bluuebunny/crossref_metadata_2025 huggingface dataset:
Titanium as an Alternative to Conventional Coiled Tubing: A North Sea Case Study
Authors: Christie Mike , Gavin Bill
Published: December 2007

This paper investigates the feasibility of using Titanium coiled tubing as an alternative to conventional steel coiled tubing for established operations in the North Sea. The criteria set is that both should be capable of performing the same work scope.

Within the North Sea many mature fields are serviced from platforms whose structures are being downrated in-so-far as deck load bearing and crane lifting capability is concerned. This imposes severe limitations as to the length or weight of steel coiled tubing that can be lifted onto and manoeuvered on board some platforms. Titanium alloys, being lighter than steel, give a potential solution to this problem in that they have a lower density and greater yield strength allowing thinner wall thickness to be used.

A direct comparison has been made between Titanium coiled tubing and steel coiled tubing in order to ascertain whether well entry capability is similar. While Titanium undoubtedly offers many benefits to those of steel coiled tubing there remains some uncertainty over Titanium’s horizontal reach capability due to its’ lower Young’s Modulus. Three wells (Example A, B & C) have been used to evaluate the ability of coil made with these two materials. These wells were part of a campaign of work carried out in 1996. The steel coiled tubing data and tubing force analysis predictions are thus real data, only the Titanium coiled tubing values are simulated. The coiled tubing prediction model was validated with steel coiled tubing during the job and therefore the model is the common link between the known and hypothetical values.
Casing Exit Techniques Using Coiled Tubing: Worldwide Case Histories
Authors: Pitman Malcolm , Rafferty Robin , Ferguson Andy
Published: December 2007

One of the operations that is essential for a successful and cost effective coiled tubing sidetrack is the casing exit. Currently, two coiled tubing casing exit methods exist dependent on completion configuration; through non-restricted monobore completions and "thru-tubing" casing exits.

The monobore completion or liner is exited by setting a packer and orientated whipstock then running a traditional starting mill and window mill.

The thru-tubing whipstock, which typically is run through a 4-1/2" completion and set in 7" casing / liner, utilizes a hinged mechanism which cams into place in the casing. A new generation of mills is used to cut the window.

This paper will discuss specific equipment, procedures and applications employed in a number of case history wells located in Alaska and in the North Sea.
Five years of Injection of Hydroxyethylcellulose: An Ecological Pure Product for enhanced Oil Recovery in the Field of Romashkino.
Authors: Loppinet A. , Iakovlev S. , Glénat Ph
Published: December 2007

The Petroleum Institute of Tatarstan has developed a special method of enhanced recovery based on the injection of ethers of cellulose mixture in order to increase the recovery of oil in water invaded hydrocarbon fields. This method creates a high viscous fringe in the formation. The purpose of this paper is to present the method, the results we got during our five years operation and the special and unique injection units which were invented to automatically perform the injection of this ecolologically pure hydroxyethylcellulose in a dispersed manner.

Our area of operation is the ROMASHKINO field, situated in the Republic of Tatarstan, of the Federation of Russia. More than 3 500 tons of HEC were injected in more than 180 injection wells. The additional oil production already produced reached 1 000 000 tons and is still continuing. A goal of our efficiency of almost 400 t/t which was initially calculated has already been reached and overcome in some areas.

In order to reach this result, TATOLPETRO, created some specialised trailer mounted injection units. Four trailers (pumping injection - cellulose mixing and control - power generation and utilities - bulk powder) easily moved from an injection well to another, in a very harsh environment, form the system. Its main feature is to be able to optimise the flowrate of the injection when arriving on a well and then to automatically find out the proper maximum possible dosing rate allowed by the state of the formation as well as the safety of the well structure itself. An other original feature is the low viscosity Vortex mixing chamber which disperses the cellulose in the water flow in order that the mixture reaches the formation before its comlete hydratation.
Analysis of Abnormally Pressured Gas Reservoirs with Partial Water Influx
Authors: Bass D.M.
Published: December 2007

Gas reservoir performance data were generated numerically to study the magnitude of three energy sources in abnormal pressured reservoirs. It was found that pressured reservoirs. It was found that peripherial water influx and formation peripherial water influx and formation expansion made the greatest long-term energy contribution. Based on the generated data, a technique is presented for determination of gas-in-place. Attempts were made to apply the technique to conventional field data with inconsistent success.

