bluuebunny/crossref_metadata_2025 huggingface dataset:
Integrated Team Approach to the Design, Construction, Start Up, and Operation of the World's Most Modern Drilling Rig
Authors: Croucher T. M.
Published: December 2007

This paper describes how an integrated team approach was applied to the design, construction, start up, and ultimately the operation of a high technology drilling rig. The rig was built to conform, wherever possible, to the stringent regulations in the Norwegian sector of the North Sea. The paper, which also contains a technical description of the rig itself, also addresses the issue of automation and it's effect on manning of a complex drilling unit and the importance of high quality training of the personnel selected to operate the rig.

In 1994, Phillips Petroleum Company Norway, the operator of the Greater Ekofisk Area fields in the central North Sea, signed a contract for the construction of a state of the art, fit for purpose drilling rig to be located on the new Ekofisk 2/4 X wellhead production platform. The rig was an element of major importance to the Ekofisk II project, the redevelopment of one the largest fields in the North Sea. The start up of drilling on the 2/4 X platform was the first major milestone in the Ekofisk II project and the timely redrilling of the Ekofisk field wells from the new rig was vital to maintain production levels.

On 26th October 1996, exactly on schedule, the first well on the 2/4 X platform was spudded. To date six wells have been drilled by the rig including the fastest well ever drilled in the Ekofisk field. The drilling program is currently on schedule and the rig has operated at an average availability of 98%.

The success of this project can be attributed to a number of factors, however, one element stands clearly as the key success factor—a truly integrated team approach to all phases of the delivery of the rig! From the very beginning, representatives of the real customer of the product, the offshore drilling team, joined the rig supplier's design team to work shoulder to shoulder on the specification and preliminary design of the rig. As the design process moved forward, the customer representation on the team was strengthened. Ultimately, the customer participated in an active manner in all aspects of design, construction, commissioning, and start up of the rig.

This paper will detail both the underlying philosophy and the practical process by which this state of the art rig was successfully built and put to work.

The paper includes a description of the rig itself, a review of how the integrated team approached the various phases of delivery of the rig and an outline of how the project was managed.

The paper then discusses the issue of whether an automated rig can lead to a reduction in manning levels and covers the unique way in which the rig crews rig were trained. Some equipment performance figures are included to demonstrate the successful operational capabilities of the rig, and finally some conclusions are drawn from the lessons that have been learned.
Flow-Pattern Transition and Hydrodynamic Modeling of Churn Flow
Authors: Tengesdal J. Ø. , Kaya A. S. , Sarica Cem
Published: December 2007

A thorough review of the existing models for slug-churn transition in vertical and upward inclined two-phase flow is presented. A new transition model based on the drift flux approach and experimental data has been proposed. The new transition model performed the best when it was compared with the existing models and agreed very well with the published experimental data. Two separate hydrodynamic models are presented to predict pressure drop and liquid holdup in churn flow. One is a modified slug model, and the other is a model based on drift flux approach. The performances of the hydrodynamic models are evaluated against a well databank that contains 46 churn flow cases including laboratory and field data.
Pembina Field Polymer Pilot Flood
Authors: Groeneveld H. , George R.A. , Melrose J.C.
Published: December 2007

A polymer pilot flood using Pusher 700 as carried out in two adjacentfive-spot patterns in the Pembina field to decrease water channeling in a thickconglomerate zone overlying the sand pay. Although a high viscosity wasachieved in the pilot injection water, only temporary improvements in theproducing- and injection-well behavior were observed.

Introduction

The Pembina field is located in Alberta, Canada, ab out 70 miles southwestof Edmonton (Fig. 1). This large field, which now covers about 500,000 acres, was discovered in 1953 by Mobil Oil Canada, Ltd. The reservoir is astratigraphic trap producing from the Cardium zone at a depth of about 5,000ft. Neither bottom water nor free gas has been found. The field is developed on80- and 160-acre spacing. There are presently about 3,000 active producingwells and 1,400 injection wells. The cumulative production to date is 800million bbl, or about 11 percent of the original oil in place. More than 75percent of the field is under pressure maintenance by waterflooding, miscibleflooding, or gas flooding.

The Cardium zone, which is of Cretaceous age, was deposited under varyingconditions and shows a wide range of rock characteristics. The sand is overlainby a conglomerate section that is extremely erratic in deposition and variablein thickness. Permeabilities in the conglomerate can be very high. Pressuremaintenance performance in the field is severely affected by reservoirstratification in the sand, and particularly by the presence of a welldeveloped conglomerate section. Early breakthroughs and high WOR s are typicalproduction characteristics for wells in areas with thick conglomeratesections.

Considering that the oil in place in the Pembina field is about 7.4 billionbbl and that about 15 percent of the area is overlain by a well developedconglomerate, some improvement of the vertical sweep efficiency throughreducing the adverse effects of the conglomerate could add large reserves tothis field. However, there have been no successful field tests to achieve thisgoal. The purpose of the pilot was to field test the efficiency of Dow ChemicalU.S.A. Pusher 700 in an area of the Pembina field where the stratification hasseverely affected a waterflood.

