bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Improved Method for the Design and Field Implementation of Air-Mist Drilling
Authors: Wilkes T. M. , Watson R. W. , Graham R. L.
Published: December 2007

Misconceptions with respect to the use of mist drilling have existed within the drilling industry since the 1950's. For example, industry has accepted the fact that a significant increase in the volumetric air flow rate was required when mist drilling. Calculations using Angel's1 approximation for conventional dry-air drilling, in fact indicated that approximately 35 to 40 % more air was necessary. This misconception2 has continued to this day and is contained in recently published drilling articles and reports. The primary objective of this paper is to correct this misconception and to demonstrate how a correct design can be accomplished at the field level.

Moreover, the paper also discusses the use of foam for the handling of the influx of liquids during air drilling. A new relationship between the fraction of soap to the fraction of liquid (including influx) is presented. The results of model-derived computations for predicting cuttings transport in a mist system are included for the purpose of demonstrating the concept. Field case study calculations using the model are documented. Comparisons between these new, improved calculations and incorrect calculations based on conventional air drilling techniques are included and discussed in terms such as cuttings size transport. Practical recommendations with respect to field operations are included.

The implementation of the recommendations and new methods in this paper will result in improvements in the design of air-mist drilling, increased use of air drilling, the implementation of mist drilling with percussion hammers, better understanding of cuttings transport in mist systems, and more efficient use of soap in the mist drilling.
Field Curves for Critical Buckling Loads in Curving Wellbores
Authors: Hill T.H. , Chandler R.B.
Published: December 2007

This paper gives a plotting technique and curves for estimating the axial compressive loads for the onset of sinusoidal buckling in curving wellbores. The analysis and data calculation are based entirely on previous work by others. Only the method of presenting the data is new. Curves are given for several common drill pipes.

P. 259
A New Generation of Dynamically Positioned Drillship for 10,000 Ft. Water Depth
Authors: Duhen Thomas , de Bonnafos Olivier , Rietveldt Bob
Published: December 2007

Following the first involvement of Foramer with Dynamically Positioned Drillships in 1966, IHC Gusto Engineering developed the "Pelican" design in 1972, with the assistance of Foramer for the drilling package.

The "Pelican" design became the most widely design used for DP Drillships, with 10 units built.

For the new challenge of ultra deep water depths up to 10,000 Ft., IHC Gusto design expertise and Foramer 30 years experience in operating up to four of the "Pelican" design DP drillships, joined forces to develop a new generation DP drillship.

A description of the design and the motion characteristics of the vessel, as well as operational considerations are included.

P. 409
Trends Extracted From 800 Gulf Coast Blowouts During 1960-1996
Authors: Skalle Pal , Podio Augusto L.
Published: December 2007

The cost of blowouts and the loss of lives incurred from blowouts warrant the study of past occurrences in order to reduce the possibilities of future blowouts.

Even though we continuously learn more about how to handle an unstable well, it seems that the problems of detection, handling kicks and loosing control do not change much with time in the real world - out on the rig. The small changes and improvements that do occur are first of all seen thorough statistical data. A new data base resently compiled will soon contain extensive data on more than 800 blowouts from the Gulf Coast area and adjoining states during the period 1960 through 1996. At the moment the compiling work has not been completed. However, at the 1998 IADC/SPE Drilling Conference an updated version of this paper will be available. Five agencies contributed blowout report information. The State Oil and Gas Boards/Conservation Office of Alabama, Mississippi and Louisiana, The Railroad Commission of Texas and the Mineral Management Service (MMS) of the Dept. of Interior.

At the moment the Texas blowouts make up approximately 50% of the blowouts in the data base but range below the average blowout frequency of 0.15 blowouts pr. 100 well-ft. drilled. The three major operations in progress when blowouts occurred were exploratory drilling, workover and development drilling. Most frequently blowouts occurred during the activity of actual drilling, tripping out and circulating/killing. The analysis indicated also that the major causes were related to swabbing, drilling into a high pressure zone or formation break down while the secondary barrier after a kick has occurred which most often failed were either failure to close BOP, failure to stab string valve or BOP failed after closure.

P. 539
Biodegradable Surfactants for Cosmetics Find Application in Drilling Fluids
Authors: Nicora Luigi F. , McGregor William M.
Published: December 2007

Alkylpolyglucosides (APG) are highly biodegradable surfactants which have not previously been used in drilling fluids and yet are commonly used in many other fields such as cosmetics. APG are shown in laboratory tests to act synergically with the polymers commonly used in drilling fluids. The addition of APG, even at very low concentrations, to a polymer mud can drastically reduce the fluid loss even at high temperatures. Moreover both fluid rheology and temperature resistance are improved.

