bluuebunny/crossref_metadata_2025 huggingface dataset:
A floating storage unit designed specifically for the severest environmental conditions
Authors: Bax J.D. , de Werk K.J.C.
Published: December 2007

This paper was prepared for the SPE-European Spring Meeting 1974 of the Society of Petroleum Engineers of AIME, held in Amsterdam, the Netherlands, May 29–30, 1974. 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 Netherland Section of the Society of Petroleum Engineers, 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.

A description is given of an oil storage facility comprising a combination of a number of vertical cylinders, forming a complete unit. Anchored to the bottom of the sea yet movable to another location if required, the floating unit has been designated a storage spar. The paper deals with the behaviour of the unit in certain sea states and with those parameters which effect motions due to wind, parameters which effect motions due to wind, waves and current. The basic philosophy of the design is discussed. Some attention is also given to the structural aspects of anchoring, tanker mooring and oil handling.

The paper also goes into some detail on the fabrication of the unit, its upending after launching, and its final installation at site.

Introduction

A glance at the map of the North Sea shows the presence of a number of highly interesting oil and gas discoveries many of which are scheduled to come into production very soon. The discovery of these new sources of hydrocarbons, and their location, sparked off a great deal of research and development activity leading eventually to the designing of equipment able to stand up to the severe and hostile environmental conditions peculiar to this northernmost portion of the North Sea. Because of the excessive water depths involved, plus the severe weather conditions, most structures going into this area have to be large and have to be heavy.

And since we are only just on the brink of development, activity is bound to increase considerably into the future. This means that water up to 200 meters deep will have to be contended with.
A Review of Tertiary Recovery in Illinois
Authors: Lawry Thomas F.
Published: December 2007

This paper was prepared for the Second Midwest Oil and Gas Industry Symposium of the Society of Petroleum Engineers of AIME, to be held in Indianapolis, Ind., March 28–29, 1974. 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.

Tertiary recovery work done in Illinois to date has included in situ combustion in two reservoirs containing oil too viscous to waterflood successfully; a few trials of steam in huff-and-puff applications; and an increasing number of small-scale pilot size to semi-field-scale size chemical floods.

The in situ combustion tests have proven that in situ combustion is capable of removing almost all of the oil from a porous reservoir, although as much as one-fourth of the oil may be consumed underground as fuel for the process.

Chemical floods, using sulfonated hydrocarbons either in microemulsions or in aqueous solution, have shown that additional oil can be removed from sandstone reservoirs that have already been subjected to waterflood recovery methods.

Partially hydrolyzed acrylamides have proven to be a very useful adjunct to the proven to be a very useful adjunct to the application of sulfonated hydrocarbons in chemical floods as a means of improving mobility control of injected fluids.

A brief review of two in situ combustion projects and eight chemical floods is given in projects and eight chemical floods is given in this paper. Data are from earlier published papers plus more recent communication with papers plus more recent communication with authorized company representatives.

Introduction

For the purpose of this paper, tertiary recovery is broadly spoken of as any process of oil recovery by chemical or thermal means beyond the secondary recovery methods of waterflooding, air-gas repressuring, or use of vacuum. This paper is a review of all known tertiary paper is a review of all known tertiary recovery projects that have been done in Illinois (Fig. 1).
Future Oilfield Equipment Availability
Authors: Mairs M. Bruce
Published: December 2007

Good afternoon gentlemen. Thank you for this opportunity.

A major oil company the other day published what it called "musings of an oil published what it called "musings of an oil person…" Today, with your permission, I person…" Today, with your permission, I would like to publish some "musings of an oil tool person…"

We find ourselves today at a very curious point in time in our industry. Demand for point in time in our industry. Demand for everything is high. Supplies are low. Production schedules are supertight. Tempers are Production schedules are supertight. Tempers are short. So is oil. Prices are spooky. Congress is nervous, so are businessmen. And the consumer stands watching all this in stark disbelief.

How did we get in this marvelous mess? To answer, we must retreat in time to the 1960's — described by one historian as the Decade of Extremes. Ten years of irony, paradox, gross exaggeration, massive paradox, gross exaggeration, massive miscalculations and contradictions in which we all had the pleasure of participation.

It was the decade of one of the worst Bear markets and the hottest Bull market in Wall Street history. It gave us political and economic extremes, extreme rises in costs, labor contracts, inflation and deficits, extremes on the campuses and on city streets, and even in religion where we witnessed rise of the occult and the Jesus Freaks. The sixties were also called the decade of materialism - when demand for everything sky-rocketed to unprecedented levels. More money chased more goods than at any time in the history of mankind.

