bluuebunny/crossref_metadata_2025 huggingface dataset:
Gathering System Optimization in a Gas Field with Commingled Flowlines
Authors: Soetedja Vincensius , Harun Amrin F.
Published: December 2007

Badak Field, located in East Kalimantan, Indonesia, is a giant onshore gas field with 181 wells and total gas deliverability of 1.3 billion standard cubic feet (BSCF) per day. In many cases, gas from more than one well is commingled in the same flowline. This study concludes that commingling flowlines has been extremely cost effective over the life of the field. However, good initial design is required to anticipate future reservoir depletion and recompletions in order to achieve the best economic efficiency.
Correct Production Rates Eliminate Sand Production in Directional Wells
Authors: Budiningsih Y. , Hareland G. , Boonyapaluk P. , Guo B.
Published: December 2007

This paper shows how rock strength analysis can be utilized in preventing wellbore collapse and sand control problems during production of directional wells. From this study it is seen that selecting the correct production rate can avoid wellbore collapse which cause sand production. When the production rate is increased the reservoir drawdown near the wellbore cause an increase in the effective wellbore wall rock stresses. Using the von Mises rock failure criteria for wellbore stability analysis, the maximum production rate without formation collapse and sand production can be estimated. The parameters that effect the rock stresses at the borehole wall are the in-situ stresses, wellbore inclination and direction, and fluid pressure in the rock which is a function of the production rate. If the decrease in the near wellbore fluid pressure due to high production rate causes the effective stresses to exceed the failure criteria the wellbore will collapse to a certain new diameter. After the new diameter is estimated the volume of produced sand is calculated. The study concludes that possible sand production should be carefully analyzed in all directional wells. The wellbore sand production is a much more severe problem in directional wells and might limit the production rate. The maximum production rates with no sand production can be obtained using the approach in this paper.
Hidden Oil Leg : Case Study of the Lower D1 Miocene Sandstone, Dulang Field, Offshore Peninsular Malaysia
Authors: Solomon G. J. , Chandramohan S. , Karra S. , Sonrexa Kartikay
Published: December 2007

The Dulang Field is located offshore east coast of Peninsular Malaysia in water depths of approximately 75 m. The field, discovered in 1981, is about 24 km by 3.5 km. After drilling 14 exploration/appraisal wells by both Carigali and its partner Esso Production Malaysia Inc., the central part of the field was developed as a unitized area in November 1990. Three 32-slot platforms have been installed in the unitized area, and development drilling is ongoing. Production commenced in March 1991 and is currently maintained at approximately 50,000 BOPD. The estimated OIIP (oil-initially-in-place) for the unitized area is in the order of 700 million barrels.

There are 19 reservoir sands in Groups D and E which are of Middle-Late Miocene age. During the exploration/appraisal phase, oil and gas were encountered in the Group E and only gas in the Lower D1 reservoirs. Wireline formation pressure test data taken in the Lower D1 reservoir in these wells plotted along a common trend with a gradient of 0.06 psi/ft. The lowermost gas pressure point was only 6 m above the normal hydrostatic gradient.

It was therefore concluded that an oil column, even if present, would be thin. At the time, it was understandable that the gas pressures plotted along the same trend because the hydrocarbon column of the Lower Dl reservoir was large and extended beyond the limits of the major faults, suggesting a common pool. However, during the development drilling phase, it was discovered that the Lower D1 sandstone was a major oil reservoir, with estimated oil-in-place of about 100 million barrels. Oil columns of 75 m and 40 m have been proven up in the northern and southern flanks of the field, respectively, in the Lower Dl. In addition, development plans were flexible enough to be able to effectively exploit the discovery.

The well and formation pressure test data suggest that the Lower Dl has a common pressure system in the gas cap over the central part of the field but different systems in the oil columns. Faulting is suspected to have provided both conduit and seal at different times to accommodate this phenomenon.
The Significance of Large Variations in Oil Properties of the Dai Hung Field, Vietnam
Authors: Behrenbruch Peter , Du Pham Quang
Published: December 2007

The Dai Hung Oil field, offshore Vietnam, is comprised of a complex subsurface structure containing stacked reservoir sequences typically found in many other Southeast Asian fields. Combined with areal fault compartmentalisation, this situation has led to the observed, large variations in oil properties. Furthermore, the depositional environment in terms of burial history has created a unique overpressure situation which also had an affect, particularly on the crude saturation conditions of individual reservoirs.