P. 723
Eliminating the Stabber When Running Casing and Tubing: The Next Step in the Rig Mechanization Process
Authors: Hollingsworth Jim L. , Lorenz Joerg
Published: December 2007

While running a string of casing or tubing one of the crew works thirty to forty feet above the rig floor secured to the rig by a safety cable. He is known as the stabber and his is arguably the most physically demanding and potentially dangerous job on a casing crew. Due to the inherent danger of the stabber's job along with the industry's ongoing pursuit of accident reduction, a system was developed to eliminate the need for the stabber without requiring major rig modifications or new construction. This system incorporates all of the stabber's functions using a combination of both new equipment and existing tools that have been modified. A mechanized stabbing device, air-operated elevator and spider with an integrated safety interlock system, a flagging device and a redesigned single-joint elevator compose the system. The mechanized stabbing device and elevator and spider with safety interlock system have been used with great success in the running of casing and tubing in the Gulf of Mexico and North Sea. Trials on a test rig have been completed on the single-joint elevator and flagging device and both are awaiting field trials as of the submission date. With the introduction of this system, safety and reliability during pipe running operations will be greatly enhanced and from this will follow the economic benefits.

P. 779
Anaerobic Biodegradability of Oil Base Fluid For Invert Emulsion Drilling Fluid.
Authors: Blanchet D. , Audibert A. , Argillier J-F.
Published: December 2007

Environmental legislations restrict the use of oil based muds, specially in North Sea and their discharge under the form of oily cuttings. Different synthetic based muds (SBM) are proposed for replacing gas oil as the base fluid. These are low toxicity mineral oils, poly or mono olefins, acetals, esters… Controversial data exist concerning their biodegradability under aerobic or anaerobic conditions. Both conditions are representative of offshore drilling activities since the oil present in the cuttings deposited on the seabed can be degraded 6n the surface through oxygen process and in the center of the pile through anaerobic process. For examination of the easy and ultimate anaerobic biodegradability, the ECETOC screening test is generally employed. This procedure was here improved to evaluate the variability due to the digester sludge. The disappearance of the initial substrate is evaluated by gas chromatography analysis that gives information on the alteration of the base oil chemical structure. The potential for anaerobic biodegradability of an oleic acid ester is compared to an a olefin (C12-C14) and fructose used as a reference substrate. An important biodegradation of the oleic acid ester is observed i.e. more than 80 % of ultimate biodegradation to CO2 and CH4 and total primary biodegradability with no accumulation of the corresponding fatty acids. This attests the easy anaerobic biodegradability of the oleic acid ester In the same conditions, the test performed with the a olefin presents a low pressure evolution and low CH4 production confirming the poor anaerobic biodegradability of this type of compounds.

P. 799
Flow Behavior of Foam as a Well Circulating Fluid
Authors: Beyer A.H. , Millhone R.S. , Foote R.W.
Published: December 2007

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

Equations for steady-state flow of aqueous foam in circular pipes were formulated from laboratory and pilot-scale experimental data. pilot-scale experimental data. These equations were incorporated into a mathematical model of foam circulation in oil wells. The model was tested in two oil wells, and predictions were satisfactory for predictions were satisfactory for engineering calculations. Accuracy of the model may be increased further by accounting for liquid holdup during foam circulation in large-diameter wells.

Introduction

Aqueous foams have proven effective and economic as circulating fluids in well cleanout and drilling operations, and are becoming increasingly important for a wide range of oil field work. Information on the flow behavior of foam in oil wells is important for designing and conducting these foam operations.

Previous work on foam rheology by David and Marsden pertained to capillary tubes only, and validity of results in oil field-size systems is not known. Mitchell measured flow characteristics of foam in tubes up to 0.1 inch in diameter. Results were used by Krug and Mitchell to develop a calculation method for circulation of foam in oil wells, but no field-scale experiments were reported to demonstrate accuracy of their predictions Work published by Wenzel et al. was for larger pipe sizes, but the foam was drier pipe sizes, but the foam was drier than that normally used in oil field applications.

The foam flow equations presented herein have been tested in field-scale systems. These equations should improve the industry's ability to design and conduct oil field foam operations.
Application Of Integrated Reservoir Simulation And Pipeline Network Modeling Software To The Sexsmith Gas-Condensate Field
Authors: Mogensen A.C. , Caswell G.R. , Trick M.D.
Published: December 2007

Over-simplification of the hydraulic component of the field production gathering network can often introduce serious errors in the reservoir simulation forecast. One principal problem involves determining the number of wells required to achieve a desired production target rate. Neither the engineer nor the automated drilling queue logic in the reservoir simulator can easily determine the effects of increased surface backpressure on existing wells caused by the connection of new wells to the surface gathering network.