Extremes were also felt in our industry. Some of these led us to where we are today - in the midst of tough problems and great opportunities.

The sixties saw the cost of drilling, producing and marketing energy products climb, producing and marketing energy products climb, while government controls held down fair profits. profits. Government policies controlling the price of gas and oil drove American oil companies outside the United States' boundaries in search of cheaper sources of oil.
High Temperature Behavior of Rocks Associated with Geothermal Type Reservoirs
Authors: Somerton W.H. , El-Shaarani A.H. , Mobarak S.M.
Published: December 2007

Measurements of sonic velocities, bulk and matrix compressibilities and thermal conductivities have been made on a group of outcrop sandstones and a group of siltstone cores obtained from wells drilled in the Imperial Valley, California. Results of these measurements, which were made at temperatures as high as 200 °C and pressures to 16,000 psi, are presented and discussed relative to their application in high temperature underground reservoir studies.

Sonic velocities were found to decrease with increased temperature and increase with increased pressure and with liquid saturation. If the effect of temperature on sonic velocities is ignored, overestimation of porosity from transit-time logs could result.

Both bulk and matrix compressibilities were found to increase with increased temperature. Application of these data to surface subsidence calculations showed that although subsidence would be small due to fluid pore pressure reduction in these particular rocks, the effects of temperature on compressibility could increase subsidence substantially.

Thermal conductivities were of the expected order of magnitude for sandstones and siltstones of the type tested. Vaporization-condensation reactions caused a more than two-fold increase in apparent thermal conductivity for the higher permeability sandstones but had essentially no effect on the conductivities of the low permeability siltstones.

From results of the present work it was concluded that the temperature effects observed were of sufficient importance to warrant additional work at higher temperatures and on a wider variety of samples typical of those which might be encountered in high temperature subsurface reservoirs.

INTRODUCTION

In the development of geothermal power, an understanding of the properties and behavior of rocks and rock-fluid systems at high temperatures and pressures may be needed for a variety of applications. These include, among others, the interpretation of well logs, prediction of subsidence upon pore pressure reduction, calculation of reservoir storage capacity, and fluid flow and heat flow calculations. Properties needed for these applications include sonic velocities, bulk and pore compressibilities, thermal conductivity, permeability and electrical resistivity factor. Capillary pressure and relative permeability data measured at subsurface temperature and pressure conditions may also be required in multi-phase fluid and heat flow calculations.
An Examination of Countercurrent Capillary Imbibition Recovery from Single Matrix Blocks and Recovery Predictions by Analytical Matrix/Fracture Transfer Functions
Authors: Cil Murat , Reis John C. , Miller Mark A. , Misra Debasmita
Published: December 2007

Countercurrent capillary imbibition is an important oil recovery mechanism in naturally fractured reservoirs. This paper presents a comprehensive study which examines 8 important characteristics of countercurrent imbibition as observed from experiments conducted with single matrix blocks. These characteristics are (1) types of imbibition and recovery trends, (2) flux and transition time, (3) imbibition front and average saturation, (4) effect of block sizes and shapes, (5) effect of temperature, (6) effect of initial water saturation, (7) reproducibility, and (8) long-term recovery.

Existence of two flow periods during countercurrent imbibition were verified. The transition time between the periods was identified as an excellent factor for scaling core size and temperature effects on countercurrent imbibition recovery. The advancement rate of the imbibition front was confirmed to be proportional to the square root of time for 1 D water imbibition into gas-saturated matrix blocks. Experiments showed that initial water saturations ranging from zero to near 20% had no significant effect on recovery behavior. Long term recovery from gas-saturated matrix blocks reached 100%.

Analytical matrix/fracture transfer functions are often used to predict imbibition recovery. Over 23 such functions have been identified from the literature. In this study, these functions are categorized as:diffusivity functions,scaling relations,empirical functions, andmaterial balance functions.

One critical finding has been that analytical functions can provide alternative solutions when modeling oil recovery from naturally fractured reservoirs. We have shown that better functions can easily be developed by simply following the examples of previous functions. In this regard, three new functions and their variations are presented and verified. The findings in this study should provide a powerful toolbox for reservoir engineers in modeling oil and gas recovery from dual porosity/permeability structures which include naturally fractured reservoirs.