Introduction

The petroleum industry has become indoctrinated into evaluating all gas reservoirs based on the P/Z - Gp Plot. This indoctrination has been so complete that gas reservoirs that deviates from a straight line indicates water-influx or gas-efflux. During the entire period of indoctrination, it has been known that very restrictive assumptions were made in order to justify the P/Z - Gp straight line relationship. These assumptions are:

- No loss or gain of energy from outside forces;

- The connate water does not expand;

- The pore space does not contract;

- The gas is always single phase in the reservoir; and

- The pressure used in the equation represents the volumetric average reservoir pressure.

In many field examples these limitations placed little restriction on the accuracy of the P/Z - Gp plot. With the advent of low permeability, high condensate, high rock compressibilities, or limited water influx the P/Z - G curve began to yield apparently correct, but unfortunately erroneous answers in the early life of a gas reservoir. This divergence from the norm has resulted in considerable re-evaluation of existing techniques of gas reservoir analysis. This re-evaluation has been most noticeable in the area of abnormal pressured gas reservoirs.
Minerology of Montmorillonite Under Elevated Temperature and Pressure
Authors: Rieke Herman H.
Published: December 2007

Proper interpretation of the occurrence of clay mineral assemblages in Tertiary argillaceous sediments, containing abnormally high pressure zones, depends on understanding their diagenetic history. Of particular interest to petroleum engineers and geologists is the observed diagenetic conversion of montmorillonite to mixed-layered clay mineral forms under conditions of deep sediment burial at low geothermal temperatures (less than 500 deg.F). The origin of these clay mineral transformations may be related to the existence of the overpressured zones.

A series of pilot temperature-pressure laboratory experiments were employed to investigate the proposed transformation of montmorillonite to an inter-stratified layer arrangement of illite and montmorillonite. Samples of natural and pure sprayed-dried sodium montmorillonite (Wyoming bentonite) were saturated with distilled and substitute sea water, and treated with various chemical solutions before being run at pressures from 1,000 to 200,000 psig, under pH conditions from 0.5 to 13, and at autoclave temperatures up to 380 deg. F. The clay samples were exposed to these environmental conditions in both closed and open chemical systems from 7 to 21 days. The modification of the sodium montmorillonite structure to an illitic form did not take place under the above stated conditions. Apparently, time is an important factor in this conversion process and will have to be taken into consideration in future experiments. Evidence for non-conversion is based on X-ray powder diffraction studies, infrared absorption scans, and chemical analysis of the samples before and after each run. Results of these experiments are discussed and compared with data from previously reported field data and previously reported field data and temperature-pressure laboratory investigations on clays naturally occurring in sediments.
From Cost Reduction Towards Value Creation
Authors: Bakshi Ash
Published: December 2007

Introduction

There is a natural tendency to accord events in which we play a direct part with a greater and more widespread significance than they sometimes warrant. Nevertheless, in this paper it is asserted that the industry restructuring which has taken place in the North Sea over the last few years is as significant as any change the oil industry has ever witnessed. As a result, a level of competitiveness has been attained which should enable the UK oil and gas industry to lead the world in terms of wealth creation in the future.

In his paper to the CRTNE conference held earlier this year in Aberdeen, Heinz Rothermund, managing director of Shell UK Exploration and Production said, "The 1986 oil price crash, disruptive as it was at the time, was one of the best things that could ever have happened to us."

That the sustained fall in the oil price occurred around the same time as we began to view the North Sea as a mature province, laid the foundations for a fundamental reassessment of the way we went about our business. In essence, it was determined that the rate of development in the North Sea could not be maintained unless the industry as a whole adopted a single-minded focus on applying the competitive economic principles necessary to maximise the net present value of each hydrocarbon asset. One of the key notions was that the industry players - oil companies and service providers - were interdependent and needed to do far more in the way of sharing information, skills and resources.
Joint Industry Development of the Downhole Oil Water Separation System-Field Case Study - An Update
Authors: Schrenkel Peter J.
Published: December 2007

This paper is a description of a system which separates the produced oil and water in a high WOR (Water Oil Ratio) well, injects the produced water, and pumps the oil to the surface. The unique feature of this system is that the production, separation, and injection are all accomplished downhole, in one wellbore.

The benefits to the operator include decreased lifting and disposal costs and improved product margins and reserve recovery. Conceptual application and design, and actual field trial histories are discussed. This paper is an update of the paper presented at the SPE 1996 ESP Roundtable in Houston1.

Introduction

A primary reason for the abandonment of crude oil producing wells is the large volume of water which is produced in conjunction with oil. Water production increases power, disposal, maintenance, chemical, capital and many other costs associated with producing oil. Additionally, high water saturation near the wellbore may adversely affect the flow of crude oil into the wellbore through relative permeability effects. The net effect of this water production is decreased producing margin and fewer recoverable reserves.