The integrated simulation of the reservoirs and pipeline gathering network connecting wells to the 200 MMscfd (5635 E03 m3/d) Sexsmith, Alberta sour gas processing plant demonstrates an approach taken to provide answers to problems typical of gas production operations. The paper reviews alternate approaches pursued prior to committing to the integration of a reservoir simulator and a pipeline network model. A review of the history matching procedures conducted to "tune" the linked models to match historical production rates and pressure losses in the network are presented. Information which is "passed" between models is presented as well as suggested software improvements to the integration of the reservoir and pipeline network models.

P. 291
New Insight into Failure of Resin-Coated Proppant Consolidation
Authors: Dewprashad Brahmadeo , Nguyen Philip D. , Weaver Jimmie D. , Wardall Tom , Black Kathy
Published: December 2007

Operators use curable (precoated or on-the-fly coated) resin- coated proppants (RCPs) for controlling proppant flowback after hydraulic-fracturing treatments and in screenless, fracpack completions. A very important but much ignored consideration when choosing an RCP for a particular treatment is the cure kinetics of the proppant. This paper presents the results of a study to compare the consolidation performances of RCPs with different cure kinetics under simulated treatment and downhole conditions of extended pump times and delayed or insufficient fracture closures throughout packs. Techniques developed for determining RCPs' cure kinetics are described. These techniques include differential scanning calorimetry (DSC), rock-mechanical measurements, and scanning electron microscopy (SEM). The cure kinetics of different RCPs are related to their consolidation strengths and photomicrographs obtained of these proppants after they are subjected to conditions simulating different times before onsets of closures at bottomhole temperatures (BHTs).

SEM micrographs showed that in the faster-curing RCPs, there was a dramatic decrease in the numbers and areas of contact points between proppant grains. These micrographs correlate well with the losses of consolidation strengths determined when faster-curing RCPs were exposed to fluids at temperature for various times before onsets of closures. For consolidations simulating wells with high BHTs, the losses of consolidation strengths were more severe, and the numbers and areas of contact points decreased.

This study provides dramatic new answers as to why many RCP consolidations might have failed in the field. Operators can use the information presented to help themselves select the best RCPs for their applications. The information presented is particularly useful for selecting the RCP to be used in screenless completions where consolidations are expected to withstand production conditions of high flow rates and stress cycling. This study improves understanding of the failure mechanisms of RCPs and provides guidelines for proper design and candidate selection for proppant-flowback control and for screenless completions.

P. 347
Reservoir Engineering Analysis of Pincher Creek Gas Field Performance
Authors: Ambastha A.K. , Chornet M. , Beliveau D.A.
Published: December 2007

Pincher Creek gas field, located in south-western region of Alberta, was discovered in 1947 by Canadian Gulf Oil. Pincher Creek gas field is a low-permeability, naturally- fractured, carbonate reservoir. Production from this field started in Jan. 1957. A total of 27 wells have been drilled in this field. However, only six wells are still producing from this reservoir. Many wells in this field have experienced shortened producing life because of water-related problems.

Initial gas-in-place and remaining reserves are reported as 46.8 and 1.5 BCM, respectively, in Alberta Energy and Utilities Board (AEUB) 1994 publication of reserves. Cumulative gas production to the end of Dec. 1996 has been 14.5 BCM. Thus, Pincher Creek gas field seems to have a very low recovery factor. Forty years of production data have been analyzed using conventional material balance, decline curve analysis, and communicating reservoir model to verify initial gas-in- place and reserve estimates for the Pincher Creek gas field. These analyses have led to definitive and consistent initial gas- in-place and reserve estimates for this field.

Efforts have also been made to understand water production mechanisms in this field. Analysis shows that water production behavior in this field is neither related to permeability distribution from core analysis nor to the distance from the bottom of perforation to gas-water contact. Diagnostic plots of the Cartesian derivative of water-gas ratio versus time have shown promise in identifying water production mechanisms for the wells in this field.

P. 367
Development and Application of Kinetic Hydrate Inhibitors in the North Sea
Authors: Phillips N.J. , Grainger M.
Published: December 2007

Low dose kinetic hydrate inhibitors, developed as an alternative to thermodynamic inhibition of gas hydrates, are a branch of specialty treatment chemicals that is still considered "novel". Such inhibitors have only been a commercially viable alternative to hydrate prevention treatment in the last three years. During and subsequent to this kinetic inhibitors have been deployed and developed successfully for both mature assets and new developments in the North Sea. The kinetic inhibitors developed are termed Kinetic Hydrate Inhibitors, or KHI. Currently a KHI is being successfully deployed in the Hyde West Sole system in the Southern North Sea, and in May of 1998 the Eastern Trough Area Project (ETAP) will start up operations and will use KHI from day one of production.