P. 237
A Viscous Coupling Model for Relative Permeabilities in Fractures
Authors: Fourar M. , Lenormand R.
Published: December 2007

Two-phase flow properties are required for modeling fluid flows and pollutant transport through fractured media. Several laboratory experiments have been reported in the literature but so far there is no general model to predict the two-phase conductivity of a fracture for a given pair of flowing fluids. In this paper we propose a simple model based on viscous coupling between two fluids flowing simultaneously in a single fracture. This viscous coupling model leads to simple analytical relationships between the relative permeabilities (Kr) and either saturation or fluid velocities. This model also explains the dependence of the non-wetting fluid Kr on the viscosity ratio. Results obtained with this model were compared to several series of data available in the literature with air and water. The fit between predicted and measured Kr is good when the ratio of flow rates is used as variable (Lockhart-Martinelli parameter). For use in numerical simulations, the saturation can be derived from the flow rates using the same model. The proposed model can improve the relative permeability curves that are used in the numerical simulations.

P. 253
Stochastic Reservoir Simulation Using Neural Networks Trained on Outcrop Data
Authors: Caers Jef , Journel Andre G.
Published: December 2007

Extensive outcrop data or photographs of present day depositions or even simple drawings from expert geologists contain precious structural information about spatial continuity that is beyond the present tools of geostatistics essentially limited to two-point statistics (histograms and covariances). A neural net can be learned to collect multiple point statistics from various training images, these statistics are then used to generate stochastic models conditioned to actual data. In petroleum applications, the methodology developed can be a substitute for objects based-algorithms when facies geometry and reservoir continuity are too complex to be modeled by simple object such as channels. The performance of the neural net approach is illustrated using training images of increasing complexity, and attempts at explaining that performance is provided in each case. The neural net builds local probability distributions for the facies types (categorical case) or for petrophysical properties (continuous case). These local probabilities include multiple point statistics learned from training images and are sampled with a Metropolis-Hastings sampler which also ensures reproduction of statistics coming from the actual subsurface data such as locally varying facies proportions.

P. 321
An Integrated Approach to Project Management, Wainwright West Project
Authors: Zaver Mohamud
Published: December 2007

A fast tracking, integrated approach to project management was utilized to develop a new pool at Wainwright West, located 200 km east of Edmonton, Alberta, Canada. An integrated multi-disciplinary project team of about 20 people composed of geosciences, development, land, drilling, completions, production, facilities and marketing, managed by a project manager was formed. This integrated, fast tracking approach resulted in production on-stream two months ahead of the original schedule and 10% below costs. Successes, enhancements and improvements were realized in every area, which were captured at a lookback session and implemented for the next phase of the project.
How We Can Be More Efficient with Our Drilling Hydraulics
Authors: Sutko A.A. , Sifferman Thomas R. , Harden Elard L. , Wahl Harry A.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Present-day drilling hydraulics can be made more efficient. The methods discussed in this paper result in lower cost and better use of hydraulic energy. These findings are based on using two nozzles instead of three and, in some cases, lowering the annular velocity. New data is also presented on borehole wall erosion and on better hole bottom cleaning with extended nozzles, especially when the nozzle angle is increased.

Introduction

Hydraulics has long been recognized as an important factor in drilling but, because of the complexity of the system, it has received limited detailed study. Early drilling optimization programs assumed that the drilling hydraulics was adequate. In more recent programs, procedures have been developed for determining procedures have been developed for determining optimum drilling fluid properties, velocities, etc. However, the basic information on what occurs beneath the bit and in the annulus was not available. Recent publications on bit hydraulics and drill cutting transport provide new insight into drilling hydraulics. provide new insight into drilling hydraulics. This paper shows how to apply this information to improve your hydraulic efficiency. Procedures are given that can save time and money Procedures are given that can save time and money by increasing penetration rates and decreasing hole problems. In addition, the more effective application of hydraulic energy can improve drilling operation while reducing fuel requirements.

EXPERIMENTAL

Bit Hydraulics

The bit hydraulics results discussed in this paper are based primarily on laboratory testing with 6 1/2-inch bits. The flow system was composed of a pump, drill pipe, bit, simulated hole bottom, and annulus.

For the pressure distribution tests, a contoured plate with seven taps located along a radius provided the bottom-of-the-hole pressures, and a row of seven taps equally spaced at 1/2-inch intervals gave the pressures up the side of the hole. The pressure at each of the points was measured with respect to the pressure points was measured with respect to the pressure at a point farther downstream in the annulus.
A New Cementing Material for Deep Hot Holes
Authors: Fincher Arnold , Goode John M.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

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

This paper describes a new cementing composition which is designed to have both low fluid density and long thickening time characteristics at elevated temperatures.

The advantages of using such a slurry are demonstrated when weak zones are encountered in cementing long strings in deep holes; when it is desired to circulate cement to the surface or bring it up the annulus a considerable distances since the reduction in slurry density allows a longer cement column to be tolerated without having formation breakdown.