For commercial and technical reasons, this situation required a detailed analysis, both in terms of variation in crude assay and live oil properties. For whole crude properties: gravity, K factor, wax content and pour point – graphs were drawn up using a large data base of worldwide crudes against which the Dai Hung data could be validated. In case of PVT properties (bubble point and formation volume factor) existing industry correlations were examined.

It could be concluded that the sweet, medium gravity and moderately waxy Dai Hung crude has whole crude properties which are comparable to other, similar crudes.

The general framework of crude properties established is suitable to type other crudes, even if limited information is available.

Of the existing PVT correlations tested1-5, it was found that Standing's1 correlation for the oil formation volume factor and the Kartoatmodjo-Schmidt5 correlation for the bubble point fitted the Dai Hung crude data the best. For the lower shrinkage Dai Hung crudes the Malaysian oil formation volume factor correlation by Omar-Todd4 gave the best data fit.
Optimisation of a Large Integrated Area Development of Gas Fields Offshore Sarawak, Malaysia
Authors: Inyang Samuel Edward , Tak Andrew Ngu Hew , Costello Gerry
Published: December 2007

Optimisations of field development plans are routine in the industry. The size, schedule and nature of the upstream gas supply project to the second Malaysia LNG (MLNG Qua) plant in Bintulu, Sarawak made the need for extensive optimisations critical to realising a robust and cost effective development scheme, and makes the work of more general interest. The project comprises the upstream development of 11 offshore fields for gas supply to MLNG Dua plant at an initial plateau production of 7.8 million tonnes per year of LNG. The gas fields span a large geographical area in medium water depths (up to 440 ft), and contain gas reserves of a distinctly variable gas quality.

This paper describes the project optimisation efforts aimed to ensure an upstream gas supply system effectiveness of over 99% throughout the project life while maintaining high safety and environmental standards and also achieving an economic development in an era of low hydrocarbon prices. Fifty percent of the first of the three phases of this gas supply project has already been completed and the first gas from these fields is scheduled to be available by the end of 1995.
Practical Methods to Forecast Production Performance of Horizontal Wells
Authors: Permadi P.
Published: December 2007

Hundreds of horizontal wells have been drilled and completed successfully in many oil producing countries. When properly utilized, horizontal wells produce more oil at lower cost. To support its economic evaluation, production prediction models are needed before the implementation.

This paper presents two analytical methods for predicting performance of a horizontal well. One method uses a steady-state inflow equation to estimate breakthrough time for water. The second method proposed, which has been derived from a pseudosteady-state inflow and material balance equations, is suggested to forecast oil production versus producing time. The former method should be used for a horizontal well producing oil from a bottom water drive reservoir, while the latter should be applied to a horizontal well producing from a depletion drive reservoir.

Field examples are given to show that the proposed methods work well. The presented correlations may help field engineers in designing or evaluating their planned horizontal wells before a sophisticated prediction tool available on hand.
Experience in the use of QRA to Prioritise Safety improvements on Offshore Platforms
Authors: Hanson R J , Lewis K J , Walters K
Published: December 2007

The objective of this paper is to share Brunei Shell Petroleum's (BSP) experience in using QRA to help understand risks in offshore operations and to identify and prioritise ways to improve.

This paper presents an overview of the results of the QRA studies using the work for one installation as an example and describes how potential improvements were identified and evaluated. It shows how this objective approach can help effective management decision making to improve safety and reduce business risk. Future goals and challenges and the interaction of this work with the Company's long term strategic planning are discussed briefly.
A New Contracting Strategy Improves Well Construction Quality and Efficiency
Authors: Varco M. R. , Boyle John , Richardson Mike , Oag Alistair
Published: December 2007

In today's mature North Sea environment every effort must be made to increase efficiencies in order to increase the return on investment of both operators and contractors.