The viscosity of the Pembina oil is about 1 cp and the flood mobility ratiois less than unity, which is a generally favorable flood situation. Thus, theobjective of the test was not a general performance improvement to correct anadverse mobility-ratio flood, but was to reduce water channeling to bring aboutbetter vertical sweep.
Acid Filtration Under Dynamic Conditions To Evaluate Gelled Acid Efficiency in Acid Fracturing
Authors: Bazin Brigitte , Roque Claude , Chauveteau G. A. , Boutéca M. J.
Published: December 2007

During the acid-fracturing process, part of the fluid enters the formation, dissolving the rock and creating channels, named wormholes which enhance considerably the volume of fluid leak-off and acid consumption into the formation. To increase the efficiency of the acidizing process, the fluid leakoff must be reduced to improve the fracture acidized length. This paper is a contribution to the study of the phenomenology of the acid fracturing process. An experimental approach, which includes the measurements of wormhole propagation velocities, leakoff volumes, and the observations of the dissolution patterns, has been developed to evaluate acid fluids performance under various representative conditions of acid flow into a fracture.

The tests are performed in a tangential cell which allows the solution to circulate in a slot and to penetrate the core at constant pressure drop, thus respecting the geometry encountered in the field process. The experiments herein described have been conducted on limestone cores of different permeabilities. The tests have been performed at room temperature, 50 and 80°C with different overbalance pressures. Fluids are gelled and regular acid.

The results are discussed in terms of acid fluid efficiency. The fluid leakoff is evaluated for different initial conditions and linked to the dissolution pattern. The results show that etched patterns suitable for acid fracturing are not developed at the core surface with the gelled acid. However, viscosifying the acid reduces the water filtration by a factor ranging from 3 to 10. Etched patterns are favored by high strength straight acids at low overpressure.
Experimental Three-Phase Flow in Porous Media: Development of Saturated Structures Dominated by Viscous Flow, Gravity, and Capillarity
Authors: Barbu Alexandru , Hicks P. J. , Grader A. S.
Published: December 2007

The motivation for this work is the need to understand the formation of oil banks during waterflooding operations as well counter-current gravity driven oil recovery mechanisms. The success of these operations depends on a combination of viscous, gravitational, and capillary forces. This paper focuses on the development of three-phase saturation structures driven by viscous flow, gravity, and capillarity. Three liquids: water, benzyl alcohol, and decane are flowed through glass bead packs. Dynamic water floods of cores saturated with mixtures of benzyl alcohol and decane are described. Saturation distributions in the core are determined using x-ray computer tomography (CT). The injection of water generates a benzyl alcohol bank that displaces most of the decane ahead of it. Benzyl alcohol and decane, driven by gravity, exchange places in the core. This gravity driven counter-current flow is rapid in the presence of low water saturation ahead of the benzyl alcohol bank and within the benzyl alcohol bank. The gravity exchange is slow in the presence of mobile water behind the benzyl alcohol bank. The water saturation structure is stable and is not significantly affected by the counter-current flow of benzyl alcohol and decane. The accumulation of decane at the top of the core triggers a backward migration of a decane tongue. The decane tongue disappears when water injection is resumed and the benzyl alcohol bank re-forms where the decane tongue existed. When mobile decane is not present, significant capillary driven longitudinal fluid transport is observed while the high gradient saturation structure in the transverse direction remains stable. Even high saturation gradients in the longitudinal direction are quite stable. Fluid flow patterns during the shut in periods and displacement mechanisms are proposed.
Gas Migration by Diffusion in Aquifer Storage
Authors: Bagrodia Vijay , Katz Donald L.
Published: December 2007

Introduction

In aquifer-storage reservoirs, natural gas, primarily methane, displaces water and forms a gas phase in contact with water-saturated porous media. Normally, such waters do not contain dissolved gas initially and the question arises as to how much gas would enter the water phase by diffusion over a period of time. Then, if there is phase by diffusion over a period of time. Then, if there is a hydraulic gradient across the storage field and water moves slowly, how much gas would be carried away from beneath the storage bubble?

Pandey et al. and Chou-Chen provided experimental data on diffusion rates of gases through water-saturated porous media. Their studies give representative values porous media. Their studies give representative values for the diffusion coefficient of methane related to porosity and permeability. Typical aquifer reservoir sands porosity and permeability. Typical aquifer reservoir sands might have 100-md permeability with a lower limit of 1 md and a higher limit of 1,000 md, and with porosities ranging from 12 to 20 percent. Using these reservoir properties, the diffusion coefficients are found from properties, the diffusion coefficients are found from Chou-Chen's correlation of diffusion with permeability.

