bluuebunny/crossref_metadata_2025 huggingface dataset:
Deep Water Structures in Concrete
Authors: Stubbs S.B.
Published: December 2007

This paper was prepared for the Second Annual European Meeting of the Society of Petroleum Engineers of AIME, to be held in London, England, April 2–3, 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 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.

Large concrete structures for use in deep water oil fields were probably originally conceived to fulfil an oil storage role, but more recently they are seen as platform supporting structures, rivalling the giant steel platforms now under construction for tie North Sea areas.

The paper reviews the general design considerations confronting the designer of large concrete structures, including the important soils considerations. The structural design problems have been examined, followed by a review of the construction considerations involved in building these large structures in a short space of time.

Finally, the all important marine considerations including towing and final installation on site are examined.

Introduction

For very many years there has been a choice of construction material for a wide range of land structures. Bridges, buildings, towers etc. have been designed and built in structural steelwork or reinforced concrete. Both forms of construction hold considerable merit and the choice between the two can often depend upon mere whim or upon closely reasoned engineering logic. For example, in the case of major highway bridges, it is not uncommon for tenders to be invited for the construction in one material and for the contract to be let on the basis of an alternative design in the "rival" material. The balance changes as the technology advances first with one material, then with the other.

There has been the same trend with many coastal structures with jetties and piers constructed in steel or concrete.
Design of Production and Processing Facilities for Offshore and Remote Locations
Authors: Worley M.S.
Published: December 2007

This paper was prepared for the Second Annual European Meeting of the Society of Petroleum Engineers of AIME, to be held in London, England, April 2–3, 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 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.

Site fabrication of production and processing facilities for offshore processing facilities for offshore or for very remote locations are often several times the cost of facilities constructed inland near industrial areas.

The high costs result from inherently low manpower efficiency, the high cost of mobilizing manpower, skills, machinery and materials and the very frequent need for high priced stand-by equipment and services.

Time requirements and costs are substantially reduced by pre-assembly and delivery of modules to the site where water transportation to the site is possible or where large skids or modules may be easily moved by sea and land. Complete production and processing plants are now being manufactured and tested mechanically and electrically in efficient factory environments where necessary components, skills and manpower are readily available. Engineering expertise has been developed and refined for positive module fit-up and for minimizing costly offshore construction and commissioning activities.

Introduction

Most offshore oil and gas production and processing platforms and some remote land and swamp locations represent the most expensive construction sites in existence. Costs are high for support structures for operating facilities in deep water where poor soil conditions prevail. Costs are directly related to horizontal space requirements and total weight loading of the support structures and bearing surfaces or for decks to hold the production equipment.

After costs for the support structures and space requirements have been optimized, production and processing facilities themselves are still very costly. These high construction costs are directly related to the many facets of inherently inefficient mobilization and utilization of manpower in hostile environments and at remote locations.
Formation Clay Chemistry
Authors: Perricone A.C. , Browning W.C.
Published: December 2007

Publication Rights Reserved

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 considered for publication in one of the two SPE magazines with the paper.

It is apparent that improvement in the chemistry of drilling fluids leading to improved drilling efficiency is dependent upon increased knowledge of sub-surface geology and geochemistry. Because of the significance and prevalence of sub-surface clays and shales, the study of formation clay chemistry is of fundamental importance to drilling production. This paper presents certain aspects of formation clay chemistry that open new avenues of approach in drilling fluid design.

Of utmost significance in formation clay chemistry is the avidity with which hydroxyl ions react with clays. This hydroxyl reaction of clays was found to cause a radical increase in total surface area and rate of cleavage in non-swelling clays such as illite, as well as clays of the expanding lattice type. It is indicated, therefore, that it is the hydroxyl reaction of clays that is primarily responsible for the weakening of the borehole formations and "mud-making" drilling fluid tendencies.