C-FER (Centre for Engineering Research Inc.) and New Paradigm Engineering conceived the idea of running a Hydrocyclone separator in series with a downhole pumping system to accomplish oil production, oil/water separation, and injection of the produced water in one wellbore. C-FER was granted a patent on this technology and there are other patents pending by both REDA and C-FER.

In 1992, C-FER approached Vortoil Separation Systems and REDA, seeking their involvement in the development and field testing of Electric Submergible Pump (ESP) Separation Systems through a joint industry development project.

Thirteen units have been installed to date.

Benefits of Downhole Separation

The general benefits of downhole separation include decreased lifting and disposal costs and improved product margins and reserve recovery. Specific potential benefits of downhole separation include:Decreased power costsDecreased maintenance costsDecreased chemical costsDecreased environmental hazard
Developing a New Discovery as a Very Large Underground Gas Storage Reservoir
Authors: Damm M.
Published: December 2007

The Dutch gas market, comprising some 80 mrd nm3 (2.8 Tscf) of annual production, is structured based on a government policy promoting small field developments. These are given priority over the giant Groningen gas field, which serves as a swing producer to supply the difference between market demand and production from other Dutch fields and inputs. To fulfil this role, the Groningen field has to provide a capacity of some 450 mln nm3/d (16,000 MMscf/d).

Owing to field depletion the Groningen capacity is declining, resulting in additional capacity measures being required. Due to changes in the gas market, which lead to increased depletion of the Groningen field, capacity shortages were brought forward, resulting in three underground gas storage reservoirs having to be developed within severe time constraints. The time frame available to bring the first of these on-stream did not allow for the filling up of a depleted reservoir, and a new discovery therefore had to be used.

The most suitable undepleted field, the Grijpskerk field, had a number of very significant uncertainties, including: Complex overburden; evidence of compartmentalisation; diagenetic impairment; and the need to lean-up the indigenous gas within the first few years of operation by re-cycling. Managing these uncertainties required the use of a number of novel techniques, including pre-stack depth migration, nuclear magnetic resonance logging, as well as very flexible development planning.

Six new wells have been drilled, combining appraisal and development objectives, while adjusting the subsurface picture during the campaign. The plant was successfully brought on-stream January 1, 1997, with 8 wells capable of delivering in excess of 8 mln nm3/d (280 MMscf/d) each. It will eventually have a capacity of 80 mln nm3/d (2,800 MMscf/d) and the reservoir can handle an annual working volume in excess of 2 mrd nm3 (70,000 MMscf).
On The World Energy Requirements And The Need For An International Energy Policy
Authors: Sapre A.R. , Schoeppel R.J. , Sadiq S.
Published: December 2007

This up-to-date study of the supply and demand of world energy resources is based on an analysis of the regional and global changes in the pattern of energy production and its consumption during the last two decades.

Since World War II, nations of the world have aspired to achieve the common goal of a higher and higher standard of living. This desire for higher affluence coupled with a population explosion have more than doubled population explosion have more than doubled the rate of energy consumption during that period. Technological growth and its spread period. Technological growth and its spread around the world has also contributed to this demand for energy. Changes in the patterns of availability and relative prices of energy resources have affected patterns of interfuel substitution and continue to affect the demand for oil and gas. During the last few years environmental concern has become a major issue further affecting the consumption patterns of energy resources.

Projections of the world energy requirements in years 1980 and 2000 are based on implicit correlations of one or more influencing factors such as population, GNP, personal income, technological innovations, and interfuel substitution.

Regional supplies of energy resources are viewed in relation to their demand and their future influence on the world energy situation. The importance of disparities in petroleum source-markets are shown to be of petroleum source-markets are shown to be of utmost importance in formulating national energy policies.

Finally, a "system" approach to global demand and supply of energy resources is suggested with a proposal for an International energy policy.
Meeting the 10km Drilling Challenge
Authors: Modi S. , Mason C.J. , Tooms P.J. , Conran G.
Published: December 2007

This paper discusses the planning and preparation process for drilling and completing a 10km departure well at the Wytch Farm Oilfield in Southern England.

An 8km departure well was drilled at Wytch Farm during 1995. At the time, this was at the limit of drilling operations. Some fundamental changes involving new technology, operational practices and techniques have been necessary to enable this well to be drilled.

More specifically, the paper will describe the directional drilling techniques necessary to enable the reservoir interval to be accessed. Research and development work performed by the drilling team to identify mechanical limitations in drilling operations at this departure are also examined. This includes a comprehensive review of offset well data to determine friction factors for all operations and concomitant measures adopted to limit rotary torques and drags to workable levels. The other major focus of this paper is to appreciate the mechanism by which drilling muds are lost to the permeable reservoir and describe methodologies employed to overcome this problem.

