a kick, is a major concerning for the safety of crew and rig equipment and, for the well itself. In the past, many well kicks have been observed at its very beginning by delta flow parameter which is simply the returned mud flow rate minus the circulating injected mud flow rate. Accurate flow measurements in this case are of great importance for the kick detection systems. When drilling from a floating rig, heave motion causes large instantaneous fluctuation in flow out from the well. It affects the delta flow measurement ant it is undesirable specially in deep water when kick detection is crucial. In the present work, many methods have been investigated as an attempt to overcome that problem. And, a new approach to obtain better delta flow indication is presented. Data has been recorded from a drillship in a real drilling operation. Discussions are carried out comparing the return flow rate of drilling mud onboard a floating drilling vessel and that obtained following the procedure here presented. Finally, a comprehensive state of the art is detailed and simulations of drilling operations illustrate an application with good results for identifying any delta flow change.

Introduction

The problems observed in the influx from formation in floating drilling units has be motivated a great effort from researchers in order to obtain more precisely the net flow rate between mud flow rate injected and returned from the well. Moreover, variations of mud tank level should be detected accurately with minimum effects of the floating rig motions. Particularly drilling vessel vertical heave motion causes undesirable fluctuations in the returned mud flow rate. The quick detection of an influx from the formation into the well is a one of the key point in the crew safety.

In the present paper, a method to identify the mud flow rate fluctuations induced by the drilling vessel vertical (heave) motion is presented. The main purpose is to detect the difference between the returned mud flow rate from measurements of a mud-logging unit onboard and estimated mud flow rate with fluctuations due to heave motion. In this manner, it is possible to have that differential on mud flow rate more clear and reliable in order to identify early gain or loss of mud flow rate from or into the formation. Any deviation observed on above mentioned differential which exceeds a fixed safety range is considered an abnormality of the well and stand by procedure for rig and crew safety must be taken. As an example, a simulation and a measurement of returned mud flow in a drilling operation are compared. Results showing simulated situations of loss and gain of mud in a drilling operation are presented.
Evaluation of Drill Bit Performance Taking into Account the in Situ State of Stress
Authors: de Castro F. J. N. , da Fontoura S. A. B. , de Albuquerque L. C. , Frydman M. , Dumans C. F. F.
Published: December 2007

The present paper describes a correlation between the bit performance and the state of stress acting upon the rock formation located immediately beneath the bottom of the wellbore. Bit performance data from 6 wells drilled offshore Brazil have been collected and analyzed. In order to reduce the empiricism associated with this type of data analysis, a study is being put forward that considers the geomechanical log along the drilled wellbore. The geomechanical log of a given rock formation is composed of its mechanical properties (Young’s modulus, Poisson’s Ratio, unconfined compressive strength, internal friction angle, etc.) as well as formation fluid pressure and in situ total stresses. The paper shows how to use these data to evaluate the stresses at the bottom of the wellbore through a 3D finite element program. Through these stresses it is possible to define an index of plastification ahead of the drill bit, and its performance is rated taking this index into account.

Some of the wells that are being analyzed were drilled in deep water locations, and the study shows a great potential for better understanding the reasons for good and bad performances regarding to the penetration rate of the drill bit in a rational manner. Based upon the analysis, a new study for drill bit evaluation will be put forward with the potential for great savings.
Viscosity Prediction of Natural Gases
Authors: Erdogmus M. , Adewumi M. A. , Ibraheem S. O.
Published: December 2007

Accurate prediction of thermal and transport properties of natural gases is very important in the design and operation of pipelines. Viscosity is one such property. This work presents an assessment of several theoretically based viscosity prediction methods. In this study seven natural gas mixtures are used. Comparison with experimental data shows the effectiveness of each model.
Progressive Technology Increases Flow Capacity in Horizontal Wells
Authors: Beall Brian B. , Tjon-Joe-Pin Robert , Brannon Harold D.
Published: December 2007