Clay base exchange reactions promoted by aqueous drilling fluids of selected cation composition are indicated to be more detrimental than beneficial when viewed from the standpoint of formation chemistry. In fact, non-reactivity of the drilling fluid with formation clays appears to be a most important drilling fluid requisite. Non-reactivity or inertness of the water phase is shown to be achieved by maintaining the absence of base exchanging cations and hydroxyl ions, and is distinct from the older ideas of inhibition or "inhibited muds".

Because of chemical reactivity and mechanical effects, it is concluded that any invasion of drilling fluid media into borehole or producing formations is damaging no matter whether the liquid is aqueous or non-aqueous. In fact, it appears that advantages previously claimed for certain drilling fluids were probably due to filtration control rather than composition of the liquid phase.
Prediction Of Pressure Gradients For Multiphase Flow In Tubing
Authors: Fancher George H. , Brown Kermit E.
Published: December 2007

An 8000 ft. experimental field well was utilized to conduct flowing pressure gradient tests under conditions of continuous, multiphase flow through 2-3/8 in O.D. tubing. The well was equipped with 10 gas lift valves and 10 Maihak electronic pressure recorders as well as instruments to accurately measure the surface pressure, temperature, volume of injected gas and fluid production.

These tests were conducted for flow rates ranging from 75 to 936 B/D at various gas-liquid ratios from 105 to 9433 SCF/BBL. An expanding orifice gas lift valve allowed each flow rate to be produced with a range of controlled gas-liquid ratios. From these data an accurate pressure traverse has been constructed for various flow rates and for various gas-liquid ratios.

A comparison of these tests to Poettmann and Carpenter's correlation indicates that deviations occur for certain ranges of flow rates and gas-liquid ratios.
The Transmission of Gaseous Hydrogen
Authors: Wurm Jaroslav , Pasteris Robert F.
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 acknowledgement 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.

The paper considers both the economics and the technical aspects of an onshore hydrogen transmission pipeline. Compressors and hydrogen embrittlement problems are discussed.

The main conclusions are -The current natural gas transmissionlines can handle the equivalent amount of hydrogen on the basis of equal energythroughput, when both the capacity and power input of the section's compressorstation are increased.Using the current economic factors and disregarding the initial compression, theoptimum hydrogen transmission costs approach 2.5 cents/million Btu-100 miles for a 2000-psia average operating pressure and a fuel cost of $3/million Btu compared with about 1.5 cents/million Btu-100 miles for natural gas.

Introduction

The potential of hydrogen as a future fuel is being generally recognized as a way of meeting our energy "challenge." Recently, an energy concept based on this potential termed "the Hydrogen Economy" or "Eco-Energy" has been proposed. Studies indicate that there would be no insurmountable problems for such a system. They have also shown the reasons why hydrogen is so attractive as a means of transporting energy: Hydrogen is a clean fuel, and it would be relatively less expensive to transport and distribute compared with electricity.

HYDROGEN AS A MEANS OF ENERGY TRANSMISSION

Currently, energy is mainly delivered to the consumer in electrical and chemical forms. Statistical data are available for evaluating the cost that transmission contributes to the price the consumer pays for energy. For instance, a typical 36-inch natural gas pipeline is capable of moving energy at a rate of about 1 billion Btu/hr, or 12, 000 MW, at a cost of about 1 cent-2 cents/million Btu-100 miles ($0.03 to $0.07/MW hr-100 miles).
Unique Hydraulic Lift System
Authors: Bell C. Allen , Spisak Charles D.
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 acknowledgement 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.

Oil producing companies are continually seeking new ways to cut production costs through the production costs through the development of new ideas.

This paper discusses a unique, economical hydraulic lift system installed by the Lafayette Division of Continental Oil Company. This system combines a new venturi, hydraulic bottom-hole pump and a compact, centrifugal power fluid cleaning system into a single installation. This jet eductor pump, or jet pump, is relatively unaffected by high gas-liquid ratio production or dirty power fluid and requires very little maintenance. The fluid cleaning system provides power fluid which meets the quality power fluid which meets the quality requirements of the jet pump for considerably less initial investment and lower operating costs than a conventional power fluid system. This combination is power fluid system. This combination is particularly adaptable to single well particularly adaptable to single well leases or fields.

