bluuebunny/crossref_metadata_2025 huggingface dataset:
Predicting the Quality and Performance of Oilfield Cements Using Artificial Neural Networks and FTIR Spectroscopy
Authors: Fletcher Philip , Coveney P. V. , Hughes T. L. , Methven C. M.
Published: December 2007

Inherent batch to batch variability, ageing and contamination are thought to be major factors contributing to variability in cement slurry performance. Of particular concern are problems encountered when a slurry is formulated with one cement sample and used with a batch having different properties. This situation occurs regularly in operations. Such variability imposes a heavy burden on performance testing and is often a major factor in operational failure.

Methods are described herein which allow the identification, characterisation and prediction of cement variability for Class G, Class A and Class H cements. Specifically, the technique involves predicting cement compositions, particle size distributions and thickening time curves from the Diffuse Reflectance Infrared Fourier Transform (DRIFT) spectrum of neat cement powders. Predictions are based on either linear statistical procedures or non-linear Artificial Neural Networks (ANNs).

For some simple slurry formulations thickening times can be predicted with uncertainties of less than ±10%. Composition and particle size distributions can be predicted with uncertainties a little greater than measurement error but general trends and differences between cements can be determined adequately.

The results establish the infrared spectrum of cements as a ‘signature’ of cement performance and composition since it yields subtle information on the nature and condition of the cement which is not given by API measurements.

A summary of the main features of this technique is as follows: Predicts the performance of some cement slurriesDetects the presence of major contaminantsPredicts cement composition and particle size distributionsIdentifies the nature and extent of cement ageingPredicts the effect of ageing on slurry performanceIdentifies and quantifies differences between cement samplesDifferentiates cement/silica blends from neat cementsDetects non-API cements

The potential benefits of the technique can be summarised as follows: Improves the assessment of cement quality or expected cement performanceHelps avoid operational failures due to batch to batch variation, ageing or contaminationEstablishes a basis on which to reject or accept cementsHelps to identify suitable local cements in new locationsImproves the efficiency of formulation design by identifying performance characteristics of cement

The objectives of the paper are (a) to review the factors controlling cement hydration and variability, and show that many of these properties are captured within the FTIR spectrum of cement and (b) to show that performance and composition can be predicted from spectra using suitable statistical techniques. Several cases studies are given to emphasise the use of the techniques.
In-Situ Wettability Determination: Field Data Analysis
Authors: Causin Emilio , Bona Nicola
Published: December 2007

Rock wettability may explain some apparent discrepancies that occur in defining water-oil contacts by RFT and logging measurements. Analysing these discrepancies makes it possible to estimate the wettability state of the reservoir. This paper presents the studies carried out on three oil reservoirs in order to check the applicability of this method. The major limitations are identified. All results are confirmed by laboratory wettability tests.
The Markham Field, A Trans-Median Development
Authors: Sharples D. M. , Myres J. C. , Morgan C. L. , Kuzemko N. C. J.
Published: December 2007

The Markham project is unremarkable by most current project benchmarks. It is not a marginal field and it is being developed with essentially conventional technology. It does however differ from most conventional developments in several key areas. It is the first field to be developed which straddles the UK/Netherlands median line and needed a treaty. A coordinated response from both the UK and Netherlands governments was therefore required to ensure that a treaty would be in place in time for production to commence on schedule.It is the first field involving the export of UK gas to continental Europe. It is also one of a very few fields in the UK or Netherlands to produce gas under various contracts.The reservoir quality varies in a general North West-South East direction across the UK/Netherlands median line. This led to concerns that distribution of recoverable reserves would be different to that of Gas-in-Place. This resulted in a variation on standard equity determination methodology.

Its geographic location is noteworthy in that it lies along the northern margin of the Rotliegendes sandstone fairway at some distance from any other known Rotliegendes field of a significant size.
Predicting Gas Saturation Buildup During Depressurisation of a North Sea Oil Reservoir
Authors: Scherpenisse Wim , Wit Krijn , Zweers A. E. , Shoei Gert , van Wolfswinkel Avend
Published: December 2007

When a waterflooded oil reservoir is to be depressurised, it is important to predict the production of solution gas from the by-passed and trapped oil. To quantify the gas saturation build-up and the relation between gas mobility and gas saturation, We have carried out a large number of experiments on core samples. These pressure-depletion experiments, which were conducted at various depletion rates and with both model fluids and actual reservoir fluids, began from one of two starting conditions: reservoir rock at initial conditions (i.e. containing oil and connate water) or watered-out reservoir rock (i.e. containing brine and residual oil). Relating the experimental results to field conditions was a major concern for two reasons: The experimental results were sensitive to the depletion rate (and the field depletion rate is two orders of magnitude lower than what was possible in the laboratory).The experimental results were sensitive to the fluid/rock system used.