Many horizontal wells are drilled using the clean "drill-in fluids" introduced in recent years. The drill-in fluids are typically comprised of either starch or cellulose polymers, xanthan polymer, and sized carbonate or salt particulates. They were introduced to minimize the mud damage to the wellbore relative to that typically observed with conventional drilling muds. However, testing and experience have shown that insufficient degradation of the filter cakes resulting from even these "clean" drill-in fluids can significantly impede capacity at the wellbore wall. This reduced flow capacity can result in reduced well productivity or injectivity. Consequently, wellbore acid or oxidizer treatments are typically applied in attempts to remove or "bypass" the filter cake. These treatments are often only marginally successful, particularly when applied in extended length intervals. Formation damage, as well as filter-cake impairment, must be eliminated to realize the full potential of horizontal completions.

Previous laboratory studies have demonstrated that drill-in fluid filter cake can be effectively removed through the application of a newly developed technique incorporating an enzyme-based polymer degradation system.1 This treatment can be designed to degrade xanthan-based, starch-based or cellulose-based drill-in fluid. Following degradation of the specific polymer, the weighting and/or fluid loss control material is easily removed using smaller, less costly acid treatments.

Case histories of wells treated with the new enzyme technology compared to direct offsets treated with conventional acid or oxidative breaker treatments will be presented. Field experience has shown that through utilization of this new technology, smaller, less costly treatments can be used to treat openhole intervals to zero-skin potential with dramatically improved treatment efficiency. Production results have indicated that three-fold increases are possible when applying a two-stage enzyme/acid treatment to acid or oxidative treatments alone. Post-treatment production logs have indicated not only increased flow, but also flow throughout the entire openhole interval.
A New Approach for the Prediction of Rate of Penetration (ROP) Values
Authors: Bilgesu H. I. , Tetrick L. T. , Altmis U. , Mohaghegh S. , Ameri S.
Published: December 2007

Today applications of drilling require proper identification of operations where a cost reduction is possible. Many indicators are present when one tries to optimize the drilling operations such as casing size and mud properties. On the other hand the selection of the optimum bit requires information from a variety of sources. The parameters affecting the bit performance are complex and their relationship is not easily recognized. The general trend is to evaluate the performance of the bit from an offset well.

A new methodology was developed to model the rate of penetration and bit wear under various formation types and operating parameters. This method introduces a new approach with improved bit wear prediction. A simulator was used to generate drilling data to eliminate errors coherent to field measurements. The data generated was used to establish the relationship between the complex patterns such as weight on bit, rotary speed, pump rates, formation hardness, and bit type.

The method was tested using data from runs conducted with a rig floor simulator. The validity of the proposed method was also demonstrated with data from an existing field.
Riser Recoil During Unscheduled Lower Marine Riser Package Disconnects
Authors: Puccio William F. , Nuttall Reid V.
Published: December 2007

In the event of a deep water emergency disconnection, the sudden release of the Lower Marine Riser Package (LMRP) connector can cause the riser string to reach destructive velocities and displacements. Impact between the outer barrel of the telescoping joint and the diverter housing must be avoided.

Likewise, the LMRP assembly must lift a sufficient distance from the BOP stack to avoid impact due to oscillatory displacements caused by rig motion.

The objectives that must be met by any riser recoil system are to reduce the risk of damage to the LMRP, BOP stack, riser string, and substructure (with associated equipment), so that when the conditions that forced the emergency disconnect sequence no longer exist, operations may resume without delay.

This paper illustrates some of the significant variables affecting the velocity and displacement of the riser string and LMRP during an emergency disconnect sequence. The methods of controlling the emergency-disconnection process are reviewed.

Correct modeling of physical forces at work can assist in applying control mechanisms to increase the envelope of safe operation of a tensioner system equipped with a riser recoil system (Fig. 1).

A riser recoil test was conducted on an deepwater offshore drilling ship to test the effectiveness of the riser recoil control equipment, and to verify the model.