Currently, two of these compact systems are in operation producing sour crude from the deep Smackover formation in Mississippi. Excluding the problems corrected during an initial startup period, no system operating problems have been reported after a cumulative twenty-nine months of service.

Introduction

The Lafayette Division of Continental Oil Company has in operation two hydraulic lift installations which incorporate a new venturi hydraulic pump and a compact power fluid cleaning system, to be called "POCS" (power oil centrifugal separation) unit, into a unique system. To our knowledge, these were two of the first uses of this combination in the industry and the first installations designed specifically for use of a jet pump.

The two single well systems were installed on wells in the deep Mississippi Smackover trend.
Fourteen Years of Progress in Catalytic Treating of Exhaust Gas
Authors: Barstow W.F.
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.

In the year 1959, the first successful system for producing noncorrosive inert gas from internal combustion engine exhaust was installed and put on-stream in a Louisiana oil-producing field. It employed a four cycle, naturally aspirated, integral engine compressor and delivered 1.0 MMscfd of catalytically purified dry inert gas at a maximum pressure of 4500 psig.

Many abortive attempts had been made in the preceding forty years to produce a compressible inert gas from engine exhaust, from boiler stack gas or from combinations of the two. In most cases, they were complete failures or had only limited success because of the corrosive qualities of the gas. The one known successful plant in operation at that time was Pan American's installation at Elk Basin, Wyoming. It had been put on-stream in 1949 and made use of stack gas from specially designed steam boilers. The design capacity of this facility was 15.0 MMscfd. In early stages of operation, they too encountered severe corrosion in compression and related equipment. It was later alleviated, but not completely eliminated, through ammonia injection into several points within the system in sufficient points within the system in sufficient quantities to render all condensate with a pH between 6.5 to 7.0.

Since 1959, progress in the field is quite evident. Inert gas plants employing engine exhaust have grown remarkably in size and in pressure capabilities. Today there is one located in a California oil field that can deliver in excess of 16.0 MMscfd at a maximum pressure of 6000 psig. Larger plants that will deliver more than 50.0 plants that will deliver more than 50.0 MMscfd are required and are in the design stage. A steam boiler stack gas plant incorporating steam turbine driven centrifugal compressors is now in service generating in excess of 50.0 MMscfd with plans on the drawing board for a facility to produce over 120.0 MMscfd.

While no significant changes have been made in the process that was successful in 1959, many progressive improvements have been discovered and employed in operating techniques and in the many components incorporated in the system.
Salt water Gel Packer Fluid for High Pressure Completions
Authors: Mayell M.J. , Stein F.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.

Past completion techniques in the middle Past completion techniques in the middle to lower miocene abnormally pressured gas sands in the Gulf Coast area have involved the use of a weighted mud as a packer fluid. Workovers on these wells incur extremely high costs associated with recovery of tubing stuck in settled mud solids. To reduce the workover costs and expense of lost or damaged tubing, packer fluid requirements were reexamined to select a fluid that would prevent these problems. Two unweighted systems were selected from an overall review and comparative tests were run to determine long term stability, sealing properties, and handling ease. Results of the properties, and handling ease. Results of the tests determined a suitable solution for use in Gulf Coast high pressure completions.

A fluid composed of 25#/bbl. attapulgite gel in a saturated saltwater solution with a chromate corrosion inhibitor and the pH adjusted to 10.5 with soda ash showed a clear superiority. It has been used in Gulf Coast wells for three years and field experience in producing and workover situations has supported producing and workover situations has supported the test results.

Introduction

It has been standard practice to use drilling mud as a packer fluid in high pressure wells in many companies since that type completion was first made. The apparent advantages of drilling mud are:The fluid is available at no additional cost.In the event of a tubing leak, the hydrostatic column may be sufficient to kill the well and may avoid troublesome casing pressure.In the event of a casing leak, drilling mud solids have excellent sealing characteristics against moderate differential pressures.

