bluuebunny/crossref_metadata_2025 huggingface dataset:
Through Flow Line Tools for Remote Downhole Well Operations
Authors: Seligman P.R. , Reeds C.B.
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.

During the period 1969–71 a number of Through Flow Line (TFL) tools were tested in two wells: one a 3500' deep non-producing well; the other a 9330' deep well on gas lift production.

This work was conducted in connection with the development of a new subsea well completion system.' Test results, however, demonstrated that TFL tools and techniques have great potential for application in wells on land as well as offshore.

Initial costs for equipping a well for TFL work are greater than for wire line operations. In many cases, however, operating costs will be significantly less. TFL tools are equally efficient in straight and highly deviated wells and are effective for a wide variety of downhole jobs including fishing problems. Numerous workover type jobs such as sand washing, perforating and cementing can be performed perforating and cementing can be performed without pulling tubing, and TFL procedures permit large differential procedures permit large differential forces to be applied downhole when necessary.

Many existing TFL tools are operational. In some cases, improvements in design or prerun inspection are warranted to improve reliability. Certain other tools are still in the development stage, and both shop and field tests are indicated to uncover design faults and to establish operating characteristics.

Introduction

In recent years, quite a bit of experimental and developmental work has been performed on oil well tools designed to be pumped hydraulically down a tubing string. Originally, anticipated application was for two types of wells:Offshore platform wells that were directionally drilled at such high angles that wire line tools simply would not fall to bottom satisfactorily.Ocean floor completions producing through submarine flow lines to platforms some distance away.
Sand Stabilization with Hydroxy Aluminum Solutions
Authors: Reed M.G. , Coppel Claude P.
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.

In many oil producing reservoirs, sand and other fine-grained rock materials migrate into wells. This influx may decrease oil production by plugging gravel packs, production by plugging gravel packs, eroding well equipment or completely sanding up wells. In many such problem formations, the principal problem formations, the principal natural cementing agents are clay minerals, which are relatively weak and may be further weakened by changes in formation fluid chemistry. When these clay minerals expand and disperse, the coarser silt and sand in the formation rock may also move in with flowing fluids and damage the well. This paper describes a procedure for treating such formations with hydroxy-aluminum to stabilize clay minerals and thereby prevent sand and silt production. production. Hydroxy-aluminum is a relatively inexpensive and commercially available chemical that very effectively inhibits clay damage in normally water sensitive formations. An aqueous solution of hydroxy-aluminum is injected and is desirably followed by an aqueous overflush and a short shut-in period. Hydroxy-aluminum cations adsorb very tightly on clay mineral surfaces and stabilize them by decreasing dispersive forces and eliminating structural expansion.

Laboratory flow studies show that after treatment many selected friable natural formation sands can withstand considerably higher flow rates without sand production. The effectiveness of the chemical treatment is related to the clay mineral content and cation exchange capacity of the rock. The process has been applied successfully in California and Gulf Coast fields.

Introduction

Movement of formation materials into wells is a serious problem in many oil-production areas around the world.
Information Services - An International Technology for Petroleum Engineers
Authors: Wexler P.L.
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 request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request 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 discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Good afternoon ladies and gentlemen. It is my pleasure to meet with you today and discuss Information Services, an International Technology for Petroleum Engineers.

My talk will cover three main aspects:

. An overview of Information Services and its technology.

A review of some current petrochemical applications which utilize the Network.

A projection of future Information Services trends.

Information Services can be viewed in three specific phases and time periods.

The first phase began in the mid-sixties and was commonly referred to as Time-Sharing. As you all know, this involved a fairly standard computer with some telecommunications capability and specialized interactive software.

During the next four to five years, this industry grew tremendously and systems and their capabilities progressed on a very fast scale. This type of service was primarily oriented toward engineering and primarily oriented toward engineering and scientific applications and Time-Sharing systems generally served a customer on a regional basis.

In the late sixties, a new phase of the industry was entered… Networking. This development was the merging of computers and telecommunications on a grand scale. Systems developed large networks providing common file access from many diverse locations. Applications began to become more business oriented… inventory management… order processing are a few prime examples. Service vendors today offer Networking capability on widely varying ranges….. from regional to national to international.