Laboratory data is presented demonstrating that the slurry has good compressive strength over a wide temperature range, can be retarded easily at high temperatures, has good flow characteristics and does not exhibit severe strength retrogression at high temperatures.

Case histories of jobs, where the composition has been used, are given with the results of the jobs.

Introduction

With the drilling of deeper wells, problems in cementing have become more and more complex. Higher bottom hole pressures have been encountered requiring heavier muds to control high pressure formations. Where weak formations exist up the hole, these heavy muds tend to break down these zones causing severe lost circulation problems. In order to protect these weak zones, problems. In order to protect these weak zones, the practice of setting intermediate strings of casing has been employed by several operators in southern United States. Many of these long strings are set in 10,000 to 13,000 feet of open hole below 2500 to 5000 feet of surface pipe. These strings of casing are usually cemented to the surface. This procedure often results in the problem of formation breakdown due to the long columns of cement utilized.

In many wells, severe corrosion zones exist above the production zones. In order to protect the casing from corrosion, the practice of employing long cement columns to cover these zones has been utilized. Here again, potential formation breakdown is a problem.

What was needed was a cementing composition of low density, but could withstand the high temperatures encountered in deep well cementing.
Improving Wellbore Position Accuracy of Horizontal Wells by Using A Continuous Inclination Measurement From A Near Bit Inclination MWD Sensor
Authors: Berger P. E. , Sele R.
Published: December 2007

Wellbore position calculations are typically performed by measuring Azimuth and Inclination at 10–30 meter intervals and using interpolation techniques to determine the borehole position between the survey stations. Input parameters are, Measured Depth (MD), Azimuth and Inclination, where the latter two parameters are measured with the MWD tool in a stationary mode (non-rotating). Output parameters are the geometric coordinates; True Vertical Depth (TVD), North and East. To maximize the exposure of a production well to the reservoir, horizontal wellbores are frequently being drilled. Furthermore, to maximize the production of hydrocarbons from these wells, their relative position within the reservoir is critical. Improving the accuracy of the Inclination measurement and thus reducing the uncertainty of the calculated TVD value will increase the confidence in wellbore position.

The NaviGator™* geosteering tool or the AutoTrak™* rotary steerable system are frequently used to optimize the position of horizontal wellbores within the reservoir. Both these geosteering tools use a Near Bit Inclination sensor (NBI) to help the directional driller perform directional changes smoothly and accurately. Unlike traditional directional sensors the NBI sensor is capable of accurately measuring inclination while being rotated. Consequently NBI measurements can be performed continuously during drilling. The measurements can be used to more accurately calculate the wellbore trajectory.

Results in the paper demonstrate that the NBI sensor is more accurately measuring inclination than other directional sensors in a horizontal well. Also, by continuously measuring the inclination during rotation, some error sources are reduced, resulting in improved TVD accuracy.
Optimising Inflow Performance of a Long Multi-Lateral Offshore Well in Low Permeability, Gas Bearing Sandstone: K14-FB 102 Case Study
Authors: Hands Nick , Francis Paul , Whittle Antony , Rajasingam Donal
Published: December 2007

Development well K14-FB 102 was completed as a dual lateral in 1997 to optimise production capacity and reservoir drainage from a tight, Rotliegend sandstone in an offshore gas play in the Dutch sector of the North Sea. The two 5 7/8" horizontal production intervals were drilled and completed openhole using a rheologically engineered, minimal solids, non-damaging sodium formate brine based fluid designed as a drill-in fluid for reservoir intervals. The system was designed around the Low-Shear-Rate-Viscosity (LSRV) which is critical not only for hole cleaning and drilling performance, but also for minimizing filtrate invasion and potential formation damage by using minimal solids. The formate system exhibited superior hole cleaning qualities during the entire interval and no significant drag was observed during drilling. No pills were pumped prior to pulling out of hole and tripping proceeded without problems, verifying excellent hole condition. As a result of high ROP's, a 35% reduction in total reservoir drilling time was achieved. The resulting production capacity was 40% above expectation and a nearzero mechanical skin indicated that the reservoir interval had been completed with minimal residual drilling induced damage. The formate system, with its unique rheological profile, differs from other water-based fluids, and provided advantages not only for drilling technique but also enhanced HSE criteria.
A New Method for Fast and Economical Connection of Large-Diameter Pipe
Authors: Drouin Andre H.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

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

This paper reviews the history of the design, testing, and field usage of a means of pipe connection that eliminates long and costly field welding of large diameter pipes. Originally developed for connecting drive pipe joints used on jackup drilling rigs, it proved its economy over welding: connections that required three or more hours welding time can be made in a matter of a few minutes. The original connectors first used in the field are still in service after six years having been used repeatedly on a number of wells.