P. 33
Innovative Cutting Structure Improves Stability and Penetration Rate of PDC Bits Without Sacrificing Durability
Authors: Mensa-Wilmot Graham , Krepp Tony
Published: December 2007

The industry's improved understanding on subjects such as vibrations and formation characterization have contributed to the current growth in Polycrystalline Diamond Compact (PDC) bit use. Although these bits are drilling faster and longer, improvements are needed to elevate their performance and extend their applications into harder formation drilling.

The continuously changing needs of operators, with regards to their drilling objectives and expectations have established the need for a new generation PDC bit. The new bit, while required to redefine the known relationships between stability, ROP, and, durability, must handle harder formations much more effectively.

A newly developed cutting structure (cutter layout) is enhancing the performance of PDC bits. The layout employs different sized PDC cutting elements in a unique arrangement, which improves stability and ROP, without compromising durability.

This paper will redefine the relationships between ROP stability and durability. It will establish the functionality of the new cutting structure (NCS) and show how this unique layout is enhancing PDC bit performance. Analytical, laboratory and field data will show the effectiveness of NCS, and the positive effect it is having on drilling efficiency and operational costs.

P. 167
Purpose-Built Drillpipe for Extended Reach Drilling
Authors: Payne M.L. , Bailey E.I.
Published: December 2007

Introduction

Substantial ERD projects have used and continue to use either or both 6-5/8" and 5–1/2" drillpipe (DP). These are standard sizes and are available through drilling contractors and rental companies. In substantial ERD wells, 5–1/2" DP still introduces hydraulic limitations in lone 12–1/4"sections and should be improved upon. The 6–5/8" DP is a good choice to reduce hydraulic pressure losses at the elevated flow rates required for ERD hole cleaning. However for nearly all ERD wells, 6-5/8" DP represents an "overdesign" from the viewpoint of drilling loads. Also, 6–5/8" DP inefficient from a space standpoint and can limit setback capacity. Finally 6–5/8" DP requires rig modifications for implementation and cannot be used inside 9-5/8" casing or 8–1/2" open-hole. This necessitates a major DP change-out at that phase of the well. The shortcomings of 5–1/2" and 6–5/8" ERD drillpipe strategies formed the basis for ARCO's development of purpose-built ERD drillpipe in an intermediate size between 5–1/2" and 6-5/8.

P. 221
An Ergonomic, Process Oriented Approach to Driller's Consoles
Authors: Harbour W. Dave , Kracik J. , Ford David
Published: December 2007

Technological advances in computer hardware, software and networks are being applied in new and productive ways every day. This paper describes how these advances can be applied to the drilling industry to create the next generation driller's console. By applying the techniques used when these advances were applied to industries such as commercial aircraft design and automated process control, a system is developed that allows the Driller, Assistant Driller and Electronic Technicians to monitor, control and maintain all of the elements of advanced, automated drilling machinery. This system presents only the data relevant to the current drilling process, while still providing access to any and all of the data at any time, thereby reducing information overload and creating a safer, less stressful, and more productive working environment.

Conventional driller's consoles present all of the data and control mechanisms for every element of drilling machinery to the Driller and Assistant Driller at all times. Typically this data, in the form of switches, knobs, dials, meters, lights, indicators and joysticks, is integrated into the console with little regard to ergonomics and the prevention of information overload. The next generation system uses color LCD touchscreen workstations for the Driller and Assistant Driller that are designed to display the appropriate data and control mechanisms relevant to the current drilling process while always displaying alarm and interlock data in a clear and informative manner. The layout of the data for each drilling process, as well as the transitions between the processes, are designed to prevent information overload and minimize the effort required for the Driller or Assistant Driller to perform their tasks and access data. The result is a smaller, lighter, more ergonomically designed driller's console that focuses on functionality relevant to the processes of drilling as opposed to focusing on simply controlling the tools required to drill.

P. 327
The Integrated Solution: New System Improves Efficiency of Drilling Planning and Monitoring
Authors: McCann D.P. , Ritchie G.M. , Ward V.L.
Published: December 2007

As operators strive to maximize efficiency throughout the exploration and production process, changes have occurred in operation organization and responsibilities. Operators and service companies are working on multi-disciplined or integrated project management teams. In addition, complex wells in remote or inaccessible locations are becoming more common place, for example, remotely GeoSteered horizontal wells. In such situations, it is difficult or impractical to have all the expertise at the wellsite throughout the drilling operation.