Let me now divert for a few minutes and discuss one specific network with which I am slightly familiar….. GE's International Information Services Network.

First, let me discuss the Network's Technology. This can be addressed in two respects - one from an overall system basis and the other with reference to hardware and software.
Numerical Simulation Of Compositional Phenomena In Petroleum Reservoirs
Authors: Nolen J.S.
Published: December 2007

Nolen, J.S., Member AIME INTERCOMP Resource Development and Engineering, Inc.

The only fundamental difference between compositional reservoir simulators and simulators of the black-oil type lies in their treatment of fluid properties and phase behavior. Since properties and phase behavior. Since compositional simulation, the only justification for a compositional study is the increased accuracy that can be obtained by a more realistic description of the fluid.

This paper focuses on the consistent and accurate treatment of fluid properties in describing a three dimensional properties in describing a three dimensional compositional simulator. It describes the methods used to calculate densities, viscosities, and equilibrium K-values, presenting comparisons between calculated values and experimental data.

Another subject of discussion in the paper is the problem of numerical dispersion. An example simulation illustrates the magnitude of the problem and demonstrates that the method-of-characteristics provides a practical means of eliminating numerical provides a practical means of eliminating numerical dispersion in multicomponent miscible displacement problems.

Introduction

Most numerical simulations of petroleum reservoirs are performed with petroleum reservoirs are performed with "black-oil" type simulators. The validity of these black-oil models rests on the assumption that the reservoir fluid consists of only two components, denoted oil and gas.
Numerical Simulation of Naturally Fractured Reservoirs
Authors: Asfari Ardeshir , Witherspoon Paul A.
Published: December 2007

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.

The finite element method has been used to investigate mathematical models of idealized systems of vertical fractures in an effort to extend our understanding of the behavior of naturally fractured reservoirs. Regular systems of fractures have been chosen in such a way that the length of the fracture can be characterized in terms of the dimensions of a representative elemental area associated with that fracture. By changing the permeability of the fracture relate to the matrix, steady state solutions demonstrate how the effective permeability of the fractured system depends on both fracture conductivity and dimensionless parameters representing fracture density. Horizontal shale lenses, scattered through a reservoir can be modelled in the same way using finite elements of very low conductivity. Comparison of our results with those from a recent analytic solution for fractured systems indicate excellent agreement.

Introduction

There are a significant number of petroleum reservoirs where discontinuities such as fractures or joints in the porous rock matrix are the main path transmitting fluids to the producing well. These naturally fractured systems producing well. These naturally fractured systems characteristically have a low matrix permeability and one or more well developed fracture systems.

The published reports on naturally fractured reservoirs show that vertical joint planes are a dominant feature. Daniel studied three fractured limestone reservoirs of the Middle East. He reports that in all three cases, vertical and near vertical fractures were widespread, and for the most part, there was a complete absence of low dipping fracture planes. Wilkinson's work on the Spraberry reservoir in Texas revealed that vertical joints are the largest, both in extent and width, and by far the most abundant type of fractures. This dominance of vertical fractures has also been reported by other authors.

Investigations of non-reservoir rocks have also revealed the same conclusions. Kelly and Clinton, Parker, and Hodgson have made extensive regional investigations on fractures and joints. They report that vertical joints constitute the most dominant mode of fracture systems. Furthermore, they report that in the areas studied, the fractures are not randomly oriented but are systematically arranged in sets. The same finding has also recently been reported by Louis and Perrot and Mahtab et al.

In all of these investigations more than one fracture system may be found. The area of an individual fracture plane may vary from a few square inches to several hundred square feet.
The Isochronal Testing of Oil Wells
Authors: Fetkovich M.J.
Published: December 2007

This paper presents the results and methods of analyzing isochronal and flow after flow multipoint back-pressure tests conducted on oil wells. Tests were conducted in reservoirs with permeabilities ranging from 6 MD to >1000 MD. Reservoirs in which oil well multipoint back-pressure tests were obtained ranged from highly undersaturated, to saturated at initial reservoir pressure, to a partially depleted field with a gas saturation existing above the critical. Each of these three reservoir fluid states can result in different interpretation methods. Back-pressure tests were run to pseudo-steady state in the field where the saturation was above the critical gas saturation.