The high logistic costs associated with offshore construction in deeper water where larger pilings are required makes the long welding time on location unbearably expensive. Also, the long stops required for welding make it extremely difficult to restart the pile moving, sometimes requiring jetting or drilling a relief hole, causing even higher cost. This connector cuts this time to a small fraction of that required for welding.

Introduction

Historically, lengths of pipe have been joined together in a variety of manners; the oldest being the bell and spigot joint which is still widely used today. Lengths of pipe are also joined together by threaded collars, integral male and female threads, couplings, flanges, by welding, etc..
Targeted Steam Injection Using Horizontal Wells with Limited Entry Perforations
Authors: Boone Thomas J. , Youck Daryl G. , Sun Sam
Published: December 2007

Limited-entry perforations have been used in vertical wells in both California and at Imperial's Cold Lake field as a method for distributing steam to different zones. The technology relies simply upon designing the number, size and placement of the perforations so that critical or choked flow occurs across the perforations during steam injection, and steam exits the well with the desired distribution. This paper describes an experimental horizontal well where this same technology was used to replace ten vertical injection wells with a single horizontal well. The well was located between rows of vertical wells in reservoir that had been subjected to more than ten years of operations under cyclic steam stimulation. The limited-entry perforations enabled steam to be targeted at the cold regions of the reservoir. A more typical completion such as a screened or slotted liner would not have provided any control over the placement of steam in the reservoir. The 1000 m long liner was cemented in place with a completion design consisting of only 28, 3/8 inch diameter perforations which were drilled through the casing and cement. The design injection rate for the well was 2000 to 3000 m3/day of 70% quality steam. This paper presents an assessment of the performance of the well based on theoretical calculations, measured injection pressures and rates, and 3D seismic imaging.
New Viscosifier for Water Based Muds Based on a Genetically Modified Starch
Authors: Ward I. , Chapman J. W. , Williamson R.
Published: December 2007

A new viscosifier based on genetically modified starch has been developed and field proven. The product, when used in combination with low levels of pre-hydrated bentonite produces drilling fluids with exceptional shear thinning characteristics. Furthermore it has been found that the product, when incorporated at the optimum level for rheology control, also acts as an effective fluid loss control agent. This overcomes the need for separate fluid loss control agents such as polyanionic cellulose or carboxymethyl cellulose. This "one pack" viscosifier and fluid loss reducer offers a commercially viable alternative to conventional systems1.

This paper details the extensive laboratory testing programme required for the development of this product. Formulations based on brines and seawater, including the highly inhibitive silicate based fluid2, are illustrated. The performance of this new fluid is compared with conventional formulations containing xanthan gum and PAC. Data from the early field trials are included.
Correlation of Bubblepoint Pressures for Reservoir Oils--A Comparative Study
Authors: McCain W.D. , Soto R.B. , Valko P.P. , Blasingame T.A.
Published: December 2007

W.D. McCain Jr., R. B. Soto, P.P. Valko, and T. A. Blasingame

None of the currently proposed correlations for bubblepoint pressure are particularly accurate.

Knowledge of bubblepoint pressure is one of the important factors in the primary and subsequent developments of an oil field. Bubblepoint pressure is required for material balance calculations, analysis of well performance, reservoir simulation, and production engineering calculations.

In addition, bubblepoint pressure is an ingredient, either directly or indirectly, in every oil property correlation. Thus an error in bubblepoint pressure will cause errors in estimates of all oil properties. These will propagate additional errors throughout all reservoir and production engineering calculations.

Bubblepoint pressure correlations use data which are typically available in the field; initial producing gas-oil ratio, separator gas specific gravity, stock-tank oil gravity, and reservoir temperature. The lack of accuracy of current bubblepoint pressure correlations seems to be due to an inadequate description of the process - in short, one or more relevant variables are missing in these correlations.

We considered three independent means for developing bubblepoint pressure correlations. These are (1) non-linear regression of a model (traditional approach), (2) neural nelwork models, and (3) non-parametric regression (a statistical approach which constructs the functional relationship between dependent and independent variables, without bias towards a particular model).

The results, using a variety of techniques (and models), establish a clear bound on the accuracy of bubblepoint pressure correlations. Thus, we have a validation of error bounds on bubblepoint pressure correlations.