To maximize the benefits of this new way of doing business and from advancements in drilling technology, new tools which take advantage of recent developments in Information Technology are required. Integration of information on a single system allows Drilling Engineers, Geologists, Petrophysics and others to share the same database of information while working together on a given project. Modern communications systems are used to send data from the wellsite to the office, which can now be anywhere in the world, in a timely manner. By doing so, real-time data can be used to update and refine drilling and geological models for improved well placement and re-planning as necessary.

P. 351
Geomechanical Analysis for Deep-Water Drilling
Authors: Aadnoy Bernt S.
Published: December 2007

In deep water the fracture resistance of the borehole is low. This result in low mud weight, which in turn bring up problems like hole collapse, hole cleaning and stuck pipe. Circulation losses and underground waterflows are other associated phenomena.

In this paper a model for the fracture resistance of the borehole is derived. Based on a review of fracturing mechanics and on results from laboratory investigations, one concludes that soft soil near seabed behaves in a similar manner as deeper harder rocks. The fracturing process is basically stress-dominated. Leak-off and lost circulation data are collected world wide and used in developing a field model. The water depths varies from 135 m to 2071 m.

By using the basic fracture model, and also by normalizing the data for various water depths, it is shown that all field data collected behaves similarly regardless of location. One conclusion is that the frac pressure is governed by the total overburden weight, which consist of water to seabed and rocks down to the bottom of the well. A new method to normalize leak-off data is also presented. Wells from varying water depths can be compared, and used to develop prognoses at other water depths.

A review of the mechanics behind penetrating/non-penetrating borehole conditions shows that this causes large variation in the fracture initiation pressure. The difference in behavior between water- and oil-based drilling fluids is explained in terms of wettability and capillary effects. A field case presents two deep-water wells.

P. 441
New Treatment for Removal of Mud Polymer Damage in Multi-Lateral Wells Drilled Using Starch Based Fluids
Authors: O'Driscoll K.P. , Amin N.M. , Tantawi I.Y.
Published: December 2007

Significant improvement in production from horizontal, multilateral wells, has been realized through the application of Specific Enzyme Breaker (SEB) technology, for the removal of natural starch polymers used in drilling operations. This new treatment allows the placement of a fluid to remove polymeric mud damage at the cessation of drilling operations for each multi-lateral section, which could not otherwise be re-entered for clean-up and effective stimulation during completion of the well.

This paper includes a study of multi-lateral wells treated with Starch Specific Enzyme Breakers and provides a comparison with offset wells in the same field which have been treated conventionally with acids. The field data presented shows Starch Specific Enzyme Breakers to be effective in degrading filter cake laid down by starch based muds and in removing polymer filtrate damage. Results also show that, compared to wells treated with acid alone, the effects of soaking with a Specific Enzyme Breaker followed by a small acid treatment, will provide significant improvements in overall stimulation performance.

This new treatment provides an effective means of removing mud polymer damage from horizontal and multilateral open hole completions, that would otherwise be left in place by conventional stimulation treatments. The removal of this polymeric damage allows acid treatments to be optimized for the stimulation of the reservoir rather than for removal or by-passing of mud damage.

P. 753
Drilling Optimization and Use of Titanium Motor Results in 40% Reduction in Short Radius Drilling Time
Authors: French M.R. , Siagian Mangojak , Sutcliffe B.C. , Jones Jerry
Published: December 2007

This paper presents a case history of 12 re-entry short radius horizontal wells drilled in the Minas Field of Central Sumatra, Indonesia. These wells were drilled in two packages of six wells each. The first package was drilled using an articulated motor system. With preliminary well preparation conducted by a well service rig, well designed milling/drill-in fluids, and consistent sidetrack plug procedures, the first package was drilled under budget. Improvements to both the milling procedure and the directional program resulted in a 40% reduction in drilling time for the second package. The directional program for the second package also utilized a new short radius drilling system centered around a 4 %" titanium steerable motor. This project was the first time the titanium motor had been used in the field.