In all cases, oil well back-pressure tests curves were found to follow the same general form as that used to express the rate-pressure relationship of a gas well:Equation

From some 40 oil well back-pressure tests examined, the exponent n was found to lie between 0.568 and 1.000, very near the limits commonly accepted for gas well back-pressure curves. Flow point alignment to establish an oil well back-pressure curve on the customary log qo vs. log Î"(p2) plot is considered to be as good as that obtained on gas well back-pressure tests.

This paper demonstrates that gas wells and oil wells behave very similarly and should be tested and analyzed using the same basic flow equations.

Introduction

Multipoint back-pressure testing of gas wells is an accepted procedure for establishing a gas well's performance curve. Flow after flow1 and isochronal2 testing are the two basic methods commonly used. In high permeability reservoirs, either method can be employed. In low permeability reservoirs, the Isochronal method of testing eliminates the transient effects that can severely distort the results obtained from a flow after flow test. Methods for analyzing and calculating gas well performance curves have been the subject of numerous investigations. The bulk of these investigations have examined non-Darcy flow behavior, the primary reason that multipoint tests are conducted.
Cementing Practices for Tubingless Completions
Authors: Clark Charles R. , Jenkins Robert C.
Published: December 2007

This paper was prepared for the 48th Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Las Vegas, Nev., Sept. 30-Oct. 3, 1973. 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 PETROLEUM ENGINEERS JOURNAL is usually granted upon request 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 discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

This paper describes field cementing practices for tubingless completions. practices for tubingless completions. Application of new cementing techniques has resulted in a significant increase in success frequency. Some of the techniques adopted were based on articles recently published in the literature while others published in the literature while others were developed through field experimentation. A before/after comparison of success frequency is made along with a detailed description of the changes in field practices. All of the wells analyzed have been drilled in the South Texas area.

Introduction

During 1970, 1971, and the first quarter of 1972, relatively poor cementing success was experienced in 2-7/8" tubingless wells drilled in the South Texas area. Table 1 reflects the primary cementing success ratios for this primary cementing success ratios for this period. Typically, these wells were drilled period. Typically, these wells were drilled to total depth of 7100' with a 10.5 ppg water base mud and were considered to be routine. However, a review of the expenditures for remedial squeezing to repair primary cementing (average crest per well of $1500) and the resultant deferred or lost production indicated a problem of major magnitude.

In light of the poor success ratios, it was decided to exert a maximum effort on primary cementing for tubingless wells to see if success frequency could be improved. Two company primary cementing studies were essentially completed in the first quarter of 1972. The recommendations concluded from these two studies plus field equipment and operational changes have lead to improved cementing success for tubingless completions. Table 2 reflects the cementing success for 12 months history since implementing the new procedures. Only one triple tubingless has been completed (a cementing success) since the change in procedures. Therefore, a before/after comparison has not been made for triple tubingless completions. This paper will give a brief description of the techniques used during 1970, 1971 and the first quarter of 1972, and a detailed discussion of the cementing procedures currently being used.
Comparison of Friction Factor Correlations for Gas-Liquid Flow in Horizontal Pipes
Authors: Hernandez Florencio , Brill James P.
Published: December 2007

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.

All published correlations for predicting flowing pressure losses account for irreversible energy losses due to wall shear stress through a Fanning or Moody type friction term. Evaluation of this term requires that one be able to predict the value of a friction factor. Use of predict the value of a friction factor. Use of the well known Moody diagram, or one of many empirical equations that describe specific parts of the Moody diagram, is the accepted way to determine friction factors for single-phase flow.

Most investigators have taken advantage of previous knowledge in single-phase fluid flow previous knowledge in single-phase fluid flow to predict flowing pressure losses when gas and liquid flow simultaneously in pipes. Thus, mechanical energy balance equations, which form the basis for single-phase flow equations, have been modified for two-phase flow through simple analogies. These analogies have resulted in wall stress terms that include any irreversible energy losses between phases and all of which are again expressed in terms of a Moody type friction term. Thus the problem becomes, in part, one of determining a two-phase or mixture part, one of determining a two-phase or mixture friction factor.

Correlations for predicting two-phase friction factors for horizontal pipe flow have been published by many authors. All published correlations are based on experimental data, and no previous attempts have been made to compare these correlations.