A typical aquifer-storage reservoir has a gas phase above water-filled porous sand. This sand is assumed to be homogeneous and initially saturated with water that is free of methane. The natural gas is assumed to be pure methane. Formulas were set forth for finding the relative saturation of methane in the water as compared with saturated water at a pressure of 48.3 bar (700 psia) and a temperature of 25 deg. C (77 deg. F).

Diffusion Calculations

By taking a molar balance across an element of water-saturated sand at y ft below the gas-water interface and by applying Fick's law with the effective diffusivity coefficient, one can compute the accumulation of methane in the element with time using Eq. 1.

(1) where

C = concentration of methane in water phase phi = porosity of the sand phi = porosity of the sand De = effective diffusivity coefficient y = depth below the interface, ft t = time, years.

This second-order differential equation can be solved with the help of the initial boundary conditions; that is, initially porous sand is saturated with water, free of methane. At the gas-water interface, water in porous media is saturated with methane. Integration of Eq. 1 gives (2)

where C is the concentration of methane in saturated water at 48.3 bar (700 psia) and 25 deg. C (77 deg. F).

Eq. 2 relates the relative concentration of methane in water to depth below the interface, time, effective diffusivity coefficient, and porosity.

Solutions were made for three cases of 1,100 and 1,000 md. The results of the integration for 100-md sand of 16-percent porosity are shown in Fig. 1.

JPT

P. 121
Stability Analysis of Stratified Oil/Water Flow in Inclined Pipelines
Authors: Fairuzov Yuri V.
Published: December 2007

A theoretical study was conducted to investigate flow-pattern transitions in slightly inclined pipelines carrying oil/water mixtures. Two criteria obtained in the linear-stability theory of stratified oil/water flow were used to predict the transition from a stratified-to nonstratified-flow pattern. A comparison of theoretical transition boundaries with published experimental data for horizontal and inclined pipes (±1° and ±5°) was performed. The study revealed that pipe inclination has a significant effect on the stratified-flow region. The results obtained can be useful for the design and operation of crude-oil flowlines and directional wells.
Novel Wax-Diverter Technology Allows Successful Scale-Inhibitor Squeeze Treatment in a Subsea Horizontal Well
Authors: Jordan M. M. , Edgerton M. C. , Cole-Hamilton J. , Mackin K. W.
Published: December 2007

In this article we present field results from two scale squeeze treatments carried out on the same subsea horizontal well from the Strathspey field in the North Sea. The initial squeeze was a bullhead application of phosphonate scale inhibitor to control a sulfate scale problem in a horizontal well. Ten months after the initial treatment a second bullhead squeeze treatment was applied in two stages. This latter utilized a thermally degraded pelleted wax diverter to temporarily impair the injectivity in the heel region of the horizontal well thus allowing propagation of the second stage of the squeeze treatment into the midsection of the horizontal well.

In this article we show the significance of production logging tool data to evaluate the location of deposited scale and water production prior to a squeeze treatment. These data were used to design a novel two stage squeeze treatment in which an initial squeeze slug was applied to the heel region followed by application of a pelleted thermally degraded wax diverter to prevent further loss of scale inhibitor to the heel region. The action of the wax diverter allowed a second scale inhibitor slug to be placed further along the horizontal section of the well. Details of the diverter selection and the squeeze design strategy implemented in this squeeze treatment will be presented. During the field treatment, physical (downhole pressure and temperature) data and chemical (nonradioactive tracers, inhibitor and ion concentrations) data were recorded. These data will be used to indicate the success of the diversion treatment by a comparison with the first squeeze applied to the same well 10 months previously.

This is the first successful application of a thermally degraded wax diverter to a subsea horizontal well in the North Sea basin. The well was successfully treated with no process upset during flowback and no decline in well production while allowing the well bore to be protected from continued sulfate scale formation. In this article it is clearly shown that with the correct selection of both the scale inhibitor and diverter agent together with ulitization of all available information relating to the reservoir, it is possible to squeeze scale inhibitors into subsea horizontal wells without the need for intervention by expensive coiled tubing from a diving support vessel.
Gel Treatments for Reducing Channeling in Naturally Fractured Reservoirs
Authors: Seright R. S. , Lee R. L.
Published: December 2007

This paper considers some of the reservoir variables that affect the severity of channeling and the potential of gel treatments for reducing channeling through naturally fractured reservoirs. We performed extensive tracer and gel placement studies using two different simulators. We show that gel treatments have the greatest potential when the conductivities of fractures that are aligned with direct flow between an injector-producer pair are at least 10 times the conductivity of off-trend fractures. Gel treatments also have their greatest potential in reservoirs with moderate to large fracture spacing. Produced tracer concentrations from interwell tracer studies can help identify reservoirs that are predisposed to successful gel applications. Our simulation studies also show how tracer transit times can be used to estimate the conductivity of the most direct fracture. The effectiveness of gel treatments should be insensitive to fracture spacing for fractures that are aligned with the direct flow direction. The effectiveness of gel treatments increases with increased fracture spacing for fractures that are not aligned with the direct flow direction.
Pumping Wells with Electrical Submergible Pumps
Authors: Parker R.W.
Published: December 2007

This paper reviews the components of electrical submergible pumps with respect to field proven designs which have provided wider application in recent years. Installation procedure is described briefly to point out precautions necessary to obtain long service runs. Performance data for several oil and water supply wells are presented to show what can be expected in the way of operational and maintenance problems and expenses. And finally, the application of electrical submergible pumping is discussed with respect to economics and ultimate recovery.