P.945
A Comprehensive Model for Predicting Corrosion Rates in Gas Wells Containing CO2
Authors: Farshad F. , Garber J.D. , Polaki B.
Published: December 2007

F. Farshad, J.D. Garber, and V. Polaki, Corrosion Research Center, University of Southwestem Louisiana

A windows based computer model has been developed with the capability for providing a physical description for the 5 different flow regime that can occur in gas wells. This description has proven to be useful in the prediction of the corrosion rates of the wells. The information can be helpful to design and production engineers.

P. 299
Economic Evaluation of the Use of Well Logs for Diagnosing Conformance Problems
Authors: Frisch Gary , Graham Larry , Wyatt Dennis
Published: December 2007

Unwanted water production may adversely affect well economics because of water-disposal costs, environmental issues, and reduced hydrocarbon production. This paper presents examples of how openhole and cased-hole logs can help determine the type and location of water entry, and indicate appropriate conformance treatments. Selected logs run following the treatments are used to evaluate the treatments. The cost of running the logs and applying the indicated conformance treatments is compared with the cost of water disposal and declining petroleum production.

Specific examples show that casing leaks, cement channels, coning, and watered-out reservoirs may all be easily identified and located through the use of openhole, production, pulsed neutron, casing inspection, and cement evaluation logs. Not all of these logs need be run in every well; thus, in each well, existing information was thoroughly studied to determine the most cost-effective diagnostic logging program.

The diagnostic information provided by the logs was useful in selecting appropriate conformance treatments. Many of the same logs used in diagnosing the water-production problems were found to be valuable in evaluating the effectiveness of the performed treatment. In some cases, follow-up treatments were suggested by the evaluation of the initial treatment and were the difference between successful rejuvenation of hydrocarbon production and continued declining well performance.

The costs of the logs used for conformance diagnosis and treatment evaluation were compared to the possible long-term costs of water disposal, environmental considerations, and reduced production from the well and were found to be relatively inexpensive.
Application of Conventional Well Logs to Characterize Naturally Fractured Reservoirs with their Hydraulic (Flow) Units; A Novel Approach
Authors: Elkewidy Tarek Ibrahim , Tiab Djebbar
Published: December 2007

This study introduces a new practical and cost-effective technique to in-situ describes the most important petrophysical properties of naturally fractured reservoirs. Cores from naturally fractured formations may not berepresentative and thus the analysis are not reliable. Well logging interpretation of porosity and resistivity can provide the required in-situmeasurements.

Here, formation total porosity, which may be estimated from conventional wireline logs, and cementation exponent, which can be determined from crossplotting log porosity versus log resistivity are the only two parameters required to uniquely derive resistivity factor, tortuosity, partitioning coefficient, fracture intensity index, matrix porosity, fracture porosity, and fracure storativity ratio for naturally fractured formations at reservoir conditions. Furthermore, these well log derived parameters are utilized along with correlated core data to express Reservoir Quality Index (RQI) in terms of partitioning coefficient and fracture intensity index. This RQI may be, then, used to characterize the different hydraulic (flow) units of naturally fractured reservoirs.

The product of this novel approach is an easy, flexible, and cost effective method that is readily adaptable to different naturally fractured formations including clastics, carbonates, and basement. This study will present the theory, application example, and practical charts for estimating the various rock properties. Application of this technique may ultimately result in opening new potentials, particularly in carbonates, redrilling or reentering hydrocarbon bearing intervals that were bypassed.

P. 417
Pressure Packing with Concentrated Gravel Slurry
Authors: Sparlin Derry , Copeland Travis
Published: December 2007

This paper was prepared for presentation at the 47th Annual Fall Meeting of the Society of Petroleum Engineers held in San Antonio, Tex., Oct. 8–11, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by who the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

An improved method of gravel packing has been used in more than fifty wells in the Gulf Coast area of Texas. It has been proven both economically and mechanically successful for controlling sand at increased oil production rates. The process uses a slurry with extremely high concentrations of gravel in a viscous oil with a "tackifying" agent. The slurry is squeezed into the problem zone until a sandout is obtained. A screen liner is then washed in the hole to keep the gravel in place.