Much has been learned from the development and introduction of KHI products with careful consideration being given to any potential effect that will compromise, not only the production operations, but also the efficacy of any additional additives. Experience has shown that each system must be treated as an individual and the inhibitor tailor made to suit. Here water chemistry, gas composition, temperature, and application all play a major role in the decision process. The use and application of this information, enabling the selection of the most appropriate material can be termed as a complete systems approach. This paper highlights the rationale behind this approach and elaborates on the aspects associated with the deployment of KHI, that experience has shown to be major limiting factors.

P. 397
Permeability Reduction by Treatment with KUSP1 Biopolymer Systems
Authors: McCool C.S. , Shaw A.J. , Singh A. , Bhattacharya S. , Green D.W. , Willhite G.P.
Published: December 2007

The application of KUSPl biopolymer for use in permeability reduction treatments of oil reservoirs was investigated. KUSPl is a non-toxic polysaccharide that is produced by a bacterium. Alkaline solutions of KUSPl have low viscosities and can be gelled by different methods. Three methods were examined to gel KUSPl in porous media. Two of the methods are based on the reduction of pH of alkaline KUSPl solutions. KUSPl is soluble in alkali but forms a gel when the pH is lowered to values below 10.8.

The first method employed the hydrolysis of an ester to reduce pH and trigger gelation. Gel times on the order of days were observed for KUSPl solutions that contained the monoethylphthalate (MEP) ester. The performance of the KUSP1-MEP system in treatments of sandpacks, Berea cores and carbonate field plugs was studied at 25 C. Brine permeabilities were reduced by factors that ranged from 75 to 4500. Permeability reduction by treatments with the KUSPl MEP system was stable to brine flow for periods of up to six months.

The second method to gel alkaline KUSP1 solutions was based on the chemical interactions with rock material. It was found that interactions with Berea sandstone, Baker dolomite, silica sandpacks and field core plugs were insufficient to reduce the pH of alkaline KUSPl solutions to values required for gelation.

Alkaline KUSPl solutions were gelled by the addition of boric acid in the third method. Bulk gelation studies conducted at 25, 45 and 65 C showed that gel times could be regulated up to several days by selection of pH and boric acid concentrations. The gels were more rigid than those produced by pH-reduction methods, indicating a different gelation mechanism. Syneresis was observed and was more pronounced at lower pH values and higher temperatures. The KUSP1-boric acid system reduced brine permeabilities in sandpacks and Berea cores (25, 45 C) by factors that ranged from 50 to 3300.

P. 493
California Gas - Quo Vadis?
Authors: Lippitt Henry F.
Published: December 2007

The supply of oil well gas has dropped sharply in southern California, and the supply of dry gas is barely holding its own in northern California—in the face of an unprecedented national shortage. Why this dismal picture? What, if anything, are the gas distributors, Los Angeles City Council, the Public Utilities Commission, Supervisor of Oil and Gas, the State Lands Commission, or the Secretary of the Interior doing to help?

Natural Gas Supply

(a) Average Daily Supply

Although the first supplies of out-of-state gas did not arrive in California until 1947 (Southern California) and 1949 (Northern California), and the first supplies of Canadian gas did not arrive until 1961 (Northern California), out-of-state and Canadian gas supplies account for over 75% of the State's gas consumption. Today, only about 20% of the State's supply comes from California produced gas sources: about 25% in Northern California, and only about 16% in Southern California.

Southern California (1971)* Approximate % Of Sources of Supply (Bcf) Mcf/Day Total

California Gas Regular Purchases 133,810 366,600 11.9% Exchange Gas 33,056 90,600 2.9 Federal Offshore 15,545 42,600 1.4 Total California 182,411 499,800 16.2%

PG and E Purchases 58,780 161,000 5.2% El Paso 608,830 1,668,000 54.2 Transwestern 273,798 750,100 24.4 Total 1,123,819 3,078,900 100.0%

Northern California (1971) Approximate % Of Sources of Supply (Bcf) Mcf/Day Total

California 258,064 707,000 25.5% PGT (Canada) 341,287 935,000 33.7 El Paso 414,231 1,134,900 40.8 Total 1,013,582 2,776,900 100.0%

(b) Type of Supply

Generally speaking, the available supplies of California produced gas may be divided into two categories:
The Effects Of Various Reservoir And Well Parameters On Water Coning Performance
Authors: Byrne William B. , Morse Richard A.
Published: December 2007