Introduction

The electrical submergible pump has become a common method of lifting volumes of fluid ranging up to 20,000 B/D. Pump depth may exceed 12,000 ft. Many operators who are not familiar with its varied applications are reluctant to use it because its economic success is not fully understood. The results of several applications economically proven by Marathon Oil Co. in the Big Horn Basin of Wyoming are presented herein to show that the submergible pump has its rightful place in the oil industry.

Description of Equipment

The many sizes and types of submergible pumps are too numerous to mention; but a typical installation designed to lift 4,000 bbl of fluid per day against a total head of 3,000 ft (water) is shown in Fig. 1. Components and costs for this installation are listed in Table 2.

The motor located on the bottom is a 150 hp, 3 phase, 60 cycle, squirrel cage induction type which operates at 3.600 rpm. The protector located above the motor is used to prevent well fluids from entering the motor. Its housing is bolted to both the pump and motor and contains a splined shaft that connects the pump and motor shafts to provide a direct drive.
Petrophysical Analysis of Some Wilcox Wells
Authors: Paine S.M.
Published: December 2007

Relationships are shown between some of the fundamental rock properties of the heterogeneous Eocene Wilcox formation along the central and eastern portion of the Texas Gulf Coast trend. Mention is made that quantitative evaluation, using the electrical logs and established correlations, often are difficult due to:variations in the shale content and cementation of the sand,variations in water salinities,thin bed effects, andinvasion effects.

However, it is pointed out that this does not preclude the use of electrical logs but rather that extra care must be exercised in their interpretation.

Several representative wells along a portion of the trend are reviewed ]to illustrate some of the general characteristics of the formation and the individual utility of some of the logging devices. Particular emphasis is placed on the value of drill cuttings and sidewall cores, as well as capillary pressure data which indicate pore size distribution and which, in turn, are related to porosity, permeability and water saturation. It was concluded that conventional coring usually is not essential for evaluation of exploratory wells along this portion of the Wilcox trend inasmuch as proper logs, in conjunction with cuttings and a few sidewall cores, generally provide adequate data for evaluation.

A recommended evaluation program for down-dip Wilcox exploratory wells penetrating either the upper or both the upper and lower section is presented. It is stressed that the suggested program is necessarily general and therefore flexible and should be considered only as a guidein selecting evaluation procedures.

Introduction

Evaluation of the Eocene Wilcox along the Texas Gulf Coast trend varies from relatively simple cases, as exemplified by a typical well in the upper Wilcox at Mercy, Tex., to the more difficult ones such as found in the lower Wilcox at Sheridan, Tex. In either instance, quantitative evaluation of potential pay sections requires information concerning the porosity, permeability, and formational content (oil, gas or water), or more fundamentally, as Archie has shown, such evaluation should reveal the distribution of each phase (oil, gas or water) within the pores of the rock, The evaluation should not be limited only to permeable rocks containing hydrocarbons, but should include also the impermeable layers as well as the permeable layers containing water.
Reversible Invert Emulsion Drilling Fluids: A Quantum Leap in Technology
Authors: Patel A. D.
Published: December 2007

A novel, invert emulsion fluid useful in the drilling, completion, and workover of subterranean wells has been invented. The new invert emulsion drilling fluid can readily and reversibly be converted from an invert, i.e., water-in-oil emulsion, to a regular, i.e., oil-in-water emulsion, and back to the original invert emulsion using an acid-base chemical switch. The surfactants used in the reversible invert emulsion fluids are strong invert emulsifiers in the presence of lime. However, the same surfactants become regular emulsifiers in the presence of water-soluble acid. The reversible emulsion property of these surfactants allows the drilling fluid to be changed from an invert emulsion to a regular emulsion at different stages of the drilling/completion operation. During the drilling stage, the drilling fluid can be an invert emulsion achieving all the performance benefits associated with oil-based muds (OBMs). During the completion stage and afterwards, the emulsion can be reversed by adding water-soluble acid, thus providing excellent filtercake cleanups, improved production in an openhole completion, better cementing, and efficient cuttings cleanup and waste minimization. The reversible system is simple and easy to run without any exotic changes in current operations or other additives than those commonly used in OBMs. The reversible drilling fluid is versatile and relatively inexpensive and versatile, especially as compared to new, exotic fluids on the market today. The reversible feature allows the mud to achieve performance, production, minimal environmental impact, and cost control. The paper discusses the overall impact of reversible invert emulsion technology in meeting the environmental and functional requirements of drilling operations. The laboratory data show that this system can provide drilling performance similar to OBMs at various oil/water (O/W) ratios, mud weights, and in the presence of commonly encountered contaminants. This paper compares the new reversible fluids with previous state-of-the-art invert emulsion drilling fluids. These new stable, reversible invert emulsion drilling fluids can readily be reversed to regular emulsions using inorganic acids such as hydrochloric acid or organic acids such as citric acid. The paper discusses the application of reversible emulsion technology on efficient removal of filter cake and improved production in openhole horizontal well completions. The environmental impacts of this system on washing and disposal of drilled cuttings are discussed.
Can We Sample the Complete Geological Uncertainty Space in Reservoir-Modeling Uncertainty Estimates?
Authors: Massonnat G. J.
Published: December 2007