Field results and experiences with this technique are discussed in the paper. Success of the process has resulted from packing large volumes of gravel around the wellbores, which allows good drainage and sand control concurrently.

Background

Sand control has been a persistent problem in the petroleum industry for many problem in the petroleum industry for many years. Numerous techniques have been tried with varying degrees of success, and gravel packing has been one of the most useful ways packing has been one of the most useful ways to solve sand problems. Although a large amount of gravel packing technology has developed, many problems still exist.

Through proper use of existing technology, we can control virtually any formation sand with gravel. The major problem has been how to control these sands without restricting fluid production.

Most operators are now more critically than ever reviewing their wells with an eye on how to increase production. One potentially profitable way is to use improved potentially profitable way is to use improved gravel packing techniques that will provide improved fluid production as well as sand control.

Sand control processes can be only as good as the completion practices used in the well. Often a gravel pack is blamed for many problems which result from a combination of problems which result from a combination of formation characteristics and poor completion practices. practices.
Core Analysis Techniques and Applications
Authors: Keelan Dare K.
Published: December 2007

Considerations are presented for planning a coring program early in the field development stage. Objectives, currently used coring devices, coring fluids and their suitability are briefly discussed. Precautions in core handling, preservation and selection are reviewed. Types of core analysis are presented, and pertinent observations concerning measurement of porosity, permeability and residual fluid saturations are made.

Applications of conventional and special core analysis are briefly discussed.

INTRODUCTION

Data, its interpretation and its use, forms the basis of any engineering study made to determine in-place hydrocarbon reserves and their most efficient recovery. Conventional core analysis makes an important contribution to the most basic data required - What hydrocarbons, if any, are present, and how much storage capacity (porosity) is available. Lithology of the rock is defined, and deliverability of the formation may be estimated from measured permeability. Examination of residual fluid contents in the core samples allows interpretation of probable production. Study of these basic parameters, coupled with supplementary test data developed on core samples, yields insight into reservoir performance, unusual response to well treatment, and down-hole log interpretation and understanding. Data typically reported and its use are presented in Table 1.

Extension of conventional core analysis that furnishes porosity, permeability and saturations to yield more sophisticated data has been accomplished through tests christened 'Special Core Analysis'. These measurements utilize specialized equipment. In most instances, tests of this nature are performed in a central laboratory where special equipment is permanently established, and trained operators familiar with each test are available. Table 2 lists commonly performed special tests.
How to Produce More Oil and More Profit with Polymer Treatments
Authors: Sloat Ben F. , Fitch Jon P. , Taylor John T.
Published: December 2007

This paper was prepared for the 43rd Annual California Regional Meeting of the Society of Petroleum Engineers of AIME to be held in Bakersfield, Calif., Nov. 8–10, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

The use of water soluble polyacrylamides to reduce water-oil ratios in producing polyacrylamides to reduce water-oil ratios in producing (21 wells has been widespread in the past three years. Field results have been difficult to correlate, however, data shows a 50 to 80 percent reduction of produced water is percent reduction of produced water is obtainable. In most cases, oil production has been either unaffected or increased.

Field results with anionic, reacted anionic, and strongly cationic copolymers of acrylamide show steady improvement in the process.

Data on field application with these new techniques in California, Kansas and Wyoming are presented.