In this paper we discuss the interpretation of the experimental results and the approach we have adopted for extrapolating them to field conditions, so that the reservoir engineer can assess their practical consequences for field development. We found that when the experiments were run starting under initial reservoir conditions, the nucleation properties of the fluid/rock/pressure combination, together with the depletion rate, determine the gas saturation build-up. To extrapolate such laboratory results to the pressure-decline rate of the field, it is essential that the experiments be conducted with reservoir fluids at reservoir pressure and temperature. When the experiments were run under watered-out conditions, no such dependency on nucleation properties was found. Instead, the mobility of the gas could be correlated with the total hydrocarbon saturation, the same correlation applying to different fluid/rock/pressure combinations.
A Study of the Physical Mechanisms of Sanding and Application to Sand Production Prediction
Authors: Cook J. M. , Bradford I. D. R. , Plumb R. A.
Published: December 2007

The complications involved in understanding and predicting sand production are discussed. The need to predict sanding potential on a foot-by-foot basis means that a simplifying approach is required, and this paper sets out experimental and initial modelling progress in this direction.

We have induced sand production in simple, reproducible and easily monitored systems, in order to be able to vary one parameter at a time and examine its effect. This has meant the use of synthetic rocks, moulded rather than perforated holes, and two simple geometries.

The effects of stress, flow rates, fluid viscosity and rock strength have been examined so far. For the high permeability rocks used in the experiments, the stresses in the rock produced by radial flow into the perforation tunnel have little influence on sanding; flow along the axis of the tunnel is found to be the controlling flow. This allows the sanding problem to be split into the prediction of damage around the tunnel induced by far-field stresses, and the transport of damaged material by axial flow.
Porosity as a Geomechanical Indicator: An Application of Core and Log Data and Rock Mechanics
Authors: Farquhar R. A. , Somerville J. M. , Smart B. G. D.
Published: December 2007

There is a growing awareness among petroleum engineers of the value of rock mechanics based analytical approaches to wellbore stability and sand production problems. It is readily accepted that the key to successful engineering lies in the acquisition of reliable data. Geomechanical properties testing is often perceived, however, as being expensive. All to often only limited numbers of samples are tested. This paper demonstrates how porosity can be employed as a geomechanical index to enable rock mechanics materials properties to be estimated using general and field specific correlations. Such an approach can be used to extend the application of a limited number of calibration samples.

General correlations exist between porosity and the uniaxial compressive strength and Young's modulus of sandstones and carbonates. Most of the work reported in the literature has concentrated on correlating porosity with absolute values of mechanical properties. Strength is, however, a stress sensitive property, increasing as confining stress increases. It is shown that porosity correlates with the constants required to construct theoretical and empirical failure criteria which describe such behaviour. Porosity also reflects other geomechanical characteristics of sedimentary rocks including failure mode, fracture intensity, drilling rate and perforation penetration.

The utility of porosity as a geomechanical index enables existing core and log data to be utilised to extend the use of limited core material.
Single-Well Wideband Borehole Seismics in the UNIWELL Configurations: An Approach to Monitoring Hydrocarbon Production
Authors: Peveraro R. C. A. , Leavy P. C. , Crampin Stuart
Published: December 2007

We present the technical basis for bridging the wide structure data-gap at the heart of the oil and gas production business: the scale of geological detail in the range between a few tens of centimetres to a few meters. This scale range is at least an order of magnitude smaller than is resolvable with current means. Many reservoir properties such as permeabilities are largely determined by the microscale behaviour of pore geometries and pore throats in the range down to millimetres or less.

The underlying unifying concept is that broadband vector seismic data contain a wealth of information regarding rock fabric and fluid content. Careful seismic field experiments, observation and data analysis can bridge the gap in the spatial knowledge of the reservoir between the very detailed, but laterally very limited information provided by borehole logging data and the spatially extensive but diffuse structural information provided by 3D seismic data. Measurements obtained in boreholes and aimed specifically at capturing certain elastic formation parameters are related through the geophysical model to reservoir parameters of direct engineering and economic interest in a series of "snapshots" of in situ distributions of fluids and rock masses, taken at opportune moments in the life of the reservoir and representing a substantial amount of reservoir volume in centimetre to metre detail.
Detailed Stochastic Modelling of a Proximal Fluvial Reservoir With Realizations Used in Flow Simulation
Authors: Svanes Tarald , Karstad P. I. , Myking Beate , Hovland Frank , Madsen Martin
Published: December 2007

Fluvial heterogeneities have been modelled for the highly heterogeneous Ness Formation of a field in the North Sea, using a marked point stochastic process. This paper describes the geological modelling and the flow simulation work done. The uncertainty in the geological parameters is large and of vital importance to the production of the formation. Therefore stochastic modelling has been applied to evaluate different sedimentological hypothesis by varying the input model parameters. Via upscaling and flow simulation the effect on reservoir behaviour has been quantified and better understanding of the geological uncertainty obtained.