A new contracting strategy has been introduced to improve drilling efficiency, while ensuring all well quality measures are met. As a result of this strategy, the BP Bruce field is one of BP's most effective, fully integrated North Sea drilling operations.

This paper describes the steps taken to successfully implement this strategy and the benefits that have resulted.
Alliance Drilling in Papua New Guinea: A Case History
Authors: Gibson W. R. , Lawson C. L. , Crowson R. L.
Published: December 2007

In today's oil and gas environment, the working relationship between operators and contractors is based on trust, flexibility and long-term cooperation. This paper presents how Phillips Petroleum Company (PPCO) and its subsidiary Phillips Petroleum Company Niugini (PPCON) analyzed several alternatives for drilling a prospect in Papua New Guinea (PNG). The chosen option was to form an Alliance with Parker Drilling Company (PDC) in PNG and to package all required equipment and services. This led to a successful heli-rig drilling operation which met all the objectives of the Bujon-1 prospect in the PNG rainforest. The traditional supplier-customer relationship can be re-engineered to reduce duplication of efforts by forming a single strategy. An Alliance can be a formidable tool to control costs and strengthen commitment from all participants in a drilling operation.
Reliability Methods Applied to Drilling Operations
Authors: Ligrone Angelo , Botto Giovanni , Calderoni Angelo
Published: December 2007

Managing drilling operations requires a careful and skilled use of all the information available.

In most cases, the information is processed by statistical methods. However, sometimes there is the risk of neglecting some part of the information, thus biasing the decision-making process.

In our opinion, the reliability approach can overcome this problem. This paper aims at showing how it is possible to effectively manage the performance of the drillstring by constantly monitoring the reliability of every single drillstring component.
An Integrated Approach to the Development of a Water-Based Mud With Oil-Based Mud Performance
Authors: Sawdon C. A. , Brady M. E. , Cliffe Steve , James S. G.
Published: December 2007

There are many aspects of water based muds (WBM) which must be improved before they can truly approach the performance of an oil based mud (OBM). OBMs provide increased drilling performance by combining shale hydration inhibition, drill string lubrication, reduced stuck pipe risk, low formation damage, corrosion avoidance and high temperature stability. The importance of these attributes is briefly discussed.

Historically, it has been common practice to focus on a single factor (such as shale inhibition) when developing ecofriendly WBM products. Insufficient attention has been given to the mutual compatibility of mud additives designed for different functions. Examples are provided on incompatibilities and side effects which can result from a blinkered component development process.

This paper describes the development of a new, integrated WBM system designed to provide much of the performance benefit of an OBM in all but high temperature well applications. The separate approach to high temperature WBM development is briefly discussed. Each component of the new system was developed to display not only high performance in its intended function, but also mutual compatibility and, where possible, synergy with the other additives. Other design criteria included the avoidance of detrimental side effects such as formation damage and/or adverse environmental impact.

Taking each criterion in order, results are presented on the performance of individual components, both alone and in combination. Synergism and product multifunctionality are highlighted. Finally, results are given for all the performance indicators of a fully formulated drilling fluid containing all the new components. Field trials have commenced on a partial system and this experience, together with subsequent case histories, is discussed.

Although OBM performance may not yet be replicated, an integrated approach does allow the target to be approached.
Hole Cleaning Program for Extended Reach Wells
Authors: Guild G. J. , Wallace I. M. , Wassenborg M. J.
Published: December 2007

This paper presents a hole cleaning program developed in the field by Amoco UK over the course of three extended reach wells. This program has be effective in cleaning the hole as well as increasing drilling progress.
Steerable Rotary Drilling With an Experimental System
Authors: Barr J. D. , Clegg J. M. , Russell M. K.
Published: December 2007