1973 Third Symposium on Numerical Simulation of Reservoir Performance Houston, Texas January 11–12, 1973

Most research on water coning has been directed toward minimizing water production by reduced well penetration or production rate control. However, complete depletion of an oil column underlain by water will necessarily be accompanies by considerable water production, at least in the latter stages of depletion. By means of numerical simulation a systematic study was made of the effects of reservoir and well parameters on water coning performance. Included were the effects of aquifer thickness, well penetration, pressure drawdown, and horizontal to vertical permeability ratio. permeability ratio. These studies revealed that higher water-oil ratios, at every stage of depletion, resulted from increasing well penetration or increasing pressure drawdown at the producing well. Accompanying the increase in pressure drawdown at the producing well. Accompanying the increase in water-oil ratio is an increase in oil production rate of the same magnitude thus decreasing the operating life of the well. There is no indication that the ultimate oil recovery is adversely affected by increased production rates. As a matter of fact it appears that high production production rates. As a matter of fact it appears that high production rates could lead to improved economic oil recovery. Produced water-oil ratio at every stage of depletion is strongly influenced by the ratio of horizontal to vertical permeability and to a lesser degree by aquifer thickness.

Introduction

Water coning, during which bottom water gradually or abruptly breaks into an oil- or gas-producing well, has long been a problem in oil fields. It is a very complex problem and has been investigated by many researchers.
A System for Formation Evaluation Under North Sea Conditions
Authors: Stewart D.I. , Fordham P.A. , Kisling J.W. , Nutter B.P.
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.

A new test system for floating vessels uses annulus pressure control to operate down-hole valves. A nitrogen-charged test valve senses the change in annulus pressure to provide positive well control at all times. A correction system is included to provide reliable operations over a wide range of pressures and temperatures. A sampling chamber is available with a complete set of accessory tools for safe testing. The results of field testing are included.

Introduction

A drill stem testing system for floating vessels has been introduced in the rough conditions of the North Sea and has given satisfactory results in this environment. The system uses a Pressure controlled Test Valve known as Pressure controlled Test Valve known as the PCT valve. When pressure is applied to the annulus (in excess of the hydrostatic pressure), the test valve opens. The valve recloses when the pressure is released. This allows the operator to conduct a test with the minimum of pipe manipulation. This avoids the problems of trying to position down-hole tools accurately while the vessel is moving up and down due to wave action. The system includes a complete line of accessory equipment to provide positive well control through redundancy of all valve functions, to ensure that the reservoir can be adequately tested in complete safety.

EQUIPMENT AND OPERATION

Tool System

The heart of the system is the Pressure controlled test (PCT) valve. Pressure controlled test (PCT) valve.
From Theory to Practice: Evaluation of the Stress Distribution for Wellbore Stability Analysis in an Overthrust Regime by Computational Modelling and Field Calibration
Authors: Last N.C. , Harkness R.M. , Plumb R.A.
Published: December 2007

Faced with significant operational problems, this paper describes how a novel application of computational mechanics was used to help to evaluate and gain insight into the stress distribution in the drilled rock volume above the Cusiana Field in the geologically complex foothills of the Eastern Cordillera of the Andes, Colombia, South America. This has contributed to improved understanding of the causal effects of poor hole condition and drilling difficulties, and provided the basis for the development of a mud weight planning tool. Improved drilling performance has lead to savings of millions of dollars.

P. 49
Two-Phase Flow Simulation of Mud Pressure Penetration
Authors: Naseby D. , Yang Z. , Rahman S. , Tan Chee
Published: December 2007

One of the key time-dependant mechanisms for wellbore failure in shales is the penetration of drilling mud into the formation. Previous studies attempted to predict mud pressure penetration into shales using single-phase flow approach. This can lead to some errors because it ignores the two-phase flow and capillary effects. In this study, a numerical model has been used to study fluid flow in shales. For modeling of two-phase flow, relative permeability curve was calculated using modified Corey's method, which is based on pore size distribution. The pore size distribution of shales was quantified by using mercury injection tests. It has been observed that the two-phase flow model can predict mud pressure penetration reasonably well when the permeability of shales is relatively high (k is greater than 500 nD). This approach has an application for the prediction of mud pressure penetration in shales with drilling induced or natural fractures, which may significantly enhance shale's permeability. It was also found that the two-phase fluid flow model, even possibly Darcy's law in general, may be inadequate when shale's permeability is low and the pressure differential is high. Possible explanations are that shales have a complex structure, with different types of water present, and predominant surface interactions, which may change shales' permeability significantly, thus making Darcy's law inadequate. Future work is recommended for investigations into fundamental laws governing fluid flow in shales in order to improve the prediction of time-dependent wellbore instability in shales.