The method by which the space of uncertainty should be sampled in reservoir models is an essential point of discussion that can have a major impact on the appraisal, development and economics of hydrocarbon fields.

Usually, uncertainty is assessed by way of many realizations of a given stochastic model with fixed parameters but this does not adequately sample the complete geological uncertainty space and it underestimates the uncertainty.

To improve the uncertainty assessment, in this article we propose a classification and hierarchy of the sources of internal reservoir architecture uncertainty.

The impact of the different levels and sources of uncertainty on elements such as original hydrocarbons in place or final recovery is quantified.

In this article we demonstrate that decisions as significant as stationarity, organization of reservoir heterogeneity, choice of the global statistics and variogramme range are of prime importance in relation to the other parameters. Furthermore, we also prove that the relative importance of any parameter in assessing the uncertainty depends on the type of result—volumetric or dynamic—on which the uncertainty calculation is computed.

Uncertainty of the global mean provided by hard data is assessed using sampling techniques.

The coefficients of variation obtained from many field cases allow a comparison between the different distributions. It lends support to the hierarchy of the sources of geological uncertainty into six levels.

The evolution of this uncertainty with the quantity of hard data, wells, and the quality of knowledge, zoning, has been quantified using synthetic models and a field case.

Both a general function for the decrease of uncertainty with the quantity of the data, and a possible increase—for some parameters—of uncertainty estimates with knowledge development are demonstrated herein.
Detailed Response of Some Rock Targets to Jets from Lined-Cavity Shaped Charges
Authors: Austin Carl F. , Pringle J. Kenneth
Published: December 2007

The U. S. Naval Ordnance Test Station has a continuing program of applied research in rock and earth dynamics. One aspect of this program has been the investigation of rock masses subjected to jet attack from lined-cavity shaped charges. The detailed testing of rock response has been carried out in air using dry bulk targets of sufficient size to preclude gross target fracturing during penetration. Overcoring methods have then been used to remove the penetration area to permit section in g and studying the hole walls. During these tests two distinct modes of penetration wall response were observed. One mode is well illustrated by coarse-grained silicate rocks which yield penetrations with severe adjacent grain damage plus significant compaction and stored energy, which is slowly released by failure of the hole walls. The second mode is illustrated by limestone, which gives virtually no megascopic damage adjacent to the hole and which is stable following penetration. Under proper conditions, however, the limestone samples consistently yield liner-metal and liner-metal-oxide filled fractures adjacent to the penetration. Tests were also performed which permitted evaluation of the effect of gross target fracturing during penetration, and evaluation of the concept of rock density as a criterion of penetration depth.

Introduction

The mechanisms of jet formation by various configurations of lined-cavity shaped charges and of penetration in metallic targets have been extensively reported in the technical literature. Jet penetration into rock and earth materials has been investigated in conjunction with mining uses and a considerable body of technical literature established on the petroleum industry applications of shaped-charge phenomena. Examination of these many publications reveals that the details of the response of rock targets to the jet penetration process are not well known. The studies reported in this paper were performed to establish the detailed response of rock targets in air to jets from lined-cavity shaped charges and, as such, do not necessarily represent down-hole, well phenomena. The rocks selected for testing are representative of broad groupings of geologic materials that occur in bulk on the earth's surface, but only the general materials applicable to the petroleum industry are discussed. Although the igneous rocks, per se, are of minor interest to petroleum engineers, these rocks are occasionally important reservoir rocks. Furthermore, the igneous rocks, despite their limited occurrence as reservoir rocks, offer a wealth of pertinent data on general rock behavior. The behavior of igneous rocks is also believed to be representative of the behavior of dense, hard, low porosity silicate rocks in general. Quartzites, strong sandstones and many metasediments are believed to belong in this grouping of materials.A set of standard definitions of penetration effects must be established in order to permit a useful discussion of jet penetration phenomena.