Published equations for predicting two-phase flowing pressure loss may be solved explicitly for a two-phase friction factor. However, the resulting equations are a function of liquid holdup. Thus, a valid comparison of friction factor correlations would rely on using data for which measured holdup data as opposed to predicted values were available. The only reliable liquid holdup data available for pipe sizes 1 in. and greater were published by Eaton, Andrews and Beggs.

The gas-water data of Eaton and Andrews for 2- and 4-in. pipe (266 tests) and the air-water data of Beggs for 1- and 1 1/2-in. pipe (58 tests) were used for this study. Using these measured holdup values, friction factors (called measured values) were calculated from the appropriate pressure loss or mechanical energy equations for pressure loss or mechanical energy equations for the correlations of Eaton et al., Beggs and Brill, Dukler (Case II), and Gushov et al.

These correlations were chosen since they are the ones that are used most frequently for predicting two-phase flowing pressure losses in predicting two-phase flowing pressure losses in horizontal pipes.
The Combustion Interchangeability Of Natural And Substitute Gases
Authors: Larson Dennis H.
Published: December 2007

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.

Over the past 40 years, several investigators have developed methods of calculating for combustion interchangeability of gases for appliance-type burners. However, when these methods are used to calculate interchangeability for more current types of gases such as substitute natural gases (SNG) or revaporize LNG, there is considerable disagreement. Currently, additional research work is being conducted to resolve these differences. Results to date show that the American Gas Association method or indexes are most suited to today's gases on U. S., appliances. In addition, we have fund that today's burner designs allow more flexibility in interchanging gases. Compositions of SNG, for example, which may not burn satisfactorily in a cast iron drilled-port burner, popular 40 years ago, will burn properly in the newer popular 40 years ago, will burn properly in the newer stamped-metal burner. Consequently, further work is being done to extend the A.G.A. indexes to reflect this added stability of newer burners.

Introduction

The U.S. gas industry is embarking on major programs to import liquified natural gas (LNG) and programs to import liquified natural gas (LNG) and to produce substitute natural gas (SNG) from solid and liquid feeds. The compositions of these gases are expected to vary considerably from the natural gas now being used in the U.S. It is, therefore, important to determine the combustion interchangeability of these new gases with conventional appliances now equipped for natural gas.

In the late 1940's and 1950's, several groups studied the problem of interchangeability as applied to natural gas. From data collected by the A.G.A. Laboratories, indexes were developed by A.G.A. and by Weaver of the National Bureau of Standards. Additional work including theoretical foundations was done by Grumer, Harris, and Rowe, at the U.S. Bureau of Mines. Another significant set of data and indexes were developed by Delbourg and Schneck in France.
Dynamic and Static Measurements on mm-size Shale Samples
Authors: Nes O.-M. , Sonstebo E.F. , Horsrud P. , Holt R.M.
Published: December 2007

A system for acoustic velocity and static Young's modulus measurements on small (mm-size) shale samples is presented. The equipment has been tested on both soft and hard shales, including cuttings. Even though more experimental testing, must be carried out to confirm and improve its performance, it is demonstrated that reliable measurements can actually be performed on the small samples. Moreover, the results appear consistent with results attained from larger plugs using more conventional test methods. This technology represents a relatively fast and inexpensive method of attaining dynamic and static data from sub-surface formations. Use of cuttings and small samples can greatly improve the data availability, particularly where proper cores are not available.

P. 23
Implementation of Cuttings Reinjection at the Ekofisk Field
Authors: Nagel N.B. , Strachan K.J.
Published: December 2007

In response to increasing concerns over the environmental effects of the disposal of drill cuttings to the sea, a number of North Sea operators have begun to dispose of cuttings through injection into underground strata. Phillips Petroleum, as part of the Eko II redevelopment program for the Ekofisk field, conducted an evaluation of cuttings disposal options prior to selecting cuttings reinjection for all cuttings disposal from the new 2/4X wellhead platform.