Stochastic modelling is a bridge between geologists and reservoir engineers. The reservoir models are easily changed in a geologically consistent way giving better history match. This integrated modelling project led to technical developments in the modelling tool in order to improve the results.
HAZOP Implementation on a Major North Sea Project, the Ninian Third Party Entrants Project
Authors: King S. D. J. , Killick R. C. , Bonner Michael , Gilbert T. J.
Published: December 2007

The paper will provide an insight into the role of HAZOP in a complex North Sea project involving three significant new sub-sea developments - Lyell, Staffa and Strathspey - operated by third parties and tied back to two existing Ninian platforms, Central and Southern. Major platform modifications were required involving both new process systems and the revamping of existing facilities, all whilst maintaining existing production. This presented substantial technical, project and safety related challenges of a type not hitherto encountered by North Sea operators. An integral part of the project plan was the comprehensive use of HAZOP as a core activity in ensuring that corporate safety and project operability objectives were met. HAZOP was seen as an important element in Chevron's Ninian Safety Case as the primary tool for hazard identification. The successful application of HAZOP in this complex ‘brown field' development required a range of measures, some often overlooked and some involving innovative HAZOP methodology and these are detailed.
Conceptual Design for HP/HT Surface Development Wells
Authors: Bacarreza L. J. , van Melsen R. J. , Jantschy G.
Published: December 2007

This paper outlines the completion design for a High Pressure High Temperature (HP/HT) platform development well. It presents the design philosophy, a brief evaluation of the existing HP/HT well completion technology and suggests further equipment and materials development.

The objective is to present a simple and reliable preliminary well design, that will reduce costs and the need for well intervention.
Use of Well Test Analytical Solutions for Production Prediction
Authors: Bourgeois M. , Couillens P.
Published: December 2007

Using well test analytical solutions for production prediction is rarely done, as this seems to be abstract and to require assumptions that are not very physical. But it presents a good alternative to numerical simulation, which is often expensive and cumbersome, and to decline-curve analysis, which has little theoretical justification in complicated cases.

This paper presents existing methods, and generalizes them to "n" wells in the reservoir. This allows the prediction of the flowrate produced for a given pressure drop history and a given global drainage area, but without a priori knowledge of the drainage area of each well. This is especially useful in reservoir monitoring.

This work shows how changes in the imposed pressure drop can be treated, which is straightforward, as it does not affect the reservoir response. But il also shows how non-linearities, i.e. changes in the well or reservoir themselves can be treated. To some extent, this technique allows modelling phenomena which are non linear, but still classic during the life of a well: fracturing, damage, or change in skin due to the appearance of multiphase flow.

This technique thus broadens the applicability of analytical production prediction.
Analysis of Interwell Tracer Flow Behaviour in Transient Two-phase Heterogeneous Reservoirs Using Mixed Finite Element Methods and the Random Walk Approach
Authors: Yi T. , Daltaban T. S. , Archer J. S.
Published: December 2007

This paper presents a new numerical approach which models interwell tracer flow paths in transient two-phase flow in heterogeneous porous media. The approach adopted is sequential in that the velocity and pressure fields are solved simultaneously using a mixed finite element approach, the phase saturation is solved by mass balance, and then the tracer is transported and its concentration at the production well is predicted using a random walk model. Mass conservation has been achieved throughout all the numerical procedures.

Comparative studies between conventional finite difference methods and the methods presented in this paper show a significant reduction of numerical dispersion by the new method. Effects of physical dispersion, adsorption, two-phase flow and transient state on tracer flow behaviour are presented. Tracer test cases for a quarter five-spot pattern with homogeneous permeability and with assumed heterogeneities are analysed. A multi-well, irregularly shaped reservoir case has also been presented.
Drilling Shallow Horizontal Wells in Germany Using Short-Radius Technology
Authors: Schamp Jürgen , Rohde Uwe
Published: December 2007

In 1993 Mobil Erdgas Erdol GmbH drilled four short radius wells in Northern Germany. The wells were drilled in two reservoirs having complex geologies and faced technological challenges in a low budget.

Three wells were gas-storage wells in a depleted oil reservoir near the city of Hamburg. Two of these were designed for water production in order to increase the storage volume and one at the top of the structure was designed for producing and injecting gas.