JPT

P. 41^
A Field Streaming - Potential Experiment
Authors: Gondouin M. , Hill H.J. , Waxman M.H.
Published: December 2007

Streaming-potential experiments were conducted within the Muddy- and Dakota-sandstone interval of a Denver basin well. Analysis of the data shows that, for this case, streaming potentials opposite sands were higher than those opposite shales when the mud was fresh. Streaming potentials opposite shales, however, were of sufficient magnitude to be important in SP interpretation. They were linearly dependent upon pressure differential, and they increased with mud filtrate resistivity. The magnitude of streaming potentials opposite sands was influenced by the characteristics of the original mud cake formed at the time of drilling. Use of mud samples taken at the time of logging may not always be satisfactory for determining streaming-potential corrections. Both the streaming and electrochemical potentials were found to be affected by the previous history of the borehole system. Following a change in mud characteristics, several days were required for SP stabilization. This was, in part, due to the mud cake acting as an imperfect shale membrane.

Introduction

Laboratory investigations by Wyllie, Salisch, Moore, Sen Gupta and Bannerjee, and Hill and Anderson have shown that streaming potentials developed across mud cakes deposited on permeable filter beds are of sufficient magnitude to be critically important in SP interpretation. Streaming potentials across shales have been reported by Schenck, Gondouin and Scala, and Hill and Anderson. The magnitude of the shale streaming potentials obtained by Schenck and by Gondouin et al led these authors to conclude that in many cases the shale streaming potential would approximately equal the mud-cake streaming potential. Hill and Anderson, however, obtained somewhat lower magnitudes of shale streaming potential. The field experiment described in the present paper was a cooperative project carried out by the respective operations and research departments of Schlumberger Well Surveying Corp., Shell Development Co. and Shell Oil Co. The primary objective of the experiment was to determine in the borehole the streaming-potential behavior of both shales and mud cakes under conditions approaching, as nearly as possible, those normally encountered in logging practice.

METHODS AND EQUIPMENT

WELL

A Muddy- and Dakota-sandstone well in the Denver basin was chosen for the experiment. Both sandstones were water-bearing and, since reservoir pressures in these sandstones are abnormally low (gradient of approximately 0.25 psi/ft), it was expected that studies of streaming potential could be conducted from low-pressure differentials (approximately 200 psi) to about 2,000 psi by bailing mud from the hole, filling up and then applying wellhead pressure.

JPT

P. 305^
First Pacific Coast Permanent Drilling Island Modified to Allow Drilling of 70 Wells
Authors: Pyles E.E.
Published: December 2007

The first permanent drilling island constructed on the Pacific Coast is now being modified to provide surface locations for the drilling of a total of 70 wells, The small circular Monterey Oil Co.- The Texas Co. filled island, 1 1/2 miles offshore from Seal Beach. was originally designed for the drilling of only three wells. Now, through the construction of a raised floor to provide additional cellars, this small island is expected to provide adequate surface drilling sites from which to develop the lease.

When this modification has been completed, about the end of this year, the little island will provide probably the densest concentration of drilling sites anywhere in the world.

The circular island is 75 ft in diameter and is located in 45 ft of water. A rectangular wharf 74 ft by 51 ft extends shoreward from the island. A group of four pipelines connects the island to a separation and shipping center onshore. Nine wells have been drilled from the island to date, and the tenth one is now being drilled.

The outer rim of the island is formed of interlocking sheet steel piling driven into the ocean floor to a depth of 15 to 20 ft. The interior is filled with rock and sand. A series of parallel reinforced concrete beams across the island carries the working load. Each beam is supported by a line of wood piling. The reinforced concrete floor rests on the beams and sand fill. The construction of the raised floor above the original concrete floor is now in progress. Through this addition the island, which was once considered supplemental only, will become a very valuable surface property from which to develop the extensive oil reservoir. The operators have spend approximately $750,000 in connection with island construction.

Early History of the Lease

In 1944 the Marine Exploration Co., one of the predecessors in interest of Monterey Oil Co. and The Texas Co., obtained rights to drill for oil offshore at Seal Beach by obtaining state lease which was the predecessor of the present State Lease PRC 186.1. This lease begins at the Seal Beach shoreline and extends 3 miles seaward. The drilling of the first two wells was done from a land location in the City of Long Beach, County of Los Angeles, 2.500 ft inland front the water's edge.
Application of the p'D Function to Interference Analysis
Authors: Djebbar Tiab , Anil Kumar
Published: December 2007

A technique for analyzing interference test data is presented that employsthe time rate of pressure change - the pD' function. Thisfunction exhibits a maximum value of 0.736 at atD/rD2 of 0.25 for an idealline-source well. Several field examples are included to demonstrate theapplication of this technique in determining transmissibility (kh/µ) andstorage (fch) between a well pair.

Introduction

It has been pointed out that interference tests1 may be run withgreater ease and may take less time than pulse tests2,3 to developin-situ reservoir properties such as transmissibility (kh/µ) and storage(fch). An interference test consists of recording the transient pressureresponse at an observation well caused by a constant rate change at some sourcewell. The pressure response can help determine formation continuity, fracturesorientation, and areal average transmissibility and storage between a wellpair.