In support of the selection of the final alternative for reinjection of cuttings, reinjection of slurrified cuttings via a dedicated well into the mid-overburden overlying the northeastern flank of the reservoir, an extensive engineering study was performed. Within the study, a number of issues were evaluated and reviewed: the relevant experiences of other North Sea operators; the economic evalution of various mud systems and disposal alternatives; a complete review of the geologic structure of the overburden for determining the optimal location of reinjection; numerical simulations of fracture behavior and performance; well design considerations; final selection of the well location; contingency planning; and a subsidence risk assessment. The subsidence risk assessment, performed in cooperation with an outside consultant, evaluated the unique concerns of reinjection into the overburden overlying a compacting reservoir.

Cuttings reinjection was initiated late in 1996 and by early 1998 more than 700,000 barrels of slurry had been reinjected into a single completion interval. Difficulties with the well have been relative minor, though the well has plugged-up several times, and the reinjection operation is considered successful. Building upon these results, plans are now being implemented for cuttings reinjection via dedicated wells at the Eldfisk field, another compacting reservoir lying to the southeast of Ekofisk.

P. 95
An Experimental Analysis of Anelastic Strain Recovery of Synthetic Sandstone Subjected to Polyaxial Stress
Authors: Yassir N. , Wang D.-F. , Enever J.R. , Davies P.J.
Published: December 2007

This paper describes, for the first time, a unique investigation of ASR using synthetic sandstone samples formed under applied polyaxial stresses. The strain relaxation in all tests invariably gave a good indication of the principal stress orientations. Measured strain relaxation ratios were approximately equal to corresponding applied stress ratios up 1.5, suggesting that, with a knowledge of one of the principal stresses, in regions of low stress anisotropy, stress can be calculated directly from strain. At stress ratios of 2 and above, corresponding relaxation strain ratios were variable, time- dependent and generally higher than the stress ratios. This suggests that shear stresses associated with stress anisotropy result in material damage that is partly responsible for the measured relaxation strain.

Correction of strains for "Poisson" effects reduced data scatter at the higher stress anisotropies but gave a poor correlation between applied stress and a) strain magnitudes, b) calculated stress, for a measured Poisson ratio (v) of 0.3. Lower v values gave better data fit, but it is suggested that the use of a Poisson correction of (he measured strain. Using low values of v, is unrealistic. The strain relaxation mode was assessed using the Kelvin-Voight model. The strain relaxation curves are not perfectly linear in normalised strain/time space. The material behaviour cannot therefore be fully reproduced using this visco-elastic model. Anisotropic samples especially seem to deviate from a linear trend, again suggesting that stress anisotropy and related fabric damage have an effect on the ASR response.

P. 161
An Innovative Energy Approach to Analyze Wellbore Stability
Authors: Santos Helio , Roegiers Jean-Claude
Published: December 2007

Wellbore stability has been traditionally analyzed by comparing the stresses to the formation strength. In addition, most of the problems have occurred in the shales; hence, have been attributed to the chemical interaction between the drilling fluid and the rock. However, field evidences urge for (he development of an improved way to analyze the stability of oil wells, due to the increase in challenges resulting from considering more difficult reservoirs.

This paper presents an innovative way to analyze wellbore stability using energy concepts. The rock mechanics aspects are emphasized; laboratory experiments usually interpreted via a mechanistic way should actually be evaluated in a more comprehensive way with energy. By analyzing the failure process of rocks, wellbore instability is explained by (he creation of surface fractures, with subsequent mud penetration. The paper describes the most energetic phenomena during (he drilling of a well, with the corresponded effects on the stability.

P. 255
Shear Strength and Stiffness of Clay-Rich Sediments during Drilling Operations
Authors: Fam M.A. , Dusseault M.B.
Published: December 2007

During exposure to different fluids and temperature gradients, the shear strength and the stiffness of shales may change because of changes in their chemical and physical properties. Time-dependent borehole stability models should incorporate these changes in order to capture actual field conditions. In this study, analytical treatments are employed to predict changes in shear strength and stiffness of soft shales caused by concentration diffusion processes (hat may arise during drilling operations. Analysis is based on the double-layer theory and the modified effective stress concept. Artificial shale specimens with different smectite contents are prepared using a slurry-consolidation technique. Fluid exchange (higher tonic concentration) is imposed on the specimen before undrained triaxial and unconfined compression tests. Volumetric strains and pore pressures are recorded with time during pressure diffusion, concentration diffusion and shearing stages. Apparently, changes in the shear strength and stiffness depend on the initial condition of the system. Soft homogeneous sediments experience an increase in the strength and stiffness with the increase in pore fluid concentration. On the other hand, stiff cemented systems and clay mixtures may show the opposite trend due to the breakage of bonds and the generation of excess pore pressure.