The disadvantages of drilling mud packer fluids, however, appear later in the life of the well and have a significant effect on workover costs. The problems surface in the following forms:Barite settling results in extensive fishing operations to pull the tubing.High temperature gellation of lime base fluids requires washover operations to clean out the well.Lignosulfonate degradation to H2S in lower pH environments causes tubular stress failures.
Energy Development: A Resource Allocation Problem
Authors: Fore James G.
Published: December 2007

Fore, James G., Member AIME

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.

The actions of both the producer and consumer in the energy market have been very rational as each tries to maximize his position. The producer is motivated by profits while the consumer is seeking to maximize his total level of utility. The problems that are occurring in the energy market can be traced in most cases to one of market restrictions or failure of the market to fully reflect costs due to externalities. It is these restrictions and/or externalities that have led to our present energy crisis and not any overt acts by present energy crisis and not any overt acts by the producers or consumers.

Introduction

Most people acknowledge that as the demand for resources increases and these resources become scarcer the price would move higher. The effect of this increase in price would be to reduce demand for that price would be to reduce demand for that resource by causing some individuals to substitute more abundant resources for scarcer ones, or it would increase the supply of that resource by development and application of new technologies to permit the use of poorer quality resources. This in turn would lead to an optimal use of resources.

The price referred to here is the market price, the market price being established by price, the market price being established by bringing together the demand curve of consumers and the supply curve of producers, Figure 1. The purpose of the price is to help our economic system achieve efficiency. It does this in two ways. The first concerns the allocation of the currently available goods and services. The second concerns the production of goods and services, that is, production of goods and services, that is, what quantities of what goods and services should be produced.

This price is completely impartial in the allocation of goods to consumers as well as to who shall produce the goods. So one would expect to hear complaints about the price being too high from some consumers and being too low from some producers. After all, allocation is the purpose of the market price. price.
A New General Optimization Method - Application to Gas Gathering System
Authors: Ghez Fabien
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.

The object of this paper is to present a new optimization method developed for problems concerning operating policy in oil or gas fields. Several mathematical procedures have been used, but none permits the handling of problems that are, at the same time, nonlinear, problems that are, at the same time, nonlinear, discrete and submitted to constraints.

The method proposed here is based on probability concepts, and the algorithm probability concepts, and the algorithm described is shown to converge, in probability, to the optimal solution.

An example of a gas-gathering system optimization illustrates the method. This example seems appropriate as it is similar to many exploitation problems. Indeed, most of them are nonlinear (friction losses, as an example), discrete (such as connecting point locations and pipe diameters), submitted constraints (pressures at wellheads and fluid speed in flow lines).

The computing efficiency of the method is then tested.

Introduction

While, in every industry, decision problems are important, this is certainly most evident in the oil- or gas field development strategy where almost always, the "best policy" must be at the very beginning, despite the small amount of available information.

The various decisions to be made relative to the development or abandonment of a field, on the basis of a very small number of exploration wells, are far from obvious. In practice, all operational aspects are concerned. It is not sufficient to search for a technical-economic optimum by successive trials without taking all variables into account. The following examples require particular accuracy in calculations that is not always reached:well drilling schedules and well locations during field life,design and construction of a gas-gathering system andcompressor positions and required power, if necessary.

Several methods have already been developed, but their mathematical limits have forced users to simplify their problems. A general optimization method is presented here. It will be seen that the described algorithm converges to the best technical-economic decision or "optimum decision" in a probability sense. It is applied to the development of a gas-gathering system in the case of a dry gas field.
Good Operating Strategy Saves Compressor Fuel in Natural Gas Transmission
Authors: Rachford H.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.