Interference pressure data can be analyzed by (1) least-squares regressionanalysis coupled with a two-dimensional single-phase compressible-fluidreservoir simulator4,5 and (2) type curve matching6,7techniques. A rapid hand analysis method1 requires the recognitionof the maximum slope line on pressure response ?p vs. time curve plottedon a rectangular coordinate paper. This slope is used to determine thetransmissibility (kh/µ). The intercept of this line on the time scale isused to obtain storage (fch) between the well pair.

The slope of the line gives the maximum value of the time rate of change ofpressure at the observation well. This maximum slope occurs at the inflectionpoint of the ?p vs. time curve. The time to reach this maximum slope ofinflection point is also a characteristic of the system and, therefore, can beused to determine the storage (fch) between the well pair. The examplespresented in this paper will illustrate this technique.

In view of the above, it is necessary to develop the behavior ofpD' at an observation well due to a constant-rate source wellfor a proper understanding of interference test behavior. The wellbore storageeffects are assumed to be negligible at this source or active well. This ispresented in the next section in terms of dimensionless quantities forsimplicity. In later discussion, equations in oilfield units are used.

It is emphasized here that the pD' function has been usedbefore in petroleum literature for water influx8–10 and wellborestorage11,12 calculations. Further, pD' behaviorhas been employed in detection of reservoir boundaries.13–15 Theseapplications will not be discussed in this report.
High-Rate Foam Fracturing: Fluid Friction and Perforation Erosion
Authors: Harris P. C. , Pippin P. M.
Published: December 2007

Foam fracturing treatments pumped down 3.5 to 4.5 in. tubing at up to 80 bbl/min have presented problems in control and execution. Wellhead pressures used to predict net entry pressure can give erratic results in the absence of good knowledge of bottom-hole pressure. Since nitrogen ( N2) delivery rates are pressure sensitive, errors in bottomhole pressure estimation control problems with both rate and foam quality. Perforation erosion, if unaccounted for, can signal a need for increase in rate to maintain bottomhole pressure.

We used a laboratory study of foam in laminar and turbulent flow and a series of field experiments with bottomhole gauges to calibrate foam friction pressure in tubulars at very high rates. To measure viscosity of foam fluid with N2 at 1,000 psi, we used a small-scale, flow loop viscometer that could be applied in both laminar and turbulent flow. Foam parameters included foam qualities from 25 to 80% N2, and guar concentrations from 0 to 40 lbm/Mgal. The effect of surfactant concentrations from 0.2 to 1.0% were also studied.

Field foam treatments pumped at high foam rates were equipped with bottomhole real-time transmitting gauges. Step-rate tests were performed on both neat foam and sand-laden foam to calculate friction pressures. Actual friction pressures from these treatments were compared with pressures based on laboratory data. The laboratory correlation can predict tubular friction accurately for foam fluids up to very high foam rates.

In several of the treatments, small perforations were used in an attempt to provide limited entry stimulation. With the bottomhole-gauge data, we were able to assess the effects of perforation erosion due to changes in sand concentration.
Case History of Reservoir Subsidence and Wellbore Damage Management in the South Belridge Diatomite Field
Authors: Dale B. A. , Narahara G. M. , Stevens R. M.
Published: December 2007

Production of fluids from the shallow, thick, and low-strength Diatomite reservoir in the South Belridge Field has resulted in reservoir compaction, surface subsidence, and numerous well failures. The most severe subsidence problems occurred while the field was under primary recovery, prior to implementation of waterfloods for pressure support. Consequently, a significant number of wells in the field have incurred casing damage, which proportionately limits the utility of these wellbores for continued production and routine wellwork operations. The nature of casing damage varies significantly depending on the location in the field, however casing shear ("kinks") generally produces the most severe problems in retaining full wellbore utility since it limits tool passage (e.g., packers, scrapers, etc. ) and is not economical to repair using conventional milling tools.

Since the mid-1980s, surveillance has been in place to monitor and assess the magnitude and progression of surface subsidence, reservoir compaction, and wellbore damage in Exxon's operations of Section 19 in the South Belridge Field. The surveillance includes the use of ground elevation markers and a variety of production logs—several of which involve novel application and log interpretation. These data subsequently were used to develop and verify hybrid geomechanics and wellbore geometric models for assessing casing damage, identifying well operability and wellbore utility limits, and forecasting the remaining wellbore life from which a reservoir management plan and wellbore management operational strategies were established. A key ingredient in the implementation of this plan and operational strategies involved a cooperative tool development with a major oil tool service company to repair casing kinked wellbores as an alternative to re-drilling wells.