Introduction

The economic life of most "oil" wells is really determined by how much water they produce. The lifting, treating and disposing produce. The lifting, treating and disposing of water is what costs the money and fixes productive life. productive life. Waterflooding economics are also very sensitive to water handling costs. Ten barrels of water have to be treated, pressured and injected to produce one barrel of oil on a "normal, flood, while many marginal projects approach 20:1. As producing depths projects approach 20:1. As producing depths increase, the water cost multiplier gets even bigger—the reason being that crude oil price are usually not related to depth, while water lifting costs are directly proportional.
Annular Flow Dynamics
Authors: Willis H. Craig , Tomm Wayne R. , Forbes Eugene E.
Published: December 2007

The new analysis technique of Annular Flow Dynamics is a simple, practical way to predict and control rheology and hydraulics in predict and control rheology and hydraulics in Drilling Fluid Systems. It is based on field experience in the sloughing shale areas of Canada and on a recently developed method of calculating Annular Pressure Losses with greater accuracy and more simplicity than previous methods. previous methods. Annular Flow Dynamics is primarily oriented towards improving drilling practices in sloughing shale situations. However, as holes become deeper, additional restrictions are imposed on casing programs and hole size. These make it even more important to be able to determine and possibly predict certain drilling fluid parameters for maximum performance. This paper shows how, by use of performance. This paper shows how, by use of a logarithmic plot of viscometer data, the following can be determined:Effective annular viscosities at any pump rate and for any flow properties.Flow type (laminar or turbulent).Accurate annular pressure losses.Approximate bit nozzle shear rates.Upper and lower limits on both flow properties and pump rates for optimum well bore stabilization and minimum E. C. D. (Equivalent Circulation Density).Approximate ascending velocity of cuttings.

In the past year, Annular Flow Dynamics has been used on a field basis in Canada with very positive results.

Introduction

Well bore instability occurs primarily when shales absorb water. Controlled activity oil minds are presently the only way to satisfy the shales affinity for water. The mechanism of sloughing shales due to actual change in the physical and chemical properties of the shale physical and chemical properties of the shale have been thoroughly researched and discussed by the industry. Less attention has been paid to the mechanical aspect of stabilizing shales by well planned and flexible rheological and hydraulics programs.
The Influence of Gas Saturation on Waterflood Performance - Variations Caused by Changes in Flooding Rate
Authors: Dandona Anil K. , Morse R.A.
Published: December 2007

The Influence of Gas Saturation on Waterflood Performance - Variations Caused by Performance - Variations Caused by Changes in Flooding Rate

It has been recognized that the presence of a gas saturation prior to waterflooding can have an important influence on oil recovery. The published results on the subject are derived from laboratory experiments on essentially one-dimensional horizontal systems flooded with low pressure differentials. In field applications, high pressure gradients could cause important effects not noted in the laboratory studies such as the disappearance of part or all of the gas by solution in the oil bank. Also, it has been realized that gravity forces make it impossible to initiate and maintain a uniform gas saturation from top to bottom of the production section.

By the use of numerical models a study has been made of the effects of flooding rate on performance of waterfloods in reservoirs having performance of waterfloods in reservoirs having gas saturation. Flooding rates over a very wide range have been simulated. At very high rates the gas is put into solution in the oil bank ahead of the water so no gas saturation effect is noted. The simulated performance at very low rates in the absence of gravity check very well with the published laboratory data. Introduction of gravity causes markedly different performance from that of the one-dimensional performance from that of the one-dimensional horizontal systems because of the nonuniform vertical distribution of initial gas saturation and gravity effects on the injected water distribution.

Introduction

At the present time, a large fraction of the oil originally in place is left unrecovered in oil reservoirs after depletion by the best methods available. The need for added recovery is of equal importance with the search for new oil-producing structures. Waterflooding is, and has been in the past, the most universally used method for increasing oil recovery beyond the levels provided by natural depletion. Improvements of waterflooding should lead to economic recovery of additional oil in substantial quantities. One of the methods that has been proposed for increasing recovery of oil by water proposed for increasing recovery of oil by water displacement involves creating a gas phase ahead of the waterflood front.

As early as 1922, Russell found experimentally that flooding of oil reservoirs by a mixture of water and gas yielded considerably more oil than water or gas drive alone. In the year 1932, producers in the Bradford field injected their surplus produced gas into oil reservoirs to conserve gas. The operators noted that the injection of gas prior to waterflooding resulted in improved oil recoveries.