Because of given surface locations, fixed targets and complex geology of this highly fractured reservoir, short radius drilling and horizontal lengths of more than 400 m were necessary to achieve the different goals of the wells. External casing packers (ECP) had to be used to ensure complete gas shut off after cementing the 7" liner. The short radius curve and the complete horizontal section was reamed for running stimulation tools later on. Geology required small targets, precise directional work with complex wellplans and correct placement of casing shoes and ECPs.

The fourth well was planned as a low budget oil production well in the shallow oilfield Voigtei. Cost reductions were achieved by using a specially equipped mining rig, a simple but adequate drillsite, cementation performed with a Mobil-owned pump truck and running of used and inspected casing. The biggest challenges were to drill 430 m of horizontal section at a vertical depth of only 270 m and to stay within the thin pay zone of the Lower Cretaceous Sandstone, which required a TVD limitation of 1 1.5 meters. To fulfill this objective a nearbit inclinometer as part of the MWD was used successfully.

The short radius curve was drilled in 8 3/8" hole diameter and cased with a 7" surface string. A specially designed pull down assembly hooked to the rig's top-drive was used to run the casing through the short radius to horizontal. Drag problems while drilling the horizontal section were overcome by additional WOB from the pull down. The horizontal section was logged with the tools connected to the drill string and cased with a 4 1/2" slotted liner.

The well could prove that shallow oil-wells can be drilled inexpensively by using existing - but for the oilfield untypical - technology.
Innovative Development Strategy for a Complex Structural-Stratigraphic Trap: A Field Case
Authors: Chen Hsiu-Kou , Thera Jack , Cleveland M. N. , Horner S. G.
Published: December 2007

This paper describes how engineering data and the latest drilling technology are used to develop a complex structural-stratigraphic trap in the Sultanate of Oman. Extended production test and pressure data were used to estimate the oil-in-place and to define the field geometry. This field has a very thin (less than 45 ft) reservoir section located just below a shale cap rock. Development wells are drilled with an inclined pilot hole to determine the reservoir depth, thickness and quality. A short radius horizontal well is then drilled to maximize oil production rate when sufficient pay zone is encountered.
Mechanistic Simulation of Foam Processes in Porous Media
Authors: Rossen W. R. , Zeilinger S. C. , Shi Jianxin , Lim M. T.
Published: December 2007

Foam mechanisms are many and complex, but in some cases the mechanisms that dominate foam properties can be represented in simple models. For instance, fractional-flow methods can reproduce the predictions of much-more-complex foam simulators while highlighting the mechanisms controlling behavior. Fractional-flow methods indicate that the effectiveness of foam processes that alternate injection of liquid and gas ("SAG" processes) depends on foam strength at extremely high foam quality, conditions difficult to control in the laboratory. Ironically, surfactant formulations made with lower surfactant concentration, that form weaker foams in steady-state flow, can foam stronger, longer-lived foams in dynamic SAG processes than foams made with higher surfactant concentration, because water drains more slowly from the "weaker" foams in the SAG process.

A numerical simulator that incorporates the relation between capillary pressure and foam stability extends simplified foam modeling to cases where fractional-flow methods do not apply. Applications of this simulator to one-dimensional (ID) foam displacements match predictions of analytical models based on laboratory data. Applications to 2D flow show that the ability of foam to correct gravity override is controlled both by the dimensions of the reservoir and the allowable rise in injection-well pressure. In flow through layers in capillary contact, the interplay between capillary cross-flow and foam collapse depends on both the dimensions of the layers and the relative magnitudes of the capillary and viscous pressure differences.
Study of Removing Formation Damage by Solidified Polymer in Extremely Hot Wells
Authors: Krilov Z. , Tomic M. , Loncaric B. , Cikes M.
Published: December 2007

Z. Krilov,* M. Tomic, B. Loncaric* and M. Cikes*

The paper is describing the problem of identification of an inconvenient type of formation damage due to polymer solidification downhole. Laboratory tests showed the presence of this problem if particular temperature has been exceeded. Based on lab test results the method of chemical treatment was developed in order to remove this kind of damage. The comparison of laboratory investigation data and field application of method is expressed.

The severe damage of production zones were occurred after using a gelled brine system for temporary viscous plugs set in some deep hot gas condensate wells in Southern Pannonian basin (BHT>195 C, TWD >4000m). Laboratory tests showed solidification of the same calcium bromide-calcium carbonate high activity synthetic polymer (polyacrilate) Water base system at temperature above 180 C. So formed viscoelastic material (solidified polymer) has plugged perforation tunnels and near wellbore porous medium, causing drastic reduction in well productivity.