The paper will also discuss recent experience with the application of partially floating casing, rotary steerable drilling systems and running and cementing long liners.

Completion and intervention challenges are also examined with an analysis of future requirements.

Introduction

The development of the offshore extension of the BP operated Wytch Farm Oilfield, located on the South coast of Britain, utilising extended reach (ER) wells into the offshore part of the Sherwood sandstone reservoir has been extensively documented in a series of technical papers [1], [2] and [3]. (Figure 1). The current phase of the development is to tap into significant reserves located at reservoir departures in excess of 10km.

The Drilling Challenge.

The section of the reservoir targeted by this Ultra-Reach well (Measured Depth : True Vertical Depth ratio >5), M-11, lies between 8km and 10km departure from the 'M Wellsite' where the Deutag T-47 rig is located. This site, specially constructed to access the offshore portion of the reservoir currently contains 10 extended reach wells and yields over half of the total 110,000 bopd production at Wytch Farm.

The challenge is to safely and efficiently drill and complete a 10km departure well into the target area to access oil in place of 24mm STB. A single horizontal well into this target is expected to recover some 25–35% of these reserves. Although this is likely to be the most expensive well drilled at Wytch Farm, the significant reserves that it will access are critical to the long term profitability of the field. The well design is the culmination of over a year's evaluation, design and planning, providing an excellent test of the industry's capabilities. Successful delivery of this well will have a significant impact on the industry to access reserves that a decade ago would have required major capital expenditure, in the shape of new facilities, to recover.

P. 191^
Polymer-Free Fluid for Hydraulic Fracturing
Authors: Samuel Mathew , Card Roger J. , Nelson Erik B. , Brown J. Ernest , Vinod P.S. , Temple Harry L. , Qu Qi , Fu Dan K.
Published: December 2007

Polymer residues that stay in the fracture after a hydraulic fracturing treatment can limit treatment effectiveness. A new and easy-to-prepare, polymer-free fluid that consists of a quaternary ammonium salt derived from a long-chain fatty acid is described. In brine, it builds viscosity due to the formation of highly entangled worm-like micelles. The micelles have a gross structure similar to a polymer chain. Since the viscosity of the fluid depends on the nature of micelles, the fluid can be broken by changing this micellar structure. The breaking occurs when the fluid is exposed to hydrocarbons or diluted with formation waters. Therefore, conventional breakers are not required, and the produced oil or gas can act as breakers for this fluid system.

The structural characteristics of the polymer-free surfactant fluid to its chemical and physical properties are correlated in this paper. Structure, rheology, fluid loss and conductivity of this surfactant fluid together with its production data are presented.

Introduction

Fracturing fluid is a very critical component of a hydraulic fracturing treatment. Selection of the fracturing fluid, job design, and well turnaround procedure all help to determine the production of a well after a stimulation by hydraulic fracturing. A fracturing fluid should provide sufficient viscosity to suspend and transport proppant into the fracture, and should break into a low-viscosity fluid after the job is completed. This will facilitate the fracture to clean up by allowing rapid flowback of fluid to the surface.

Analysis of the fluid returned to the surface (flowback fluid) after hydraulic fracturing indicates that as little as 30 to 45% of the guar-based polymer pumped during the treatment returned from the well during the flowback period. Polymer residues that remain in the fracture significantly contribute to a lowered proppant-pack permeability leading to a loss in fracture treatment effectiveness.

The field success of a viscoelastic surfactant-based (VES) polymer-free fluid in frac-pack applications led to the development of a similar fluid for hydraulic fracturing.

The VES fluid can be used for the fracturing treatment of potentially all gas and oil wells below 240 F. The principal advantage of this fluid system is its operational simplicity. This fluid is easy to prepare and requires less equipment at the wellsite This fluid does not require polymer hydration, biocides, crosslinkers, or breakers. The hydrocarbons produced, or dilution of VES gel by other formation fluids, can break this fluid.

This new fluid has been used for the successful execution of more than 250 fracturing jobs. Results from representative treatments are presented.
Application of a Monte Carlo Technique in Gas Plant Design
Authors: Guttormson Dean L. , Snyder Louis J. , Palmatier Everett D.
Published: December 2007

This paper describes two illustrative examples demonstrating the application of Monte Carlo techniques to gas process design. In addition, a detailed discussion is presented of the characteristics of the Monte Carlo procedure. In the first example Monte Carlo procedure. In the first example Monte Carlo simulation is used to determine the distribution of required MEA circulation rates to sweeten gas in a proposed installation. A simple problem formulation is used; therefore, it is possible to test the sensitivity of the calculated circulation rate distribution to the number of Monte Carlo events and to the selected probability distribution. In the second example, the probability distribution. In the second example, the optimum size of a lean oil absorption plant is determined. Feed rate and composition together with product prices are selected as random variables. Distributions of present-value profit are generated for several plant sizes. profit are generated for several plant sizes. Optimum plant size is selected to maximize the mean present-value profit.