P. 283
Effects Of Induced Pore Pressure On Stability Of Wellbores Drilled In Shales
Authors: Chen X. , Tan C. P. , Haberfield C. M.
Published: December 2007

Due to the low permeability of shales, excess pore pressures will be induced in the material in response to the volume change of the rock matrix during drilling. These excess pore pressures will reduce the effective confining pressure applied on the material which will lead to a less stable wellbore condition. However, the extent to which the induced pore pressure influences wellbore stability varies dramatically with the in-situ stress regime, wellbore trajectory, and the poroelastic and strength anisotropies of the shale.

This paper examines wellbore stability under different drainage conditions taking into account variations in the in-situ stress environment, wellbore trajectory and shale properties. Design charts derived from the analyses are then presented and their application discussed. Finally, the effects of induced pore pressure on wellbore stability are demonstrated through numerical modelling of borehole deformation of a thick-walled hollow cylinder shale sample under different drainage conditions. Comparison of numerical results with laboratory measurements shows good agreement.

The investigation provides further insight and understanding of the effects of induced pore pressure on stability of wellbores drilled in shales. The design charts enable assessment of the effects of in-situ stress regime, wellbore trajectory and poroelastic properties of the formation on wellbore stability to be readily made. In addition, recommendations for appropriate drainage conditions for use in wellbore stability analyses enable more accurate prediction of the safe mud weight window.
Borehole Stability in Shales: A Physico-Chemical Perspective
Authors: Fam M.A. , Dusseault M.B.
Published: December 2007

Stability problems encountered in shale formations significantly increase the cost of drilling operations. It is not possible to identify a single main factor in shale instability; failure mechanisms are only now beginning to be identified, and the dominant processes seem to vary for different conditions of stress, mineralogy, fabric, and geochemistry. This article reviews a number of physical and chemical concepts in borehole stability analysis and raises several issues related to the activity coefficient and cation exchange processes. It is shown that the degree of saturation and clay particle separation have significant impact on the activity coefficient of tested cores. A simple coupling model based on the modified effective stress principle shows that when a shale with low porosity and high specific surface (reactive shale) is subjected to an increase in pore fluid salt concentration, a pore pressure front may develop. This front may trigger changes in effective stress and shear strength around the borehole. This may be a major destabilizing mechanism in the more reactive shales (generally the smectitic shales).

P. 461
Is Capillary Suction a Viable Cohesive Mechanism in Chalk?
Authors: Lord Charles J. , Johlman Carolyn L. , Rhett Douglas W.
Published: December 2007

This paper is based on a series of residual water analyses performed on Ekofisk Field chalk samples. The main objective of this work was to critically evaluate the importance of capillary suction as a cohesive mechanism in chalk. .

Capillary suction models have been proposed in the literature to explain the structural weakening that occurs when water is injected into chalk reservoir rocks. These models theorize that mineral grains are held together by the surface tension of water menisci. Water saturations of 5 - 10 % are generally considered optimum for this mechanism. As additional water is injected into the rock, the menisci disappear and the rock loses cohesive strength. Proponents of these models claim that the superior strength of "dry" chalk is also due to capillary water which is so tightly bound that it survives normal laboratory drying procedures. Despite the popularity of this theory, no evidence has been published that verifies the presence of capillary menisci in dried samples.

We used a thermal desorption - mass spectrometry technique to quantify the amount of adsorbed water that remains fn dried reservoir rock samples. The results of these analyses on Ekofisk Field chalks demonstrate that the capillary suction cohesion model is not a valid mechanistic description of chalk behavior. Our data show that the residual water content of chalk is at least twenty times too low to support capillary water menisci. An alternative weakening mechanism, such as mineral dissolution at grain-to-grain contact points, needs to be considered. This type of critical testing is necessary in order to develop a realistic and accurate model of waterflood response in chalk reservoirs.
Induced Seismicity Analysis for Structure Identification and Stress Field Determination
Authors: Gaucher E. , Cornet F.H. , Bernard P.
Published: December 2007