The laboratory tests and attempted well stimulation jobs showed that this type of residuum is practically undissolved in any well known solvent or acid. Due to further lab investigations the way of chemical treatment, using sequential injection of base (KOH) or oxidant (NaOCl + NaOH), following by inhibited organic acid (CH3COOH) was developed and successfully used in field practice to remove formation damage downhole.

The described method of treatment, accompained with laboratory analytical procedure for damage identification, can be applied in designing the well stimulation jobs.

P. 743
A New Concept in Scale Inhibitor Formation Squeeze Treatments
Authors: Miles Leon
Published: December 2007

Scale control in producing wells has been a particularly thorny problem because scale often begins in the formation before the scaleforming fluids reach the wellbore. Continuous treatment down the casing annulus protects down-hole equipment but does not attack the scale at its starting point. Squeeze treatments with liquids and fracture packs with solid scale inhibitors have not been entirely successful because of short treatment life.

A squeeze treatment utilizing a liquid which forms a slowly soluble inhibitor in situ has been developed and field tested with excellent results. Field histories over a period of 30 months are now available. The period of 30 months are now available. The field histories support the laboratory data upon which the treatment was based.

Introduction

Scale may be defined as a mineral deposit formed on surfaces in contact with water. The most common scales associated with oilfield brines are calcium sulfate, barium sulfate and calcium carbonate. Other insoluble salts are also found, but usually in small quantities along with these three. Corrosion products such as iron oxide and iron sulfide may also be considered as scale.

Many industries face scale problems, but those handling brine from deeply buried formations are plagued with a unique combination which makes scale control very difficult. We usually handle very large volumes of poor quality water under severe temperature and pressure conditions. Our main problem is the pressure conditions. Our main problem is the remote and nearly inaccessible location for treatment where the trouble really begins. A thorough understanding of scale formation is required before successful treatment can be assured.

Causes of Scale Deposition

Three major causes of scale deposition have been identified.

A Mixture of Two Incompatible Waters

One mixture possibility is foreign water entry into the producing zone from casing leaks or poor cement jobs. Obviously, this problem should be solved by more direct methods than chemical treatment. Another possibility not so easily overcome may occur at producing wells when injection water breaks through. Bernard has shown that no reaction occurs within the formation pore space when water incompatible with formation water is injected. He reasoned that discrete pore channels were filled with injection water displacing formation water. No opportunity for mixing presents itself until both formation water and injection water, flowing in separate pore channels, make contact at the producing wellbore face. At some point in time, a ratio of the two would then result in precipitation and scale. precipitation and scale.
Simulation of Crawford Gas Storage Field
Authors: Nacul E. C. , Gilmore R. , Theodos A.
Published: December 2007

The Crawford Field is a very large gas storage field located in Hocking and Fairfield Counties, Ohio. The Crawford field lies along the distal edge of the clastic wedge that forms the Silurian aged Clinton delta complex. The Clinton sands in the field consist of multi-stacked, coalescing, lenticular sandstones and siltstones deposited as distributary channel sands, interbedded with marine shales and floodplain muds. The Clinton sequence strikes N 17° E with a dip to the southeast of about 62 ft/mi.

The main purpose of the study was to create a strategic plan for developing the Crawford gas field for storage operations in the most efficient and cost effective manner. In the study we have verified the number of wells required in the Crawford Gas Storage Field to inject and withdraw the monthly schedule assigned by Columbia Gas Transmission Corporation, determined the best well priority for the field, and defined the amount of gas migration northward into an undrilled future development area of the field.

In order to accomplish this study, the reservoir area of approximately 40,000 by 70,000 feet was gridded in a 45 by 75 single layer model with uniform cells of aspect ratio of 1.062. A history match of 3 cycles (1989 to 1993) was performed with a very good agreement between the simulation and field results. With the reservoir description adjusted from the history match a 3 cycle forecast (1993 to 1996) was performed. This forecast allowed Columbia Gas Transmission Corporation to analyze the Crawford Gas Storage Field capability for the next three years.
Evaluating the Optimal Norwood Deepening Method in the Antrim Shale
Authors: Frantz J. H. , Tatum C. L. , Bezilla Michael , Kalnbach B. W. , Wilkinson J. G.
Published: December 2007

The purpose of this paper is to present the results of a Gas Research Institute (GRI) evaluation to determine the optimal deepening and completion technique for the Norwood Antrim Shale unit in older Antrim wells in the Michigan Basin, including the potential range of Norwood production responses. There are approximately 500 older Antrim wells not drilled through the Norwood, that could be deepened below their current Lachine unit completion. GRI performed this work because operators are uncertain of the best deepening/completion procedure, the potential productivity of the Norwood, and the appropriate well spacing for the Norwood completions. In this paper, we show the results of actual field case histories and simulated performance projections to determine the optimal Norwood deepening method and well spacing.
Production Study Evaluates Completion and Stimulation Program
Authors: Zamora Frank , McDaniel B. W. , Hyde Paul
Published: December 2007