P. 115
Does the Seasoning Procedure Lead to Intrinsic Properties?
Authors: Bouteca M.J. , Bary D. , Fourmaintraux D.
Published: December 2007

In laboratory experiments, an evolution of the measured rock properties is often observed when the core undergoes cyclic solicitations. There is still a debate in order to define which value should be chosen, and basically the question is to define which value is intrinsic to the rock and which value should be considered as an artifact. Experiments have been performed on a reservoir sandstone and 9 loading cycles have been applied. It is shown that the sandstone behavior can be fully described using Biot's semi-linear poroelasticity. Within this theoretical framework, it is shown that cyclic loading leads to intrinsic values of the rock constitutive law.

P. 321
Characterization of Flow Within Natural Fractures: Numerical Simulations and Field Applications
Authors: Bertuzzi F. , Sanfilippo F. , Brignoli M. , Parravicini G.
Published: December 2007

Natural fractures are commonly encountered in several Oil Industry related activities: one has to think, for example, to mud losses or lost circulation problems when drilling fractured formations. In the same way the characterization of porosity and permeability is one of the most difficult task when dealing with naturally fractured reservoirs. In fact these properties depend on parameters which cannot be known with direct measurements, such as the geometric characteristics of the single fractures, their density, the extension of the networks they form, etc. Moreover, the conductivity of natural fractures depends on the physical mechanisms which govern the flow within them and, during the exploitation of the reservoirs, can diminish due to the increase of the effective stresses which tend to close the fractures.

Recently Eni/Agip has presented a methodology which characterizes the conductivity of the open fractures using real time monitoring of mud loss data while drilling. Starting from this previous work, a detailed characterization of single-phase flow within natural fractures has been performed via numerical simulations and analytical models. In particular, the effect of the geometric properties of the fractures (aperture, tortuosity and roughness) on the flow pattern and on the average conductivity have been investigated. The main results can be summarized as follows;

– validation of the hypothesis of the laminar flow in the description of the flow dynamics in a small fracture; – development of flow patterns characterized by the presence of areas of high permeability that can be seen as network of channels; – correction of the so-called cubic law for hydraulic conductivity through the measure of the fractal dimension of the fracture surface.

Moreover, as it is shown with field examples, the interpretation of mud loss data on the basis of the acquired knowledge allowed to achieve a better evaluation of the near- well conductivity. These facts will provide more reliable and useful information when examining mud losses problems, and consequently the way to solve them, and are of primary importance for the first evaluation of productive intervals and for their selection for testing, completing, etc

P. 337
The Method of Reducing Drilling Costs More Than 50 Percent
Authors: Gjelstad G. , Hareland G. , Nikolaisen K.N. , Bratli R.K.
Published: December 2007

This paper shows how using the Drilling Gptimization Simulator (DROPS) has been applied in the planning phase of two North Sea wells. Both the 12.25" and the 8.5" sections were optimized on Well #1 and the 12.25" section was optimized on Well #2. Geological Drilling Logs (GDLs) were generated from offset drilling data in the same field for both the two wells. Both wells with the different hole sections were simulated with the available bit types and designs. The optimum bit selection and the drilling parameters every meter for the hole-sections were optimized. The hydraulic limitations of the pump and the planned mud weight program were used to optimize the bit hydraulics in conjunction with the bit operating parameters, different pull depths and bit designs. The 12.25" sections showed savings potential of 72.4 percent on Well #1 compared to the last well drilled in the field. This included optimizing bit type, hydraulics, operating parameters and pull depths. Well #2 showed savings potential of 15 percent using oil based mud and 20 percent using water based mud compared to the two other wells drilled previously in the field with oil and water based mud respectively. It was concluded that Well #1 could save $ 1.3 million, while Well #2 was originally drilled close to optimum and only showed a potential savings of $ 0.3 million when using optimum drilling parameters.

The optimization of the 8.5" section was more complex because of several coring intervals. The five full hole sections between the coring intervals were optimized. The five subsections were drilled through formations of different length and lithology. The bit designs, pull depths, number of bits, hydraulics and operating conditions were optimized for each section. In addition to optimization of the drilling parameters, simulations for reuse of bits were conducted to further cut the drilling costs. The cost savings on the 8.5" section for well#1 showed a maximum potential for saving varying from 23.4 to 78.8 percent for the different sections.

From the simulations it can be concluded that the optimum drilling scenario of the 12.25" and 8.5" fitll hole sections for well #1 would reduce the drilling cost with more than $ 4.5 million.