Some of the needs in directional drilling of extended reach and horizontal wells are discussed. It is forecast that Steerable Rotary Drilling (SRD) will meet some of these needs, providing economic benefits. Known options for an SRD system are briefly discussed. The system devised uses synchronous polyphase modulation of bias from a mechanism connected to, and rotating with, the drill bit, powered by drilling fluid and controlled by a directional sensor package, the orientation of the latter being independent of BHA rotation, stabilized and controlled. This scheme meets structural requirements while being capable of development for a wide range of hole sizes. The concept was proved by drilling an interval of 638m (2092ft) with an experimental SRD system. Deviation, while rotating, was controlled at rates up to 8.5730m (8.6°/100ft) to change elevation up/down and azimuth left/right. The system was successful with both PDC and roller cone bits and the deviation rate vector was largely independent of bit weight, rotary speed and penetration rate. The drilling trials have provided data for a product aimed particularly at extended reach and horizontal drilling. Economic benefits are expected by saving time and by improving directional control.
Formation Compressive Strength Estimates for Predicting Drillability and PDC Bit Selection
Authors: Spaar J. R. , Ledgerwood L. W. , Goodman Harvey , Graff R. L. , Moo T. J.
Published: December 2007

Various indirect measuring techniques are presently employed for estimating formation strength, which in turn is correlated to drillability and polycrystalline diamond compact (PDC) bit selection. Formation mechanical properties derived from conventional open-hole logs in combination with a rigorous assessment of formation shear wave velocities can be used successfully to determine drillability as it pertains to bit selection. Formation drillability is best determined from unconfined compressive strength and the angle of internal friction assessment. Rock strength is found to correlate well with the overall measures of bit effectiveness.

Further, the angle of internal friction, which is a subsidiary rock strength parameter, correlates with PDC bit wear rates.

Compressive strength and drillability have been linked in the laboratory and observed in the field since the early 1960's. Compressive strengths, however, need to be qualified as a function of confinement stress. The concept that compressive strength increases with confinement stress is well-understood and can be easily explained with Mohr's failure criteria. With the Mohr's failure technique, it is important to understand that inherent rock strength properties (cohesion and angle of internal friction) must be known before compressive strengths can be estimated.

This paper also presents case histories from Gulf of Mexico wells that illustrate how unconfmed compressive strength and angle of internal friction can be employed to indicate drillability as it pertains to optimized bit selection.
Interfacial Sealing Properties of Slag Mix (Mud-to-Cement Conversion Technology): Laboratory and Field Evaluation
Authors: Nahm J. J. , Romero R. N. , Javanmardi Kazem , Wyant R. E.
Published: December 2007

Anti-gas-migration slag mix slurries having 24-hour to 48-hour set-times were used for the cementing of five 11¾-inch casing strings at the deepwater Auger prospect in the Gulf of Mexico with no failures or evidence of annular gas migration. The long set-times were required to permit setting and testing of the subsea seal assembly prior to cement hydration, In addition, a slag mix TA plug in the 11¾-inch casing string effectively isolated known gas from the open hole below and a slag mix open-hole kickoff plug isolated gas in the hole below that plug.

Gas migration during slag mix slurry setting and the interfacial sealing properties of the set slag mix were investigated using a U-tube apparatus, a commercial gel strength tester, and a HTHP shear bond tester. Zero gas leak rates, low volume shrinkage, excellent bonding quality, fracture healing, extremely low permeability, and right-angle setting have been observed. It is postulated that the healing or regeneration of slag mix bonds observed in our shear bond tests may be linked to the theorized densified microstructure of slag cement reported in the literature.
Minimization Of Formation Damage, Filter Cake Deposition, & Stuck Pipe Potential In Horizontal Wells Through The Use of Time-Independent Viscoelastic Yield Stress Fluids & Filtrates
Authors: Powell John W. , Stephens Mike P. , Seheult J. Mac , Sifferman Thomas , Swazey John
Published: December 2007

Over 60 horizontal wells have been drilled and completed with slotted liners in Prudhoe Bay, Alaska using a low solids or solids-free clarified xanthan/brine drill-in fluid. As previously described the drill-in fluid demonstrates a functional true yield stress (TYS) in the circulating fluid.1 The yield stress is also present in the filtrate, limiting depth of filtrate invasion. The fluid has been further described as being viscoelastic (VE) under static conditions and at the low shear rates exisiting in an expanded plug flow region. This plug flow region is persistent over a wide range of flow rates and is a function of polymer concentration and brine salinity. The exhibits both time-indepent and pseudoplastic properties at higher shear rates (TIP). Collectively the viscoelastic, time-independent pseudoplastic fluid rheology is abbreviated as VETIP.1 Fluid performance has correlated to excellent well productivity, lack of formation damage, minimization of stuck pipe and liners, minimization of filter cake deposition and the lack of mud cake clean-up or removal problems, improved cost-effectiveness, and apparent improvements in present and long term well values.