Completion techniques and associated stimulation treatments used for wells in the Devonian Shale of the Appalachian Basin have been evaluated in a 2-year study of production logs and production history. The study was a joint effort of a gas production company and a well service company. Results of the study have revealed that well economics can be significantly improved if completion zones are better chosen and the appropriate associated fracture stimulation treatment is used. This paper presents study methods, findings, conclusions, and recommendations on completion plans and stimulation designs for future wells in this field and similar Devonian Shale wells.
The Use of Well Log Data for Estimating Permeability in a Heterogeneous Reservoir
Authors: Molnar D. L. , Aminian Khashayar , Ameri Samuel
Published: December 2007

The determination of the permeability distribution in a heterogeneous reservoir is the key for performance predictions. The permeability is usually evaluated from cores and/or pressure transient well tests. The determination of the permeability distribution in a heterogeneous reservoir is a complex problem because core samples and well test data are only available from very limited number of wells. At the same time, geophysical logs are available from the majority of, if not all, the wells in a reservoir. Therefore, the evaluation of permeability from well log data represents a significant technical as well as economic advantage. The evaluation of permeability in heterogeneous formations from well log data however represents a difficult problem. Generally, a simple correlation between permeability and porosity cannot be developed in heterogeneous formations. The goal of this study has been to investigate the feasibility of estimating the permeability of a heterogeneous formation utilizing geophysical well logs as well as geological interpretations.

Granny Creek Field in West Virginia has been selected for detailed evaluation in this paper. This field has produced oil from the Big Injun Formation since early the 1900's. Water flooding operations were initiated in the 1970's and currently are in progress. Well log data from a substantial number of wells, as well as core samples and/or core analysis results from a limited number of wells, were available and were collected. The core samples and the various well logs were analyzed to determine permeability and porosity. However, a reliable porosity-permeability correlation could not be developed even when the formation was subdivided into several zones based on the various geological interpretations.

A methodology was developed in this study by integrating actual well log responses (Gamma Ray, Deep Induction, and Bulk Density) and geological interpretations to subdivide the formation into several zones which led to development of a reliable correlation between bulk density and permeability. The field-wide applicability of the correlation was verified through comparison against measured permeability values, The results presented in this paper could serve as a guideline for correlating permeability with well log data in heterogeneous formations.
A New Technique for Analysis of Wellbore Pressure From Multi-Layered Reservoirs With Unequal Initial Pressures To Determine Individual Layer Properties
Authors: Aly Ahmed , Chen H. Y. , Lee W. J.
Published: December 2007

In this paper, we present a new method for analyzing a multi-layered, commingled reservoir with unequal initial layer pressures. The main objective is to provide techniques and methodology to determine the individual layer permeabilities, porosities and skin factors from the pre-production well test data. The layer information obtained early in the life of the reservoir is very important for planing production schedule and economic decisions concerning the future of the wells. This pre-production well test is carried early in the life of the reservoir, during the period after perforation but before any surface production and is caused by crossflow in the wellbore only.

The results of this study provide a useful foundation for the design of a new pre-production well test procedure that ensures that the individual layer properties are measured adequately and early in the life of th6 reservoir when they are most needed.

The pre-production well test requires no production on surface. Thus, the environmental impact caused by flaring oil or gas during a conventional well test is alleviated.
Fontenelle Field Hydraulic Fracturing Stimulation of the Frontier Formation: Case History
Authors: Martinez A. D. , Ruffin B. D.
Published: December 2007

This paper is a case history of the Frontier Formation hydraulic fracture stimulations applied since 1984 in the Fontenelle Field located in Sweetwater County, Wyoming. The hydraulic fracture treatments have undergone several design changes that have led to a 25% increase in production and a 66% decrease in completion costs.

Design changes that have been incorporated to reduce costs include reduction in pad volumes, use of sand versus intermediate strength proppant, reduced pump rates, and the use of water based gels instead of CO2 foams. Improved production is attributed to improved fracture geometry resulting from 3-D fracture model analysis.
Rose Run Stimulation: A Case History of Problem Identification, Research, Planning, Implementation, and Evaluation
Authors: Cramer J. W. , Thomas J. B.
Published: December 2007

The Rose Run Sandstone consists of individual quartz and feldspar grains cemented by dolomite, clay minerals, and overgrowths of quartz and feldspars. Historically, the Rose Run has been stimulated with hydrochloric(HCl) acid with appropriate additives to remove the dolomitic cement matrix to improve permeability. Post stimulation results vary widely.