P. 267
Morrow-Springer Pressures of the Anadarko Basin
Authors: Davis Herbert G. , Nondorf James L.
Published: December 2007

The Morrow-Springer pressures in the Anadarko Basin have become a major factor in the exploration and exploitation of the Basin's major pre-Permian gas reserve. The tectonics affecting the Morrow-Springer formations during and after deposition of the sediments may be partly responsible for the abnormally low and high pressures in their respective areas. Isopach maps of the Morrow-Spriinger indicate the major divisions of pressure gradient in the formations. BHP gradient maps can be interpreted in areas where control is available with knowledge of the thickness of unit to be penetrated and the amount of reservoir rock anticipated. To date 5000 to 6000 feet of Morrow-Springer has been penetrated in the 'deep' basin. BHP's to 10,000 psi can be predicted however extensive geophysical and geological research are required to resolve the complex south flank of the Anadarko Basin with greater BHP's.

INTRODUCTION

The Morrow-Springer pressures in the Anadarko Basin have become a major factor in the exploration and exploitation of the Basin's major pre-Permian gas reserve.

In the fifties and early sixties little was known of the pressure system of these formations and exploration had reached 'boom' proportion as the drillbit continued to discover gas in the Lower Pennsylvanian.

Figure I illustrates the Anadarko Basin in its tectonic location, bounded on the south by the buried Amarillo-Wichita Mountains; on the west by the Sierra Grande Uplift; on the northwest by a minor arch in Pennsylvanian time, the Las Animas Arch, which we like to use as the separation between the Anadarko Basin and the Denver Basin; on the north by the Central Kansas Uplift; and on the northeast by the Nemaha Range.
Rigorous Treatment of Distorted Grids in 3D
Authors: Young Larry C.
Published: December 2007

This paper was prepared for presentation at the 1999 SPE Reservoir Simulation Symposium held in Houston, Texas, 14-17 February 1999.
Environmental and Safety Regulations in Sour Gas and Crude Operations
Authors: Ehrhardt C.D.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Because of the harmful effects of hydrogen sulfide, drilling and producing operations involving sour gas and crude are subject to special regulations. These vary from state to state. Environmental regulations which control sulfur recovery plant operations are especially severe. plant operations are especially severe. Regulations applicable to the states bordering the Gulf of Mexico and to the Gulf are discussed. Technical, professional and management people involved in such operations must be familiar with the hazards and with the regulations.

Introduction

The dangers of hydrogen sulfide to humans, the environment, and to equipment have long been recognized. It is toxic, flammable, explosive and corrosive. Studies by the Bureau of Mines and the Texas Medical Association of the hazards of sour gas date back into the 1920's. In the earlier days of sour gas and oil operations, operators depended upon selfregulation. Gradually, health and Industry associations provided guidance which made for safer operations. More recently, many regulations have been adopted by various governmental agencies to require all stages of sour operations to conform to safety and environmental standards.

This presentation is not intended to be a complete and finer reference on all of the applicable regulations, since the regulations are too lengthy, complex and changing; rather, it is intended to give an overall view of this aspect of regulation, and to permit a quick review of the regulations in permit a quick review of the regulations in effect in different areas. Regulations in the states bordering the Gulf of Mexico and the Gulf will be discussed.

HARMFUL QUANTITIES AND DEFINITIONS

The concentration of hydrogen sulfide which constitutes a harmful quantity depends upon the subject being considered, whether humans, the environment or equipment, and upon the body or agency setting the standard.
A New Approach for Modeling Horizontal Well Singularities in Petroleum Engineering
Authors: Guevara-Jordan J. M. , Fermín A. K. , González R. J.
Published: December 2007

We propose a new methodology to evaluate the transient pressure distribution of horizontal wells with any curvilinear trajectory in isotropic/anisotropic reservoirs of arbitrary shape. This is based on the mathematical representation of the tortuous horizontal wellbore using a generalized function. A novel method for removing the singularities involved in the generalized function allows the reduction of the original problem to the standard solution of the homogeneous diffusivity equation with reformed initial condition and boundary values. This new approach combines the Green function method and any standard numerical technique in a single computational strategy to obtain the transient pressure response generated by a curved/twisted horizontal well in oil reservoirs with irregular frontiers.
Stochastic Formulation for Uncertainty Assessment of Two-Phase Flow in Heterogeneous Reservoirs
Authors: Dongxiao Zhang , Liyong Li , Tchelepi Hamdi A.
Published: December 2007

In this paper we use a direct approach to quantify the uncertainty in flow performance predictions due to uncertainty in the reservoir description. We solve moment equations derived from a stochastic mathematical statement of immiscible nonlinear two-phase flow in heterogeneous reservoirs. Our stochastic approach is quite different from the Monte Carlo approach. In the Monte Carlo approach, the prediction uncertainty is obtained through a statistical post-processing of flow simulations, one for each of a large number of equiprobable realizations of the reservoir description.