Lack of formation damage, near-zero stuck pipe incidence rates, and minimization of filter cake removal problems are attributed to a functional true yield stress (TYS) in the circulating fluid and filtrate. The yield stress is measurable with oscillatory (Rheometrics), capillary, constant stress, and very low shear rate rotational viscometers. New field and laboratory data correlate well to the yield stress measurements. The yield stress of the filtrate declines with time, thermal degradation, biodegradation, and is quickly broken with hypochlorite breaker, restoring original permeability, without formation damage.
KTB-4 Years Experience at the Limits of Drilling Technology
Authors: Claus Chur , Thomas Bendzko , Bernhard Engeser , Axel Sperber , Trach T. V. , Lothar Wohlgemuth
Published: December 2007

The Continental Deep Drilling Program of the Federal Republic of Germany (KTB) is a non-commercial, geoscientific research project that is part of the international lithosphere research.The goals are to investigate the physical and chemical conditions and processes of the earth's deep continental crust. Two wells, the pilot hole and the ultra deep hole, were drilled in the program. The ultra deep borehole reached a depth of 9101 m on October 10, 1994. Drilling conditions are characterised by crystalline rock, borehole temperature exceeding 250 °C and severe borehole instability. The paper describes drilling strategy, equipment and the experience which was made during the operation.

Special consideration will be put on borehole stability that became the number one problem with increasing depth.
Wellbore Stability, Drilling Fluids Design, and the Drilling Performance of Horizontal Wells in Unconsolidated Oil Sands at Peace River, Alberta
Authors: Warren B. K. , McLellan P. J. , Pratt C. A.
Published: December 2007

Shell Canada Limited drilled two pairs of twin horizontal wells in the Peace River oil sands in the summer of 1993. This paper describes the detailed planning for the drilling of these wells, including wellbore stability, hole cleaning, differential sticking, lost circulation and torque-drag concerns. The drilling fluid selection process used to address potential problems will be highlighted. The value of thorough pre-planning led to the successful drilling of these four, one kilometer long horizontal wells in underpressured, uncemented oil sands.
Cost Effective Design Change in the Drilling Programme for the Gullfaks Field
Authors: Skogseth Ottar , Gaasø Rune
Published: December 2007

Low formation strength, rapid pore pressure build-up and shallow gas sands below the platforms dictated the casing programme for the first wells drilled at the Gullfaks field. A original casing programme containing sizes from 32" conductor penetrating the seabed to 7" liner through the reservoir allowed 7" monobore completions with a gravel pack option.

A standard well was drilled and cased with 6 casing strings and cleaned up before skidding the rig to next slot. A gravel pack was installed with a snubbing rig while the drilling rig was engaged with the next well on the opposite drill shaft (the first few gravel packs were completed with the drilling rig).

New casing programmes have been implemented. Continuous improvement, proven procedures for drilling through shallow gas sands, creative engineering in co-operation with contractors and research institutes and new information gained through a range of formation integrity tests below the conductors have made this possible.

26" casing was originally set at 550 m TVD to isolate the upper shallow gas sands and to obtain formation strength for the next section. After new information obtained by a series of mini-fracturing tests below the 32" conductor shoe, the 26" casing was made redundant.

Advances in drilling techniques resulted in drilling longer sections with smaller hole sizes. This resulted in a casing programme without 26" and 20" casing. A range of alternatives was introduced in the casing programme to cater for the requirements for specific wells.