The production from some wells suffered from steep declines. When shut-in, most wells exhibited good pressure recovery. Reservoir analysis calculated skin factors as high as +10 indicating formation damage.

An in-depth study of wells in Randolph Township of Portage County, Ohio (Fig. 1) was initiated to try to identify the mechanisms that effect well productivity. Drill cutting samples, well logs, rotary sidewall cores, petrologic data, core analysis, and SEM photos were analyzed. The primary goal of this study was to determine possible improvements to current stimulation treatments. An additional benefit of this study was to evaluate the viability of remedial acid treatments in removing damage from producing wells.

Drill cutting samples, mud logs, natural production shows, and well logs are used on site to determine if the well would be completed.

Rotary sidewall cores were obtained from several wells for in-depth analysis. Routine laboratory core analysis measured permeability, porosity, and core fluid saturations. Thin sections were prepared and SEM photos were taken for petrographic analysis. Rotary sidewall cores from one well were analyzed and deemed representative of the Rose Run Sandstone. Rotary sidewall cores were tested to determine initial permeability to Rose Run formation brine and regained permeability to various acid solutions. The results of all analyses were considered in revising initial well stimulations as well as designing remedial acid treatments to address the problems that have been identified.

Production rates, decline curves, and pressure build-up data of conventionally treated wells were compared to wells treated with a new acid solution to determine if any positive benefits could be realized. The evaluation of remedial acid treatments using the new acid solution was based on the treatments ability to reduce the rate of production decline.
Techniques for Determining Subsurface Stress Direction and Assessing Hydraulic Fracture Azimuth
Authors: Hill R. E. , Peterson R. E. , Warpinski N. R. , Lorenz J. C. , Teufel L. W. , Aslakson J. K.
Published: December 2007

This reference paper reviews and describes 15 techniques for determining hydraulic fracture azimuth. The techniques described are categorized into core-based, borehole-based, near-wellbore, and regional geologic indicators that can be used to predict or measure hydraulic fracture azimuth. The core based methods include: 1) circumferential velocity anisotropy, 2) anelastic strain recovery, 3) differential strain curve analysis, 4) axial point load tests, 5) petrographic examination of microcracks, 6) overcoring of archived core, 7) drilling-induced fractures in core, and 8) direct observation of over-cored open-hole stress test fractures. The borehole based techniques include: 9) borehole breakouts, 10) borehole deformation, 11) borehole imaging of drilling-induced fractures, and 12) directional gamma ray logging. The near-wellbore techniques provided data on the orientation of the fracture induced during an actual fracture treatment and include: 13) microseismic logging and 14) earth tilt surveys. Finally there are the geologic indicators (Method 15) including earthquake focal mechanisms, fault slip data, surface mapping of neotectonic joints, and volcanic vent alignment. These regional data have been compiled for the World Stress Mapping Project and many maps are available that can be used as a first approximation of stress direction.

Experience has shown that the more techniques that can be used in a single well or field, the more reliable the result. The concept or theoretical basis for each technique as well as the benefits and limitations of the techniques are described.
Drilling Fluids Waste Minimization and Stabilization Using Polymer Technology
Authors: Thompson L. F.
Published: December 2007

The purpose of this paper is to address environmental issues associated with generated waste through drilling. Polymers have been proven to be extremely effective in the waste reduction in drilling closed system without the use of solids control equipment with shale shakers optional and the stabilization of drilling discharges using additional polymer technology. The objective is to demonstrate that with the proper use of polymers, waste can be reduced and stabilized without an increase in volume and with a very cost effective method. The result is that the environment will be enhanced while reducing risks and costs.
The Development and Field Application of a 3D Computer Graphics System for Displaying Wellbore Trajectories
Authors: Santos O. L. A. , Azar J. J.
Published: December 2007

This paper presents the development of a 3-D computer graphics software for displaying wellbore trajectories. The software is designed for use with PC microcomputer operating under MICROSOFT WINDOWS™ environment. Examples of the software application are given in two important areas of directional drilling: 1) avoidance of wellbore collisions and 2) planning and drilling monitoring of relief wells.

First, the paper presents the basic theory behind the computer graphics techniques used for developing the computer software. Second, it presents the display modes and important features provided by the system that includes 2-D and 3-D views of wellbore trajectories with ability of rotation, zoom-in and zoom-out, and display of uncertainty ellipses. These features are very helpful in planning and monitoring wellbore trajectories. Also, these capabilities allow the software to be used as a powerful training tool.