Introduction

In designing gas processing facilities, plant size or capacity must be established prior plant size or capacity must be established prior to determining process configuration and operating conditions. Establishing the optimum capacity is complicated in that plant inputs and economic constraints, such as feed volume and composition, product price, and equipment operation, may not be known with certainty. This paper demonstrates use of Monte Carlo techniques in gas plant design problems when system inputs are uncertain.

To use Monte Carlo techniques in analyzing gas processing projects, plant inputs and economic constraints that characterize the project must first be defined. These project project must first be defined. These project parameters fall into two classes: deterministic parameters fall into two classes: deterministic and stochastic variables. Deterministic variables have a known value, but can vary with time (e.g., the gas price in a long-term gas sales contract). Stochastic variables are not known with certainty and are described by a probability distribution spanning a range of probability distribution spanning a range of values. For most variables a triangular distribution adequately relates the value of a stochastic variable to its minimum, maximum and expected value.

Next, appropriate yardsticks for comparing investment decisions must be selected. Present-value profit and investor's interest rate are Present-value profit and investor's interest rate are commonly used economic yardsticks. It may be preferred to use key process variables, plant preferred to use key process variables, plant investment, or product output to characterize performance so that the result may be used in a performance so that the result may be used in a subsequent economic analysis.
Cement Evaluation and Casing Inspection With Advanced Ultrasonic Scanning Methods
Authors: Graham W.L. , Silva C.I. , Leimkuhler J.M. , de Kock A.J.
Published: December 2007

This paper will demonstrate cased-hole applications of a new ultrasonic scanning tool. Field logs are presented from environments containing various wellbore, casing, and cement slurry types. Cement evaluation and casing inspection examples will include logs from wells with heavy completion fluids, lightweight cements, heavyweight casing, and hastelloy pipe (used in highly corrosive environments).

Very high horizontal and vertical sampling rates permit simultaneous cement evaluation and casing inspection. The data are corrected for direction and tool rotation using a navigation package. Data such as acoustic impedance, cement compressive strength, casing thickness, casing outer diameter and/or radius, casing ovality, tool eccentricity, and 40 to 100 calipers may all be recorded in real time in conventional or imaging formats. Improved processing software provide two- and three-dimensional images.

It was observed that differing wellbore and casing conditions require different logging parameters (such as scan rate and sample density). Thus, the mechanical and electrical configuration of the tools are flexible to maximize signal response in all possible downhole conditions. Multiple scanning heads with selectable transducer characteristics are available. Downhole processing also reduces telemetry demands and allows other tools to be combined with the new scanning device to provide additional real-time data without reducing logging speed or delaying analysis processing until after logging.

Introduction

Downhole ultrasonic scanners have been used primarily for imaging wellbores. A new scanner that furnishes improved images and that offers remarkable casing inspection and cement evaluation capabilities has been developed and field proven. The new device operates in two modes: image mode and cased-hole mode.

In image mode, the scanner evaluates only the "inner" surface of the target (the formation bounding the wellbore or the inner wall of the casing). High vertical and azimuthal sampling provides high-resolution, two and three-dimensional images. These images are useful in locating fractures, identifying borehole breakout, delineating bed boundaries, studying formation textural features along the borehole wall, and evaluating casing integrity by revealing distortion, wear, holes, parting, and other anomalies on the inner wall of the casing.

When cement evaluation or a more complete casing assessment is needed, the ultrasonic scanner operates in cased-hole mode. The full circumferential maps of casing thickness and acoustic impedance generated from the measurements made in this mode can be used to reveal thinned casing and to clearly distinguish between cement and fluids in the annular space behind casing. In cased-hole mode, a significant part of the acoustic waveform is processed. Thus, high telemetry data rates, intense processing capabilities, and selective transducer frequencies are required.
Influence of Areal Anisotropy on Horizontal Well Performance
Authors: Yildiz Turhan , Ozkan Erdal
Published: December 2007

The objective in this paper is to investigate the influence of well orientation and areal anisotropy on the transient pressure response of a horizontal well whose axis deviates from the principal areal permeability directions. The investigation is based on an analytical solution in Laplace space. It is observed that areal anisotropy and well azimuth angle have a substantial effect on transient pressure behavior especially at early and intermediate flow times. If the well axis is not normal to the maximum permeability direction, the intermediate time linear flow does not appear.