In this article we provide a case history that describes the various synergistic reservoir and wellbore management activities designed to effectively mitigate subsidence-induced operational problems and the accompanying field benefits resulting from their implementation.
Steam Injection Project in Heavy-Oil Diatomite
Authors: Murer A. S. , McClennen K. L. , Ellison T. K. , Larson D. C. , Timmer R. S. , Thomsen M. A. , Wolcott K. D.
Published: December 2007

A steam injection project was conducted in diatomite containing heavy, biodegraded oil (12°API, ∼3,000 cp) in the South Belridge field, Kern County, California. The diatomite interval tested (the San Joaquin, Etchegoin, and Belridge diatomites) underlies an active steamflood in the sandstone of the Tulare formation. Initially, the test was to determine the viability of cyclic steam recovery from an unpropped, steam fractured completion in the diatomite. Four standard steam cycles were completed, with sluggish oil recovery [oil–steam ratios (OSR) were less than 0.1]. The well was then hydraulically fractured and propped. Two additional steam cycles were completed that had considerably greater oil recovery (OSR>0.2). The project was then configured for steamdrive by drilling a closely spaced producer. The new producer was initially completed with a propped hydraulic fracture and cycled once. The original cyclic producer was converted to continuous injection, and a two-well steamflood was operated for more than 1 year. During the steamflood, heavy oil was mobilized and response has been continuous. The configuration of the "pattern," with only one producer, results in poor capture efficiency. The performance of this incomplete pattern has been, as expected, poor (<0.1 OSR), but steam injection is shown to be a promising recovery technique for the heavy oil diatomite. The process is applicable to California diatomites, or any other high porosity, low permeability, shallow reservoirs that contain a significant concentration of heavy oil.
Sedimentation in Emulsions of Water Petroleum
Authors: Tipman Edward , Hodgson Gordon
Published: December 2007

Introduction

An appreciable number of the oil fields in Western Canada are accumulations of heavy black oils in more or less unconsolidated sandstones. When the crude oils are produced by conventional means, they are frequently contaminated with both sand and oilfield water. The water is usually present as emulsified water, and the sand and other solid material are suspended in the emulsions.

The presence of the solid material in the crude oils is troublesome and, in general, little is known about the behavior of suspended solid particles in emulsions. The Stokes equation describes the behavior of suspended particles in homogeneous fluids in terms of particle size, density differential, and fluid viscosity. In the case of an emulsion, particle size and density differential introduce no difficulties, but considerable doubt centers around the viscosity term.

For crude oil emulsion the Simha equation and the data presented by Fukushima and Ichimura show a non-linear dependence of the viscosity ratio on the water concentration. While it is undoubtedly reasonable to use these data for predicting the viscosity of a specific emulsion, and while it is equally reasonable to expect the calculated viscosity to predict the settling rate of a solid spherical particle in the emulsion by means of Stokes equation, there seems to be no direct evidence that this calculation is indeed sound for describing the settling rates of solid particles in emulsions of water in crude oils.

Procedure

A direct approach to the problem was thus indicated. Laboratory equipment was designed and built for the direct determination of the rate-of-fall characteristics of solid particles in emulsions of water in oil. Although the apparatus incorporated the basic design of conventional falling-ball viscometers, the study was concerned directly with the rate-of-fall characteristics of particles in emulsions, rather than with the viscosity of the emulsions as such.
Steam Distillation Studies for the Kern River Field
Authors: Richardson W. C. , Beladi M. K. , Wu C. H.
Published: December 2007

The interactions of heavy oil and injected steam in the mature steamflood at the Kern River Field have been extensively studied to gain insight into the effect of steam on compositional changes of oil during the recovery process and to provide input for compositional thermal simulation. Steam distillation behavior of this 13°API California oil between 300 and 467°F under a variety of process conditions, along with extensive analysis of distilled hydrocarbons were incorporated to give a more in-depth description of what is happening to the oil and what changes are occurring in the distillates or produced oil. This information was further integrated with analysis of the field distillate, "casing blow," to infer what is happening in the field. The results show that steam distillation is temperature dependent and more important than originally thought. The data developed in this study are a basis for improvement of numerical thermal models with potential for better designed steamfloods and reservoir management. The results may also impact certain logging techniques used in steamfloods and possible heavy oil upgrading techniques.

Kern River oil is more than 10% distillable at 300°F and 15% distillable at 400°F in dynamic laboratory steam distillation tests at steam throughputs of four times the initial volume of oil. Distillate physical properties of density, viscosity, molecular weight, and hydrocarbon composition of the distillates changed significantly. Distillate properties increased in value with increasing steam throughput, and at higher temperatures. This information is important in the tuning of equations of state, including hydrocarbon-water interaction parameters for compositional thermal simulation.

Analysis of the field distillate, "casing blow," showed properties similar to laboratory distillates at low steam throughputs. The observation of a light field distillate production in a mature steamflood compared to laboratory measurements implies that the casing system temperature is a major controlling factor in "casing blow" composition and quantity.