The fuel used for compression in modern long transmission systems is about 5% per thousand miles under full-capacity steady load. For a long system the minimum required compression work needed for steady loads is approximately proportional to the ratio of the cube of the delivery rate to the square of the mean flowing pressure. However, demand usually varies periodically, causing systems to operate in the transient state with an average delivery rate less than the design value. In this case, the work (and fuel) required should be substantially lessened.

This paper applies a transient model to study a realistic theoretical system delivering 90% of design rate with +10% daily demand variation. An iteration for improving the strategy of using existing compression equipment 'was developed. This procedure led to a mode of operation which required 16.7% less fuel than that for a conventional operation of this system.

Introduction

Long line transmission systems are designed to optimize the use of initial investment capital in pipe and compression facilities for a specific, steady delivery rate. Application of such design criteria in the past has led to pipe and compressor sizing so that about 5% of the gas delivered is burned as fuel each 1000 miles. While the supply shortage may change such design criteria in the future, it appears timely to study possible ways of saving fuel usage in existing systems now. It is the purpose of this work to examine whether the required fuel can be decreased for existing systems in conventional operation by simply changing operating strategies.

Demands at sales points are usually variable in time, and as a result the average throughput of a system in practice may fall 10–20% or more below the design rate. This follows since constraints on the system, such as minimum delivery pressures and maximum pipe pressures, fix pressures and maximum pipe pressures, fix the maximum sustained delivery rate at the steady state design figure.
Virgin Damage Surface of a Synthetic Analogue to a Reservoir Sandstone
Authors: Unander Tor Erling , Holt Rune M.
Published: December 2007

This paper is based on laboratory investigations of synthetic sandstone cemented under stress making it possible to perform mechanical tests directly from the simulated in situ stress state. We have mapped the acoustic emission damage surface, or Holcomb surface as we have called it here, around this stress state. The results show that this surface does not coincide with the "true" damage surface as damage is induced in the material even for very small load deviations from the forming stress state. The Holcomb surface mapping is done with a new technique that is able to better describe and quantify onset of acoustic emission.

P. 23
Static and Dynamic Compressibility of Deep Underground Caverns
Authors: Berest P. , Bergues J. , Brouard B.
Published: December 2007

Compressibility of deep fluids-filled cavern is discussed. Compressibility is measured both through statical and dynamical tests. Statical compressibility is influenced by cavern shape and cavern fluids nature. This parameter plays an important role for such applications as the determination of stored hydrocarbons volume, of volume lost during a blow-out, and of pressure build-up rate in a closed cavern. Dynamical compressibility is measured through the periods of waves triggered by pressure changes. Both tube waves and longer period waves associated to the existence of an interface between a liquid and a gas can be observed. They can provide additional information, for instance the existence of trapped gas in the well-head.

P. 105
A Comparison Of Leak-Off Test And Extended Leak-Off Test Data For Stress Estimation
Authors: Addis M.A. , Hanssen T.H. , Yassir N. , Willoughby D.R. , Enever J.
Published: December 2007

The principal function of leak-off tests is to assess casing integrity, but the test data are commonly used beyond this original purpose, for stress estimations in exploration and drilling. The value of leak-off test data for stress estimation is questionable and extended leak-off tests have been proposed as a more appropriate method for stress estimation. The paper for the first time compares leak-off test (LOT) and extended leak- off test (ELOT) data from two areas, the North West Self of Australia and the Norwegian North Sea. Standard LOTs have a characteristically large scatter associated with the leak-off pressures (Plo), minimum stress and fracture gradient estimates in both areas. However, the minimum stress determined from ELOTs are consistent and form a lower bound to the standard fl0 data in both areas. The ELOT takes about an hour to perform, but provides far superior data than that obtained from a LOT, and is recommended where stress data are required.