Synthetic drawdown tests were analyzed to estimate the principal permeabilities and skin due to damage using conventional straightline methods. The estimated principal permeabilities from the simulated tests significantly deviated from the input values due to azimuth angle. However, the estimated geometric mean areal permeability (kH=kxky) and 3D equivalent system permeability (k=kxkykz3) agreed well with the input values.
Determination of Pressure-Transient and Productivity Data for Deviated Wells in Layered Reservoirs
Authors: Larsen Leif
Published: December 2007

Analytical methods are presented to determine pressure-transient and productivity data for deviated wells in layered reservoirs. The computational methods, which are based on Laplace transforms, can be used to generate type curves for use in direct analyses of pressure-transient data and to determine the effective skin of such wells for use in productivity computations.
Early Determination of Reservoir Flow Units Using an Integrated Petrophysical Method
Authors: Gunter G. W. , Finneran J. M. , Hartmann D. J. , Miller J. D.
Published: December 2007

This paper uses case histories to introduce a graphical method for easily quantifying reservoir flow units based on geologic framework, petrophysical rock/pore types, storage capacity, flow capacity, and reservoir process speed. Using these parameters and four graphical tools, this paper outlines a quantitative approach to transform rock-type-based zonations into petrophysically based flow units that can be input into a numerical flow simulator. This method provides a tool for determining the minimum number of flow units to input into a numerical flow simulator that honors the foot-by-foot characteristics at the wellbore.

A flow unit is a stratigraphically continuous interval of similar reservoir process speed that maintains the geologic framework and characteristics of rock types. Rock types are representative reservoir units with a distinct porosity-permeability relationship and a unique water saturation for a given height above free water level.

The ideal data for this method is continuous core porosity, permeability, and saturation information drawn from throughout the entire reservoir. If such a data set is not available, it is necessary to calibrate wireline log data with core information to produce reliable estimates of porosity, permeability, and saturation. A full discussion of these data transforms are beyond the scope of this paper.

The four graphical tools used to determine flow units are: Winland porosity-permeability cross plot, Stratigraphic Flow Profile (SFP), Stratigraphic Modified Lorenz Plot (SMLP) and Modified Lorenz Plot (MLP).

This method begins by establishing rock types within a geologic framework. The geologic framework allows the flow units to be interpreted within a sequence stratigraphic model determining well-to-well correlation strategies. The key flow unit characteristics to be identified are barriers (seal to flow), speed zones (conduits), and baffles (zones that throttle fluid movement).

This integrated, petrophysically based method of determining flow units has been successfully used in a wide array of reservoirs. We have applied it to young, unconsolidated sediments; structurally complex naturally fractured/vuggy carbonates; low permeability "tight" formation gas sands; diagenetically altered carbonates; complex mixed lithologies; and interbedded sand-shale sequences.

The earlier in the life of a reservoir this process is used, the greater the understanding of future reservoir performance. This method allows the user to employ the least number of flow units and honor the character of the foot by foot data for simulation studies.
Evaluation of a Gas Well Testing Method
Authors: Lee John W. , Harrell Robert R. , McCain William D.
Published: December 2007

In principle, drawdown tests provide data that allow a complete characterization of a gas well. Unfortunately, rapid analysis of drawdown test data is generally regarded as possible only for the special case in which production rate is maintained strictly constant for the duration of the drawdown test. In many tests, constant production rates are either inconvenient or impossible to maintain; analysis of data from such tests has been thought to require the tedious use of superposition, which, as a practical matter, means that a computer must be used practical matter, means that a computer must be used to perform the necessary arithmetic.

Actually, a technique for analyzing variable-rate drawdown test data easily and rapidly has been in the literature since 1965. This method, proposed by Winestock and Colpitts, is virtually as rapid as conventional techniques used to analyze constant-rate drawdown tests; and it provides estimates of formation permeability-thickness product, skin factor, and permeability-thickness product, skin factor, and turbulence effects. Knowledge of these parameters allows more accurate predictions of current and future deliverability of a tested well than are usually possible with conventional back pressure tests or isochronal tests.

This paper reports the results of a study which was performed to test the validity of the analysis technique proposed by Winestock and Colpitts. The study, which was based on a numerical simulation of the pressure-production history of a gas well, showed that the analysis technique of Winestock and Colpitts is indeed valid for pressure drawdown data obtained with smoothly varying production rates.