Introduction of a slimmer casing programme with 13 3/8" casing set as the first string after 32" conductor still allows for a 7" monobore completion. The drilling rig skids over to a new slot after having installed the 7" liner. A snubbing rig cleans up the well, installs the completion string, perforates and installs the gravel pack (optional).

Introduction of alternative casing programmes will reduce drilling costs and drilling time per well by up to 30%, compared to the standard drilling and completion programme used up to 1993 (base case).
Drilling, Completion, and Workover Operations With the World's First Subsea Spool Trees
Authors: Stewart A. A.
Published: December 2007

Kerr-McGee's Gryphon Field in the UK sector of the North Sea was the first development in the world to utilise a subsea Spool Tree system, also known as "horizontal" or "valveless" trees.

This paper describes the operation experiences of using the Spool Tree system during drilling, completion and well intervention operations.

Field performance is reviewed against design expectations and where relevant, comparison between Spool Tree operations and more conventional tree systems is presented.

The successful operational aspects of the system are highlighted and the economic impact on the Gryphon project is reviewed.

Significant attention is paid to lessons learned during installation and interventions, and these are presented along with future recommendations for the benefit of other operators throughout the world.

Overall the Spool Tree system application to the Gryphon field has been an outstanding success providing significant flexibility and economic impact to the development of the field.
Step-Rate, Calibration Injection and Treating Pressure Anomalies in Soft Rock High Permeability Formations: An Explanation Based on Bottom Hole Pressure and Production Results
Authors: Stewart B. R. , Mullen M. E. , Brown J. E. , Norman W. D.
Published: December 2007

1 Abstract

Soft rock fracturing popularity has resulted in its wide spread use for stimulated completions in sand control environments. Varying degrees of completion efficiency and production improvements have been observed. More importantly these variances have been difficult to explain. This paper explores anomalies in pressure behavior observed during step rate, calibration testing, and fracturing treatments. This investigation will focus on why the predicted and actual production rates as a function of completion efficiency and skin do not always match. Scenarios will be proposed which can explain both the pressure anomalies and the production variances. The scenarios are constructed using bottom hole pressure data, pressure transient analysis, and production prediction using system analysis.
Gas-Lift Unloading and Operating Simulation as Applied to Mandrel Spacing and Valve Design
Authors: Hall James W. , Decker Kenneth L.
Published: December 2007

Gas-lift has been practiced for many years using principles developed in the 1940's and 1950's. For the most part, these principles have been developed based on experience and "rules of thumb" with little or no regard for actual valve performance. This paper describes the use of a software program that simulates the unloading and lifting of a gas lift well using scientific principles and valid valve performance data.

A brief explanation of the function of the program is provided and then investigated in more detail as it is applied to a planned gas lifted completion in the North Sea. A conventional design methodology is presented and its validity examined with the simulation software. The paper highlights areas of current design methodology which may lead to problems such as multi-point injection, unstable gas injection rate, and excessive lift gas use.

Explanations are given for the occurrence of the problems and suggested modifications are presented to avoid the problems.
Collapse and Post Collapse Behaviour of Tubulars: A Simple Approach
Authors: Abbassian F. , Parfitt S. H. L
Published: December 2007

This paper describes a simple method of evaluating the collapse strength and post collapse behaviour of oil field tubulars subjected to external pressure. The method is based on elastic ovalisation and subsequent plastic collapse by formation of a four-hinge mechanism. The resulting predictions of collapse strength are compared with available collapse test data, and other existing collapse equations. For post collapse behaviour, model predictions are compared with available experimental and numerical data. Applications of the method to collapse of perforated and slotted liners, prepacked screens and collapse under non-uniform loading are described.
An Analysis of Helical Buckling of Tubulars Subjected to Axial and Torsional Loading in Inclined Wellbores
Authors: Miska Stefan , Cunha J. C.
Published: December 2007

This paper describes new theoretical results for prediction of buckling behavior of tubulars in inclined wellbores. Using conservation of energy and the principle of virtual work improved equations for buckling and post-buckling conditions are derived. The effect of torque on the buckling process is considered. Practical examples are provided showing the influence of torque on the critical buckling force. The equations for critical buckling force reduce to those previously derived when torque is set to zero and weightless strings are considered.
Development of a New Theoretical Model for Three-Layered Reservoirs With Unequal Initial Pressures
Authors: Aly Ahmed , Lee W. John
Published: December 2007

In this paper we present a new theoretical model for three-layer reservoirs with unequal initial pressures. We developed a semi-analytical simulator based on the developed model. The computational model proved to be much faster than a three-dimensional, finite-difference commercial simulator used to validate the analytical model. Also, the amount of information (spatial gridding) needed to run the model is much reduced. The analytical model allows each layer to have different layer properties, different boundary conditions, and different initial pressures.