P. 131
Can Dipmeter logs be used to identify In-situ Stress Directions in the North Sea?
Authors: Fejerskov M. , Bratli R.
Published: December 2007

Analysing borehole breakouts is a well known method for obtaining horizontal stress directions. In this study dipmeter data from 46 wellbores in the Tampen area in the northern North Sea were analyzed for breakouts. The analysis identified a large problem of differentiating borehole breakouts from key- seats. Even at very low bole deviation elongations seemed to align with hole azimuth. This hampered breakout identification, and indicated that key seating possibly is a much larger problem than implied in earlier breakout work from the North Sea From our findings and also based on other stress data from the area it seems as though the wellbore very often deviates in the direction of the least horizontal stress, thereby masking breakouts as key seats. To examine this observation the effect of bedding and stress on the wellpath were examined, without yielding a solution to the problem. For future stress analyses in the northern North Sea enhanced use of imaging data will be important to avoid similar problems. Borehole breakouts identified by dipmeter analysis primarily seem to give an indication of the in-situ stress direction, as long as the number of observations are statistical significant. Traditional breakout analysis should not be trusted alone, but always be constrained by, for instance, image analysis.

P. 151
Constraining the State of Stress in Tectonically Active Settings
Authors: Plumb R. , Papanastasiou P. , Last N.
Published: December 2007

This paper describes the hierarchical approach used to characterize the regional state of stress in tectonically active settings. The example featured here is the Cusiana field where wellbore instability was a serious problem. The Cusiana field is located in the foothill of the Colombian Andes, South America. A key to solving the instability the was to identify what stress information was needed to improve drilling performance. Using drilling records, caliper logs, cavings samples, cores from the reservoir and a few meters of borehole image, an internally consistent working hypothesis of the state of stress was formulated, tested and refined. Simple calculations based on elastic-brittle model, confirmed also b, y drilling data, showed that the minimum principle stress is horizontal and the overburden was the intermediate stress. Elastoplastic modeling of borehole deformation in sands and shales based on core testing and finite element analysis placed tighter constraints on the relative principal stress magnitudes and the magnitude of the maximum horizontal stress.

P. 179
Flexurally-Induced Stresses in the Northern North Sea: Preliminary Comparison of Observation and Theory
Authors: Grollimund B. , Zoback M.D. , Arnesen L.
Published: December 2007

In this work we evaluate the role of lithospheric flexure resulting from post-glacial rebound as a possible source of regional stress variations in the northern North Sea. Compilations of leak-off and pore pressure data, estimates of the full stress tensor from observations of wellbore failure, and earthquake focal plane mechanisms indicate high horizontal compression (i.e., SHmax>Sv and Shmin=Sv) on the west side of the Viking Graben and decreased horizontal stresses on the east side. In this study we extend the available knowledge about regional stress magnitudes by analysis of leak-off and pore pressure data. We use numerical modeling of lithospheric flexure due to post glacial rebound to show that this is a possible cause of the observed high horizontal compression in the Tampen Spur, regional stress variations and possibly the high pore pressures observed at depth west of the Viking Graben.

P. 189
The Shrinkage Rate of KCL-Exposed Smectitic North Sea Shale Simulated By a Diffusion Model
Authors: Bostrom B. , Svano G. , Horsrud P. , Askevold A.
Published: December 2007

Based on a containment transport model developed for hydrogeological purposes, a numerical method for the analysis of intrusion of potassium ions into a shale has been developed. The scheme has been applied in the back-analysis of KCl-brine exposed specimens of smectite-rich Tertiary Paleocene shale from the North Sea. The specimens, exposed under effective confining stresses in a triaxial cell at 80 C, shrank during the KCl-exposure. Two tests with different KCl concentrations (5wt% and 20wt%) have been back-analysed.

The ion transport is modelled by diffusion Using a finite difference scheme. In the back-analysis it was assumed that the observed shrinkage is due to the ion exchange when the bound Na+-ions are exchanged with K+-ions from the exposure fluid. The agreement between simulated and measured shrinkage rate was good, indicating that the assumed relation between ion transport, ion exchange and shale shrinkage is a valid mechanism.