The last part of the paper illustrates the application of this graphic system in planning and monitoring: 1) directional drilling in high density well areas such as offshore platforms in order to avoid wellbore collision; and 2) the relief well drilling to assist in the approaching procedure between relief and blowing wells and the use of ranging tools.
Characterization of Devonian Shale Gas Reservoirs Using Coordinated Single Well Analytical Models
Authors: Carlson E. S.
Published: December 2007

We present here a simple, fast methodology which can be used to provide information about the two least-measurable parameters of Devonian Shales, fracture spacing and fracture continuity. The results of these calculations can assist in establishment of field development programs. Although this technique may provide for the most detailed characterization possible for the shales, we show the clear need for further research into geophysical and other geological methods for detection of fracture densities.
Predicting Compaction and Subsidence for an Immature Gasbearing Carbonate Field
Authors: Prins M. , Smits R. M. M. , Schutjens P. M. T. M.
Published: December 2007

Reservoir compaction and associated surface subsidence levels can be significant when high porosity carbonate gas reservoirs are depleted. A well known example is the Ekofisk field in the North Sea Therefore these phenomena are incorporated when designing offshore platform constructions. Because the design and the construction part of development take place well before the field production starts (i.e. when only little is known about the field), uncertainties exist in the parameters that are required for the prediction of surface subsidence.

This paper describes the prediction of subsidence for the M1 field, offshore Sarawak, East Malaysia and shows that although many uncertainties may exist in the parameters required for the predictions, investigation into the effects of these uncertainties provides useful insight in the possible range of subsidence levels. The predicted range of subsidence levels can subsequently be used as input for the platform design.
Water Cone Subsidence Time of a Horizontal Well
Authors: Lee Robert L. , Nath Shyamal , Khan Mashiur , Permadi Pudji
Published: December 2007

Because of a localized decrease in pressure, water may rise to a height above the oil-water interface and be produced through a horizontal well. The localized increase in the water-oil interface elevation creates a cone of water near the well. If a large enough drawdown is exerted on the reservoir, water will start replacing the oil in the production stream. The instant when water first enters the well is known as the critical drawdown or threshold drawdown. As the producing water-oil ratio increases, the operating cost of the well as well as the oil production cost will start increasing. At some point, the well may need to be shut-in to allow the water-oil interface to subside. In this situation, an optimum shut-in time exists, and it is dependent upon the subsidence time of the water cone.

Analytical solution for subsidence of water cone under a horizontal well is being presented in this paper. Usually, wells require a shut-in period if the drawdown exerted on the reservoir is above a critical value. But, depending on the amount of the drawdown exerted, the water cone can have a wide variety of shapes at the post-critical drawdown condition. To avoid this, the initial water cone shape in this solution, after the well is shut-in, is defined at the point of critical drawdown.

The water cone shape under a horizontal well at the point of critical drawdown is estimated here by developing an empirical formula. The cone shape is found to be a function of the critical oil production rate.

The water cone subsidence time is determined by solving the diffusivity equation using the separation of variables technique. The resulting solution shows that the subsiding instantaneous cone heights are exponentially related to time and are effected by hydraulic conductivity of reservoir, coefficient of specific storage of porous medium, the critical oil production rate and the reservoir geometry. Finally, the cone subsidence time is presented in a series of type curves that assumes various reservoir parameters.
Well Design for Shallow Gas
Authors: Murray S. J. , Williamson M. D. , Gilham Steve , Thorogood J. L.
Published: December 2007

Shallow gas and its associated operational procedures have been the subject of much opinionated debate. Previous work in the area has focused either on regulatory issues or on the steps that can be taken while drilling to minimise the consequences of a shallow gas kick. Although some attention has been given to modelling the behaviour of wells under shallow gas blowout conditions, this has not resulted either in a practical design tool nor in a structured procedure for checking well designs.

This paper puts forward a provisional framework which highlights the design checks that should be made to ensure that rig systems, well designs and operational procedures are safe and fit for purpose.

The framework should permit engineers to approach the problem of shallow gas well design in an analytic and structured fashion, using a specified set of analysis techniques. These techniques are reviewed and transient well unloading and quasi-steady blowout simulations are identified as critical elements. The basis and operation of a practical software tool which addresses these elements is described. Some examples of its use are given and areas where modelling improvements could be made are suggested.
Allowable Torque of Tubular Connection Under Simulated Running and Working Conditions
Authors: Tsuru Eiji , Maruyama Kazushi , Inowaki Ryuichi , Tochikawa Tetsuro
Published: December 2007

In field operations, the make-up torque of tubular connections depends on compensated axial weight and environmental temperature. Also, in running operations, torsion can be applied to casings with connections under loading.

This paper deals with the torque resistance of tubular connections, with regard to field operating conditions. The results indicate that the make-up torque increases when the grease quantity is small and the temperature is low, and the torque resistance improves under loading. Using the predicted torque resistance, the true safety of the connections can be evaluated for their torsional strength.