We treat porosity and permeability as random space functions. In turn, saturation and flow velocity are random fields. We operate in a Lagrangian framework to deal with the transport problem. That is, we transform to a coordinate system attached to streamlines (time, travel time, and transverse displacements). We retain the normal Eulerian (space and time) framework for the total velocity, which we take to be dominated by the heterogeneity of the reservoir. We derive and solve expressions for the first (mean) and second (variance) moments of the quantities of interest.

We demonstrate the applicability of our approach to complex flow geometry. Closed outer boundaries and converging/diverging flows due to the presence of sources/sinks require special mathematical and numerical treatments. General expressions for the moments of total velocity, travel time, transverse displacement, water saturation, production rate, and cumulative recovery are presented and analyzed. A detailed comparison of the moment solution approach with high-resolution Monte Carlo simulations for a variety of two-dimensional problems is presented. We also discuss the advantages and limits of applicability of the moment equation approach relative to the Monte Carlo approach.
Internal Tubular Plastic Coatings for Sour Gas and Crude Service
Authors: Voyles Jack L.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Baked phenol-formaldehyde formulations, commonly referred to as baked phenolics, have had varying degrees of success in H2S environments. The degree of success for a given baked phenolic used as an internal tubular coaling depends upon H2S concentration, pressure, and temperature of the environment. Laboratory tests of baked phenolic coatings indicate 5% H2S, 2,000 psi, and 200 degrees F to be the upper limits for satisfactory performance. Case histories have proven certain individual formulations are capable of performing satisfactorily above these limits.

Introduction

Coating material formulations for H2S environments of high pressure and temperature are achieved by combining inert fillers with thermosetting phenolic resins. The type and amount of filler used in baked phenolic coating materials influence the temperature limit, acid resistance, flexibility, permeability and gas diffusion rate. A baked phenolic coating well balanced in the preceding five points will perform well in continuous service points will perform well in continuous service above the limits of most manufacturer recommendations. Extensive laboratory and field tests are necessary to determine the performance capability of a baked phenolic coating in an H2S environment.

REQUIREMENTS IN COATING APPLICATION

Proper application is essential to produce a satisfactory coating performance in service The following are necessary steps to achieve proper coating application. proper coating application.Adequate metal cleaning for internal tubular coating requires flint blasting to an SSPC-SP-5 (white metal finish).An anchor pattern (1 1/2 to 2 mils)is required to obtain a satisfactory bond of coating material to the steelsubstrate.A uniform coating film well balanced in adhesion and cohesion produces a product that will not delaminate or lose bond with the steel substrate.
Sulfur Recovery from Sour Natural Gas: A Review of Gas Treating/Claus Plant Design and Operations
Authors: Goar B. Gene
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

The decision to build a sour natural gas treating facility for the purpose of sweetening the gas and recovery of elemental sulfur involves many considerations, and usually represents a significant investment. Selection of the optimum gas treating process and sulfur recovery scheme may to a process and sulfur recovery scheme may to a complex problem. Many well established criteria are important to consider during the design phase of such a project. Subsequent operation of these facilities requires a good knowledge of potential problem areas.

This paper is a general review of the main factors that should be considered in the selection, design, and operation of a gas treating/sulfur recovery facility.

Introduction

Today we are facing a serious energy crisis in this country. All available natural gas reserves will be needed in the future. Some operating companies are reluctant to produce sour gas wells today, because of the high cost of treating the gas to remove H2S and other contaminants to meet sales gas specifications. This picture is changing rapidly as the price for gas increases and the supply of available energy dwindles.

In the past (1965–1970), an added incentive for treating sour gas was recovery of the elemental sulfur. At present, the market situation for sulfur is not very favorable. The supply is plentiful and the price is somewhat depressed. However, the price is somewhat depressed. However, the future looks brighter. About 50% of all sulfur produced in the U.S. and Canada is consumed in the manufacture of fertilizers. Since the world population growth and need for fertilizers is on the incline, it is probably safe to assume that the price for probably safe to assume that the price for sulfur will follow an upward trend in the future.

Once a sour gas well is drilled or a "sour gas field" drilling activity is completed, the producer must consider such questions as:Is it more economical to lay a sour gasline to the nearest gas treating plant, which may have excess capacity, and pay a treating cost to have the gas sweetened?Or, is it more economical to lease equipment for on-site sweetening?
Drillstem Maintenance in Sulfide Environments
Authors: Mauzy Harry L.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Sulfide stress cracking (SSC) is a major obstacle to the successful drilling and completion of deep wells in sulfide environments. The mechanism of SSC is described and the current status of SSC resistant steels is reported. Precautionary measures to avoid or control SSC are enumerated.