The simulations showed tensile stresses near the specimen boundaries, where the shale first shrinks. A downhole situation was therefore analysed with a linear elastic model, and the development of tensile stresses with time was investigated. This linear elastic analysis showed that in the vicinity of the borehole wall, large tensile stresses develop as the front of the K+ ions progresses into the shale. Such tensile stresses may lead to the development of cracks and fissures, which in turn increases the surface area of the brine-exposed shale. An accelerating mechanism of cracking may thus develop, increasing the potential of destabilising the shale.

For each practical case there is thus an upper limit to the KCl-concentration which should be used in smectite-rich shale. Up to this limit, stability is improved due to a reduced stress concentration. Above this limit, stability problems will increase with increasing KCl-concentration.

P. 273
Laboratory Study of Permeability Evolution in a Tight' Sandstone under Non-Hydrostatic Stress Conditions
Authors: Keaney G.M.J. , Meredith P.G. , Murrell S.A.F.
Published: December 2007

Hydrostatic and triaxial compression experiments have been conducted to investigate the evolution of fluid permeability and fluid storage capacity in Tennessee sandstone, a low- porosity tight' reservoir sandstone. A newly developed single-ended transient pulse permeability measurement technique has been used for this study. Under hydrostatic stress, both permeability and specific storage are demonstrated to be dependent upon effective confining pressure. The evolution of axial permeability as a function of increasing compressive deviatoric axal sttess has been investigated in triaxial compression experiments. All samples were deformed within the brittle faulting regime. Both permeability and specfic storage decrease during compaction, and subsequently increase when axially-aligned dilatant microcracking becomes dominant. Brittle failure is sometimes accompanied by a transient increase in permeability by as much as 1.5 orders of magnitude. Following brittle failure the permeability is controlled by the properties of the fault rock. Permeability decreases as stable sliding occurs on the fault up to large axial strains, such that the fault may act as an impermeable seal to migrating fluids.

P. 329
Reservoir Compaction and Seafloor Subsidence at Valhall
Authors: Pattillo P.D. , Kristiansen T.G. , Sund G.V. , Kjelstadli R.M.
Published: December 2007

The combination of in situ effective stress and reservoir chalk mechanical weakness in the Valhall field has resulted in compaction and associated subsidence at the mudline. This paper summarizes recent finite element modeling of this phenomenon, emphasizing items of concern in a numerical simulation of this nature. The paper also presents new results from a simulation allowing inelastic overburden response.

P. 377
Integrated Borehole Stability Analysis - Against Tradition
Authors: Zheng Z.
Published: December 2007

Technological advances in drilling equipment, directional control and mud systems and a better understanding of reservoir properties have resulted in the drilling of an increasing number of highly deviated and horizontal wells. Along with these wells come the increasing borehole instability and sand production potentials under normal in-situ stress conditions (when the stresses are vertical and horizontal, with vertical greater than both horizontal stresses). Conventional guidelines for horizontal well design have been to drill in the direction parallel to the minimum principal stress, which reduces the difference between the principal stresses perpendicular to the borehole, and results in a minimum stress concentration around the borehole. Such guidelines are based on an effort to reduce the required borehole pressure to maintain zero breakout.

Research on borehole breakout and borehole stability in the past fifteen years has shown that a stable breakout is characterized by a stress distribution which transfers the high stress concentration from the opening to the zone near the tip of the breakout, and causes a quasi-hydrostatic stress state in that zone. Breakout geometry is therefore more stable than circular geometry. Recent experimental studies on utilizing breakout geometry to enhance tunnel stability have also shown that breakout geometry has a much greater "excavation strength" than circular geometry under the same stress configurations. Breakout geometry provides a "self-supportive" function that allows a smaller degree of failure potential around the borehole than other excavation geometries.