In 1993, during the development of the European hot-dry-rock geothermal field at Soultz-sous-Forets (France), 44,000 m3 of water were injected to stimulate the natural fracture system of this granitic rock mass. Some 16,000 microseismic events were recorded by a network consisting of a hydrophone and three four-component seismic sensors cemented in the granite at the bottom of observation wells. Multiplets (close earthquakes with similar waveforms) are retrieved in order to find local structures and correlate them with major fractures observed in the well by acoustic imaging and flow logs. Among the eleven identified and relocated multiplets, eight of them deline a planar structure, which is presumed to be a fracture plane. Two of the multiplets lie on a linear structure and one of them is the intersection of two previous planar multiplets. This leads to a description of the fracture network within a few tens of meters around the borehole. In addition, in order to compare the geometrical rupture parameters of the "multiplet" fractures with those of the "borehole" fractures, focal mechanisms of multiplets are modeled by using a statistical approach. This is done by combining the geometry of the fracture planes, the P wave polarity and the S wave polarization, as seen only at the four stations. The S waves polarization shows an hexagonal anisotropy with a North- South horizontal symmetry axis, which is consistent with the regional maximum horizontal stress direction.

P. 545
Geomechanical Characterization of the Overburden Above the Compacting Chalk Reservoir at Valhall
Authors: Kristiansen Tron Golder
Published: December 2007

A study was initiated to improve the geomechanical input to the full field compaction/subsidence prediction model for Valhall and wellbore stability analysis models used to plan long extended reach wells in the Valhall field. The results are also applicable for other geomechanical activities in the field, like well design, waste injection, hydraulic fracturing stimulation in the reservoir and the design of a potential waterflood. The study used an integrated approach to characterize the Tertiary formations above the chalk reservoirs. In-situ stresses (magnitude and direction), pore pressure and geomechanical deformation properties of the formations were determined. Results, observations and conclusions are presented.

P. 193
Experience Transfer to Development Projects: How and Who?
Authors: Buset H. , Pagenhart A. , Throndsen T. I.
Published: December 2007

Various techniques have been used to facilitate transfer of experience and technology to different projects from operations and related projects. Results from different models are discussed, along with continuing challenges. Today's advances within global communication can significantly improve information sharing in design management and technical solutions. Many different professionals within the operations and project organizations are involved in experience transfer, and methods for organizing their interactions to streamline progress are discussed.
A comparison of approaches to EMS implementation in two E&P Companies
Authors: Brandon Oliver , Nixon Ashley
Published: December 2007

In recent years there has been an increasing interest in the design, development and implementation of environmental management systems (EMSs) in the E&P industry. In large measure this is due to the much higher profile that environmental issues have attracted in the public mind, and the requirement for organisations to demonstrate their commitment to excellent environmental performance. The introduction and widespread acceptance of ISO 14001 as a model for such EMSs has added a further impetus to the development process, among both companies with a long-standing environmental policy, and those whose environmental awakening has been more recent.

For those whose awareness of environmental issues is well established in management practices, the challenge has been to review systems and align them with the requirements of the Standard. For others, with a more recent environmental awakening, the challenge has been to create an EMS unsupported by a culture of environmental awareness or formalised management.

This paper compares the approach of two quite different companies to the design, development and implementation of their EMSs. In March 1997, Perez Companc S.A., an Argentine company, became the first E&P operator in the world to achieve ISO 14001, when three of their fields in Argentina were certified by DNVQA. Shell Prospecting and Development Peru (SPDP) are the leaders in the development of the Camisea gas field in Peru, and are well advanced in the adaptation of existing environmental management practices as part of their programme of ISO 14001 implementation, aiming for certification in 1998.

The experience of these companies has demonstrated that even though the context differs substantially between the two organisations, there are common features in their respective approaches to the process which may be useful guides to others embarking on similar programmes.
A Multi-Point Flux Discretization Scheme for General Polyhedral Grids
Authors: Gunasekera D. , Childs P. , Herring J. , Cox J.
Published: December 2007

Multi-point flux discretization schemes for triangular, 2D perpendicular bisection, tetrahedral, 3D perpendicular bisection and corner point grids have been presented in the past by Aavatsmark and Verma in several papers. This paper presents a single implementation based on the ideas in the above papers for general 3D structured and unstructured grids, regardless of their method of construction. In this work, multipoint flux (MPF) coefficients are calculated only for cell faces that exceed a K-orthogonality error limit and are supplied to the simulator as an additional list of transmissibilities.