Introduction

A major obstacle to the successful drilling and completion of deep wells is the increasing frequency of sour environments as deeper horizons are penetrated. While sour environments can cause trouble at any depth, higher strength steels required for deep drilling are more susceptible to failure than steels normally used for shallow wells and the deeper environments may be even more hostile.

The sudden catastrophic failure mode experienced in sour environments is termed sulfide stress cracking (SSC), and is characterized by flat, brittle failures with little visible corrosion and no detectable plastic deformation. These failures occur plastic deformation. These failures occur while operating at apparently safe load levels and often after extended periods of satisfactory performance.

In the 20 to 25 years since the epidemic of drillstem failures in the Jumping Pound and Pincher Creek fields in Canada and Pound and Pincher Creek fields in Canada and the Lacq field in France focused attention on material performance in sour environments, extensive investigations have conclusively shown that SSC is a severe form of internal hydrogen embrittlement, accentuated by the presence of hydrogen sulfide (H2S). presence of hydrogen sulfide (H2S).

MECHANISM OF SULFIDE STRESS CRACKING

Atomic hydrogen (H), generated in drilling fluids by corrosion processes, bacterial action, or thermal degradation of organic additives, can be absorbed into and diffuse through the steel crystal lattice. In the absence of H2S, atomic hydrogen quickly forms molecular hydrogen (H2) that cannot be absorbed. The presence of H2S greatly decreases the speed of recombination of H to H2, thereby increasing the amount of atomic hydrogen available for absorption.

After being absorbed into the steel, the atomic hydrogen migrates to and accumulates at the region of highest stress usually just below the root of a thread, notch, section change, or other discontinuity.
New Automated Continuous Gas-Lift Control System Improves Operational Efficiency
Authors: Bergeron Terry , Cooksey Andrew , Reppel J. Scott
Published: December 2007

The gas lift injection rate and its correlation to the oil production rate has been well established. State-of-the-art electronic flow controllers are now being employed to improve the efficiency of the injection process in gas-lifted applications so that the profitability of the wells can be increased. These control systems, which integrate modern electronic flow measurement methods with proportional-plus-integral-plus-derivative (PID) control, generally result in an improved return on investment for gas lift installations.

This paper presents field data for an automated continuous gas-lift control system that illustrates how a more efficient use of injection gas results in lower injection costs, and in some cases, increased oil production. Case No. 1 confirms the benefits of maintaining a constant injection rate by regulating the production. This case also supports the theory that once a certain gas injection rate is reached, additional injection will not yield additional oil production.

Case No. 2 discusses a remote single-well application that suffers from lost production because of injection line freezing at the injection choke and will illustrate how the use of electronic gas-lift controllers eliminated the problem.
A New Gelling System for Acid Fracturing
Authors: Woo G. T. , Lopez H. , Metcalf A. S. , Boles J.
Published: December 2007

Typically, the gelling agents used in crosslinked hydrochloric acid are available as polymer dispersions with a pre-blended inverting agent or gellant activator. An inverting agent increases the polymer dispersion's viscosity initially and will further increase the polymer dispersion's viscosity over the shelf life of the product. As a result, the polymer dispersion's pour point and stability are adversely affected, thereby reducing the polymer dispersion's shelf life. Additionally, the use of a nonylphenol ethoxylate, the inverting agent commonly pre-blended in polymer dispersions, has been banned in the North Sea due to environmental concerns.

A new gelling system for crosslinked acid fracturing treatment has been developed. The system includes a micro-emulsion polymer gelling agent and a highly specific surfactant that is used as an external activator. The micro-emulsion polymer possesses very unique and more desirable properties such as a lower pour point and viscosity profile, a greatly enhanced dispersability, and a microscopic emulsion polymer particle.

With a lower pour point and innate viscosity profile, the gelling agent is readily pumped directly from the shipping vessels to the blending unit even in cold weather. With such a greatly enhanced dispersability, the gelling agent is readily dispersed in the hydrochloric acid without the risk of forming unhydrated masses or "fish eyes". Additionally, the microscopic emulsion particle greatly prolongs the shelf life of the gelling agent by virtually eliminating polymer settling. With the use of the special external gellant activator, the emulsion polymer could achieve 70% or more hydration within one minute. The characteristics of the gelling agent and the use of the external activator enable the gelling system capable of "continuous mix" or "on the fly" gelling operations.

In addition, this external activator is biodegradable making it more conducive to environmental concerns.

This paper describes the chemistry of the new gelling system, its enhanced gelling capabilities, discusses the results of lab testing leading to its development, and finally, the results of extensive field-testing.