Fundamental stability mechanisms for stable breakout are revisited and the feasibility of drilling parallel to the intermediate principal stress direction under stable conditions investigated through numerical simulations. The results show that under most in-situ conditions, drilling in the intermediate principal stress direction and allowing some degree of breakout affords tmproved stability during drilling and subsequent production, provided that the breakout generated failure materials can be removed efficiently. The mud weight required to maintain stability is substantially less for this type of borehole configuration that leads to reduced formation damages, and allows for the generation of a single hydraulic fracture parallel to the borehole rather than multiple fractures perpendicular to the borehole (assuming it is drilled in the direction of the minimum principal stress). The cost savings and possible production enhancement derived from such drilling practices could result in a dramatic economic impact on the petroleum industry.

P. 395
Reservoir Compaction, Surface Subsidence, and Casing Damage: A Geomechanics Approach to Mitigation and Reservoir Management
Authors: Fredrick J.T. , Deitrick G.L. , Arguello J.G. , DeRouffignac E.P.
Published: December 2007

Geologic, and historical well failure, production, and injection data were analyzed to guide development of three-dimensional geomechanical models of the Belridge Diatomite Field, California. The central premise of the numerical simulations is that spatial gradients in pore pressure induced by production and injection in a low permeability reservoir may perturb the local stresses and cause subsurface deformation sufficient to result in well failure. Time-dependent reservoir pressure fields that were calculated from three-dimensional finite difference reservoir simulations were input into three-dimensional nonlinear finite element geomechanical simulations. The reservoir models included nearly 100,000 gridblocks (100-200 wells), and covered nearly 20 years of production and injection. The geomechanical models were meshed from structure maps and contained more than 300,000 nodal points. Shear strain localization along weak bedding planes that causes casing dog-legs in the field was accommodated in the model by contact surfaces located immediately above the reservoir and at two locations in the overburden. The geomechanical simulations are partially validated by comparison of the predicted surface subsidence with field measurements, and by comparison of predicted deformation with observed casing damage. Further, simulations performed for two independently developed areas at South Belridge, Sections 33 and 29, corroborate their different well failure histories. The simulations suggest the three types of casing damage observed, and show that although water injection has mitigated surface subsidence, it can, under some circumstances, increase the lateral gradients in effective stress, that in turn can accelerate subsurface horizontal motions. Geomechanical simulation is an important reservoir management tool that can be used to identify optimal operating policies to mitigate casing damage for existing field developments, and also applied to incorporate the effect of well failure potential in economic analyses of alternative infilling plans and operating strategies.

P. 403
Three History Cases of Rock Mechanics related Stuck Pipes while drilling Extended Reach wells in North Sea.
Authors: Charlez P.A. , Onaisi A.
Published: December 2007

Stuck pipes have three different origins : hole geometry (excessive dog legs in highly deviated wells), pack off (wellbore instability or bad hole cleaning leading to a plugging of the annulus) and differential sticking (drill string embedded into the mud cake due to an excessive difference between mud weight and reservoir pressure). This paper presents three different examples of stuck pipes directly related to rock mechanics problems.

The first one results from a typical pack off in a highly unstable under compacted shale formation drilled in under balanced conditions.

The second stuck pipe is quite untypical since it occurred while drilling a 9 5/8 cemented shoe track. Finally, the third one occurred while drilling the reservoir section of a highly deviated well (720 inclination) and during a directional survey. The analysis of the surface data clearly showed that differential sticking was the cause of the stuck pipe.

In the three cases, the well had to be side tracked where each time the cost was in the range of 1M.

P. 423
Seismic Wave Propagation in Fractured Rock
Authors: Myer L.R. , Pyrak-Nolte L.J. , Yi W.
Published: December 2007

Azimuthal variation in shear wave speed and existence of two shear wave arrivals are commonly assumed to be diagnostic of fractured rock. These properties derive from a representation of fractured rock as an effective anisotropic medium. Work on effects of single fractures suggests that energy can be partitioned in ways that are not captured by the effective medium representation. Single fractures cause frequency dependent reflections, refractions and group time delays in plane waves and can trap energy as interface waves. These effects can result in distinctive seismic signatures in multiply fractured rock.

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