Following a construction or a conversion, all grids are stored in a general unstructured grid data model, where a grid is a collection of cells, a cell is a collection of faces and a face is an ordered list of points. The surface of a cell face is described by the set of triangular facets created by joining the centroid of the face to its edges. Externally generated corner point grids are converted to this data structure before generating MPF terms, which may involve a face splitting step at faults. The permeability within each cell is allowed to be a full tensor at an arbitrary orientation. The K-orthogonality error is estimated at each cell interface and is used to select the transmissibility formula, which is either K-orthogonal type leading to a two-point flux or multi-point type.

The paper presents simulation results for a set of test examples, with and without the use of multi-point fluxes. Comparisons of accuracy and CPU times are also presented to provide an understanding of the efficiency of the scheme.

Technical contributions in the paper include the conversion of corner point grids into a triangular facet based model, an algorithm for calculating multi-point flux coefficients for general structured and unstructured grids and the handling of MPF terms in a simulator.
Fully-Coupled Geomechanics and Fluid-Flow Analysis of Wells with Stress-Dependent Permeability
Authors: Chin L. Y. , Raghavan R. , Thomas L. K.
Published: December 2007

A fully-coupled geomechanics and fluid-flow model is developed to analyze pressure transient problems in stress-sensitive reservoirs with nonlinear elastic and plastic constitutive behavior. For hydrocarbon reservoirs with stress-dependent permeability (stress-sensitive reservoirs), the coupled interaction between geomechanics and fluid production can significantly influence both the stress state and the fluid flow in the reservoir. Therefore, in general the coupling effect can not be ignored when analyzing stress-sensitive reservoir problems. Detailed model formulations and numerical implementation are presented. Practical application examples illustrating various aspects of well behavior analysis of stress-sensitive reservoirs are also demonstrated in this paper.
Integrated Reservoir and Surface Pipeline Network Compositional Simulations
Authors: Litvak M. L , Wang C. H.
Published: December 2007

Effective procedures for the integrated reservoir and surface facility compositional simulations have been developed. Multiphase compositional fluid flow equations in reservoir, well tubing strings, and surface pipeline network system are solved simultaneously. The procedures have been implemented in the commercial compositional reservoir and surface facility simulator VIP.

The equation of state is applied for the phase-equilibrium calculations. New equation of state (EOS) interpolation procedure has been developed (as an option) for simplified phase-equilibrium calculations in integrated compositional simulations. The EOS interpolation procedure can be effectively applied for phase-equilibrium calculations in reservoir, well tubing strings, pipelines, and/or separators. Saturation pressure, recovery factors of hydrocarbon components, and compressibility factors are determined as tabular functions of pressure, temperature, and fluid compositions. The equation of state is applied for the automatic generation of these functions in an initialization step of a reservoir simulation.

The effectiveness and accuracy of the new simplified phase-equilibrium procedure have been confirmed in many full field compositional models and pattern models. The new option significantly reduces the CPU time required for the simulations and it matches results of fully compositional simulations in tested models.

The developed procedures for the integrated reservoir and facility compositional simulations have been applied in many reservoir studies. Their applications in the integrated reservoir and surface facility model of the giant Prudhoe Bay oil field have been demonstrated.
A Generalized Friction Factor Correlation to Compute Pressure Drop in Horizontal Wells
Authors: Yalniz M. U. , Ozkan E.
Published: December 2007

This work investigates the effect of fluid ingress through perforations on flow in a horizontal wellbore and correlates this effect in the form of an apparent friction factor. The investigation uses theoretical and experimental models. It is shown that when there is no influx, the perforations or slots on the well surface cause a reduction in the pressure gradients proportional to their area. The wellbore pressure gradients increase with influx from perforations but unless the ratio of the influx rate to the wellbore flow rate is sufficiently large, pressure gradients are lower than those of an unperforated well. The results of this study are combined to develop a generalized friction factor correlation that is a function of the Reynolds number and the ratios of the influx to wellbore flow rate and the perforation to wellbore diameters.