P. 161
Laboratory Investigation of the Improvement in Waterflood Displacement Efficiency by the Addition of Finely Divided Coke Particles to Floodwater
Authors: Raza S.H. , Ertekin Turgay
Published: December 2007

Discussion of this paper is invited. Three copied of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P.O. Box 228, The Hague, the Netherlands. Such discussion may be presented P.O. Box 228, The Hague, the Netherlands. 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.

Laboratory investigation has been made of a novel approach designed to improve the displacement efficiency of a waterflood. This approach consists of injecting a slurry of finely divided solid particles in water, at a linear advance rates of 3 to 20 ft./day, into 4 to 6-darcy unconsolidated sandpacks saturated with oil and water. The solids used in the slurry preparation are oleophilic coke particles and hydrophilic fluorite particles, in concentrations ranging from particles, in concentrations ranging from 0.02 to 1.2 gm/liter. The sand used in the preparation of sandpacks is rendered either preparation of sandpacks is rendered either strongly oil-wet by prolonged contact with oil containing N-octylamine or strongly water-wet by prolonged contact with water containing a water-soluble surfactant, Orvus-K.

The data presented in this paper show that the addition of coke particles to floodwater results in enhanced oil recovery which is associated with lowered water-oil ratio production in both the oil-wet and the water-wet sandpacks. The increment in oil recovery over the conventional waterflood, generally of the order of 2 to 107, P.V., is directly proportional to the P.V., is directly proportional to the initial oil saturation in the sandpack and to the slurry concentration up to a maximum concentration value. In comparison, the addition of fluorite particles to floodwater does not result in enhanced oil recovery from either the oil-wet or the water-wet sandpack.

The enhancement may be explained by the principle of preferential wettability exchange - a principle used in the benefaction of a mineral from its associated waste matter in the froth flotation process of mineral dressing. It is shown that mechanical drag does not play any significant role toward the enhancement of oil recovery.

Introduction

Primary oil recovery from an oil field depends upon the type and magnitude of the expulsive forces, the permeability of the reservoir rock, the viscosity of the reservoir oil, and to some degree upon the field exploitation. These factors vary not only from field to field but may also vary within a field.
Water Quality In The North Sea And Injection Water Standards For North Sea Oil Fields
Authors: St. John D.H. , Barkman J.H.
Published: December 2007

Discussion of this paper is invited. Three copies of any discussion should be sent to the Netherland Section of the Society of Petroleum Engineers, P.O. box 228, The Hague, the Netherlands. 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.

Seawater injection will probably be required to maintain reservoir pressure in most North Sea oilfields. Since there is little published data on North Sea water quality was carried out in the vicinity of the Auk and Brent fields. From these measurements conclusions have been drawn about the filtration and chemical treatment requirements for the seawater that will be injected into the reservoirs of these two fields.

Introduction

Water injection will be needed to maintain initial reservoir pressure in the Auk and Brent fields and will probably be required in most North Sea oil fields. The Auk project will require about 70,000 b/d injection water and each Brent production platform will require about 250,000 b/d. Because of its greater size, the emphasis of the work was directed towards the Brent field. The most convenient source for injection water is North Sea water taken from below the production platforms and in order to design facilities for filtering and treating this water a knowledge of its quality and its effect on the reservoir is needed. At presented there is no published data on the quality of North Sea water with respect to suspended solids, micro-organisms or scaling tendencies. This paper describes the results of a programme of on-site measurements of North Sea water quality which were made in the vicinity of block 211/29, 90 miles northeast of the Shetland Islands. The objectives of the programme were:To determine the type of chemical treatment needed to prevent corrosion, scaling and bacteriological problems.To find the pump intake depth that yields the best quality water.To determine whether the suspended solids level can be substantially reduced by filtration.To estimate the rate of impairment due to suspended solids that would result in the Brent formation from the injection of either filtered or unfiltered seawater.
Parameters Affecting Azimuth and Length of a Secondary Fracture During a Refracture Treatment
Authors: Siebrits E. , Elbel J.L. , Detournay E. , Detournay-Piette C. , Christianson M. , Robinson B.M. , Diyashev I.R.
Published: December 2007

Refracturing in a plane normal to that of the initial fracture can be beneficial in tight gas fields, even when the initial fracture is deeply penetrating and highly conductive. The magnitude of the benefits will depend on the timing and the penetration of the secondary fracture. The Gas Research Institute has sponsored a project that addresses the conditions required for maximum benefit and the validation of the process with a field trial. This paper addresses the theory and conditions required for maximum benefit.