Introduction

To completely characterize a gas well, a testing program should provide an estimate of reservoir permeability-thickness product, information about the extent of well damage, information leading to estimates of the possible effect of stimulation, and deliverability. Unfortunately, conventional gas well testing methods do not provide all this information. For example, the most common method is the Back-Pressure Test. This test has two major weaknesses: First, this test, at best, provides only deliverability estimates, and gives none of the other information needed to completely characterize a gas well.
Reservoir Modeling Using Scale Dependent Data
Authors: Panda M.N. , Mosher C. , Chopra A.K.
Published: December 2007

A reservoir description incorporating the precision and scale of all available data (geological, petrophysical, seismic, tracer and well test data) is critical for reservoir modeling. The heterogeneous variables sampled by these data are composed of several superimposed random functions, each characterized by a unique spatial and temporal scale or support. For example, core, well log, well test and seismic data have supports ranging from inches to thousands of feet.

Current geostatistical methods map lithofacies, porosity, and permeability on a network of grid nodes called the geologic modeling cells. Pseudo point properties that assimilate information from all available data are modeled onto model cells using one of several available conditional simulation techniques. Some methods attempt to combine data with varying support and data with multiple scale support through simple correlations. For example, one approach to incorporate geophysical data is to use a direct transform of the seismic signal to rock properties through a linear regression or crossplot. Reservoir models built using such linear correlations tend to be case specific with little generality.

This paper presents a method for identifying the impact of multi-scale data (data that measure average property over multiple flow units) on reservoir modeling. It examines the information about the reservoir system each data type carries. For example, what fraction of core scale variability is captured by well log data. We also present a consistent method for integrating multi-scale data. Through a series of numerical simulations, we show the impact of heterogeneity of reservoir properties on the fluid flow performance.

Introduction

Reservoir modeling is a systematic approach to estimate constitutive properties based on a few experimental observations. In other words, it is an algorithm that produces multi-dimensional distribution of rock properties forming a prototype of the actual reservoir. The main goal is to impose the same boundary conditions as in the reservoir and obtain actual responses. The benefits are that once an appropriate model is formed it can be examined for a variety of boundary conditions.
Conjugate Fracture Zones: Potential "Sweet Spot" Reservoirs Within Regional Parallel-Fracture Systems
Authors: Lorenz John C.
Published: December 2007

The mesh of permeability that can be provided by sets of intersecting conjugate fractures offers significant conductivity within a reservoir. This plumbing system will be an enhancement over not only matrix permeability values, but also over the permeability provided by related sets of sub-parallel, bed-normal, regional extension fractures. Conditions under which regional extension fractures have developed locally into conjugate fractures are described, offering possible exploration scenarios. Conjugate fractures may occur as bed-normal fractures with a vertical axis of intersection or as steeply inclined fractures with a horizontal axis of intersection, depending on the orientation of the principal stresses during fracturing. Increases in stress magnitudes and anisotropy during production drawdown of reservoir pressures may cause shear offsets along conjugate fractures. This will further enhance the fracture permeability, but only up to the point at which fault gouge begins to develop. Conductivity will not be enhanced, however, where conjugate fractures developed as deformation or shear bands, which are typically permeability barriers.
Techniques for Measuring Wax Thickness During Single and Multiphase Flow
Authors: Chen X. T. , Butler T. , Volk M. , Brill J. P.
Published: December 2007

Accurate measurement of wax thickness deposited on a cold pipe wall is of vital importance to the development of predictive models for paraffin deposition in flowlines and wellbores. Existing wax thickness measurement techniques, including pigging, spool piece, pressure drop, and heat transfer methods, are critically reviewed. An on-line wax thickness measurement technique, named the liquid displacement-level detection method (LD-LD), is presented. This new method is capable of giving both longitudinal and circumferential wax thickness distributions as well as the total wax deposit volume for single-phase and multiphase flow in pipes.
Diffusion of Advanced Stimulation Technology in the Petroleum Industry: A Case History
Authors: Wolhart S.L. , Hill D.G. , Smalley E.A.
Published: December 2007

In 1995, Gas Research Institute undertook an aggressive technology transfer program to deploy the results of over a decade of research in the area of hydraulic fracturing. The program was called the Advanced Stimulation Technology (AST) Deployment Program. The intent was to transfer advanced fracturing technology as widely as possible to the natural gas industry through programs with producers and service companies focused on education, training, demonstration and documentation. The goal was to disseminate the technology on a level such that, if beneficial, it would continue to be practiced beyond completion of the GRI program. AST incorporates a process of data collection, real-time analysis and onsite job optimization into the design, implementation and evaluation of hydraulic fracturing. Several of the critical concepts involved in this process include:real-time analysis,quality control,stress profiling androck mechanics.