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Effect of Completion Geometry and Phasing on Single-Phase Liquid Flow Behavior in Horizontal Wells
Authors: Yuan Hong , Sarica Cem , Brill James P.
Published: December 2007

Horizontal wells can have very complex flow geometries, in part due to interaction between the main flow stream and the influxes along the wellbore, and also due to completion type.

An experimental facility was used to investigate the effects of completion geometries and the density and phasing of injection openings in horizontal wells. Three test sections with perforation densities of 5, 10 and 20 shots per foot and phasings of 360, 180 and 90 were. Four test sections were used for slotted liners, including one single slot case and three multiple slot cases. The numbers of slots for multiple slot cases were 18, 18 and 36 on 4-ft. long sections with slot phasings of 360, 180 and 90, respectively. A total of 1,257 tests were conducted for no fluid injection, no main flow at the test section inlet, and with fluid injection for Reynolds numbers ranging from 4,000 to 60,000 and for influx to main flow rate ratios ranging from 1/5 to 1/2000.

Experimental results show that completion geometry, phasing and density in addition to Reynolds number and influx to main flow rate ratio have dramatic effects on the pressure behavior and therefore the production behavior of horizontal wells.

A general friction factor expression for horizontal wells with multiple injection openings was developed based on the conservation of mass and momentum. A commercial Computational Fluid Dynamics (CFD) computer program was used to determine the length of the flow developing region in a horizontal well after the flow is disturbed due to radial influx. Applying experimental data and the result of CED simulation to the general friction factor expression resulted in new simple correlations for horizontal well friction factors. Very good agreement was found between the friction factor correlations and experimental data. A field example is presented to show the importance of using a proper friction factor correlation to calculate the pressure drop in a horizontal well.

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Techniques for Solving Torque and Drag Problems in Today's Drilling Environment
Authors: Aston M.S. , Hearn P.J. , McGhee G.
Published: December 2007

Torque and drag minimisation is becoming increasingly important, due to the need to drill more challenging wells and because of tighter legislations restricting the use of highly lubricating oil based and synthetic based drilling fluids. This review compares different mechanical and chemical methods of torque and drag reduction, with reference to field experiences. Results obtained from a new lubricity rig are discussed. These indicate that a wide range of lubricant types can be effective in water based muds. Therefore, lubricant choice needs to be largely based on cost and availability considerations. The rig is found to be suitable for evaluating solid lubricants such as beads, and these are shown to be effective in silicate based fluids.

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Quantitative NMR Interpretation
Authors: Cannon D.E. , Minh C. Cao , Kleinberg R.L.
Published: December 2007

Advancements in nuclear magnetic resonance (NMR) logging have provided important information on formation productivity, pore size and fluid type. This information has been most easily used as a stand-alone NMR interpretation or as overlays of NMR data on other log data. Attempts at using NMR data quantitatively with traditional porosity measurements have been more difficult. The difficulty originates from the need to combine measurements that are insensitive to pore structure and pore fluid with NMR measurements that are sensitive to those formation properties. For example, even in a perfectly clean freshwater sand, an NMR tool may produce a porosity that is different from density and neutron porosity. The differences have been attributed to either the lack of an early-time signal from small pores associated with silt and clay size grains or incomplete fluid polarization. The lack of an early-time signal has been addressed with the latest generation tools; however, incomplete polarization still needs to be addressed.

Polarization would not be a problem if NMR data were acquired with a sufficient wait time to guarantee complete polarization. The penalty for such a guarantee is long acquisition times and increased costs. In addition, accurate knowledge of the formation's T1 is needed to determine the correct wait time. Such knowledge is often not available.

Current NMR tools include an approximate polarization correction based on the measured T2 and an estimate of T1/T2 ratio. A more rigorous method is proposed that replaces the welisite correction with one dependent on the actual volumes the tool is measuring. To do this, the data are reprocessed without a polarization correction. Calculations are made of NMR tool-response parameters for different pore sizes and pore fluids. These calculations are a function of the hydrogen index and T1 of the individual formation components; inputs to the parameter calculations are pressure, temperature, oil viscosity, water salinity and acquisition wait time. The outputs are the tool's response to fine grain, coarse grain and vuggy porosities; gas; oil; and oil-base mud filtrate. The resultant parameters, NMR data and other log data are entered into a simultaneous solver for the final result.

The advantage of this approach is that it allows the polarization correction to be adjusted according to the individual volumes present. it also allows incomplete polarized NMR data acquired at increased logging speeds to be appropriately corrected. Examples using this approach on formations with light hydrocarbon zones and vugs in water-base and oil-base muds are examined. The results for all cases are self-consistent including resistivity measurements, which are also sensitive to pore size and pore fluids, confirming the viability of the technique.

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