Based on field results, AST can have a significant impact on well productivity and completion costs. Companies have documented fracturing cost savings of up to 50% and/or well performance improvements of up to 300%, depending on current practices and conditions. The average improvement is a 20% reduction in treatment cost and a 25% increase in production, although not necessarily on the same well at the same time. This paper focuses on the key components involved in new technology diffusion, technology transfer barriers and the strategy GRI used to overcome these barriers.

Introduction

Moving a technology or innovation from an idea to widespread acceptance is often very difficult. This process can be a lengthy one, and accelerating the time to market acceptance has been an area of intense study. Technology diffusion can be defined as the process by which an innovation is communicated through certain channels over time among the members of a social system. The rate of technology diffusion or dissemination is controlled by many factors which are defined by both the innovation and the user or adopter. The decision to adopt an innovation is based on the perception of the innovation by the adopter and can be characterized by five qualities:Relative advantage - how much better is the innovation than the idea it supersedesCompatibility - is it consistent with existing values, past experiences and needs of the potential adopterComplexity - how difficult is it to understand and useTrialability - can it be experimented with on a limited basis, andObservability - are the results of the innovation visible to others.

Research has shown these qualities to have the greatest influence on the rate of adoption. Innovations that are perceived by individuals as having greater relative advantage, compatibility, trialability, observability and less complexity are adopted more rapidly than other innovations.

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State of the Industry in CO2 Floods
Authors: Grigg Reid B. , Schechter David S.
Published: December 2007

Every other year the Oil and Gas Journal presents a summary of worldwide enhanced or improved oil recovery (EOR or IOR) methods and current production.1 Other papers review EOR technologies and present U.S.A.ge, both in the US and worldwide.2,3 Our intent was not to duplicate this type of documentation but to review CO2 as a maturing EOR process and to assess what was going well in the field as well as what was not going well, to identify research opportunities, and to develop correlations between problems encountered and solutions developed. A survey was sent to a number of engineers responsible for day to day operations of CO2 floods. This paper reviews the response received concerning 25 projects. Represented in the responses are experiences from 25 fields by 19 different engineers employed by nine oil companies.
Analysis And Interpretation Of The Water-Oil Ratio In Waterfloods
Authors: Yortsos Yannis C. , Choi Youngmin , Yang Zhengming , Shah Piyush C.
Published: December 2007

An important problem in water control is the identification of the dominant reservoir or production controls (for example, channeling or water coning). Recently, Chan (1995) postulated that a log-log plot of the produced WOR vs. production time may be used to diagnose these factors. In this paper we provide analytical and numerical results for a variety of waterflood conditions to explore this possibility.

We show analytically that the late-time slope of the log-log plot can be related to the well pattern, the relative permeability characteristics, specifically the power-law exponent in the kro - Sw relationship or the reservoir heterogeneity. Analytical results are also provided for the behavior immediately following water breakthrough. In certain simple cases (mobility ratio equal to one, layered systems), analytical type curves can be derived. In the general case, we use numerical simulation to provide numerical type curves.

The results are summarized in terms of the various power-law scalings in different time regimes and by a catalogue of numerical type curves. They confirm the potential of WOR-time plots as diagnostic tools for reservoir analysis and characterization.

Introduction

An important problem in water control is the identification of dominant reservoir or production factors (for example, channeling or water coning) from produced water-oil data. Water production can be the result of a natural water-drive, edge- or bottom water-drive or a waterflood. Despite its relevance, however, the problem has received rather scant attention in the literature so far. Aspects of waterflooding under various conditions have been extensively described in the literature (e.g. see the SPE monographs of Craig, 1971, and Willhite, 1986). Limited, however, are studies on the dependence of WOR on production time. Ershaghi and Omoregie (1978) proposed the so-called X-plot, to interpret and extrapolate water-oil production. In this approach, a combination of the fractional flow function was found to vary linearly with time, in an appropriate semi-log plot. The X-plot method successfully matched various field data.

In a more recent study, Chan (1995) used numerical simulation to examine the sensitivity of the curve of produced WOR vs. production time on various reservoir and production factors. He conjectured that a log-log plot of this curve can be used to diagnose the origin of the water production, and specifically to determine whether it is due to channeling (heterogeneity) or to coning. An essential part of this conjecture is that a log-log plot of WOR vs. production time contains linear segments, the slopes of which are different in the cases of channeling or coning, hence they can be used for diagnostic purposes. No expressions for these slopes were postulated or derived, however. Chan's conjecture is presumed to have strong support from numerical simulations and field data.

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