We used the semi-analytical simulator to perform a detailed study of the behavior of three-layered reservoirs during the "pre-production period." The pre-production period occurs early in the life of the reservoir, after perforation but before any surface production and is caused by crossflow in the wellbore. The layer information obtained is very important for scheduling production and making economic decisions concerning the future of the wells. The pre-production well test requires no production on the surface during the test; thus the impact on the environment is negligible.

The main objective of this work is to develop a qualitative approach to extract more information about the reservoir from pre-production wellbore pressure, dimensionless pressure and dimensionless pressure derivative curves. More specifically, we studied the pre-production behavior of three-layered reservoirs. Effects of the ratio of flow capacity and storage in different layers were investigated. We found that the layers with highest and lowest permeabilities can be characterized with the logarithmic time derivative of pre-production pressures. A positive derivative indicates high permeability in the layer with the highest initial pressure, and a negative derivative indicates high permeability in the layer with low initial pressure. Also, the layer with the highest initial pressure will always flow into the wellbore whereas flow will always be from the wellbore into the layer with minimum initial pressure. As the sandface rates reach steady state, the three-layer system behaves like an equivalent single layer system. Thus, we can apply a single-layer model to analyze the late transient in high permeability reservoirs.
Determining Permeability, Skin Effect and Drainage Area from the Inverted Decline Curve (IDC)
Authors: Rietman Noel D.
Published: December 2007

The inverted decline curve, or IDC, is the plot of the inverse of a well's producing rate (1/q) against the log of its producing time. If the well's producing pressure history is known, this curve can be used to determine reservoir permeability, the skin effect, and the area being drained by the well. For a hydraulically fractured well, the length of an infinite conductivity fracture which is equivalent to the actual finite conductivity fracture can also be determined.

This technique uses equations which fit the constant pressure transient radial flow solution. Also, polynomials have been developed which match pre-pseudoradial flow production from hydraulically fractured wells with dimensionless fracture conductivities of 0.01, 0.1, 1, 5 and 500. For pseudosteady state flow periods, a depletion or a pseudosteady-state equation can be used to match the performance of the well. By this technique, the well's entire production history becomes the equivalent of a very long drawdown test. This method is especially useful for low permeability reservoirs.

Advantages of this method over type curves include: greater resolution because the scale of the y-axis is linear rather than logarithmic, the capability of using superposition to account for pressure changes, the ability to include the derivative in the analysis, and better determination of permeability and skin effect because, as in a Homer plot, the fonner is dependent on the slope and the latter on the intercept. The entire production history, including pre-radial, radial, and pseudosteady state flow, can be used in the analysis.
Prediction of Future Well Performance, Including Reservoir Depletion Effects
Authors: Poe B. D. , Elbel J. L. , Spath J. B. , Wiggins M. L.
Published: December 2007

In the past, the reservoir material balance (voidage) effects occurring between the end of the measured (known) production history and future Inflow Performance Relationship (IPR) time levels have been commonly ignored in the computation of the future IPR behavior. Neglecting the reservoir voidage that occurs during the time interval between the end of the known production history and the future IPR time levels results in erroneous estimates of the future IPR behavior.

A detailed description is given of the mathematically rigorous technique that has been used in the development of a multilayer well performance simulator that properly accounts for the reservoir voidage effects. Some of the more significant results are also presented of an extensive effort to develop an accurate and computationally efficient well performance simulation model.

The reservoir can be considered to be multilayered, with mixed reservoir layer completion types and outer boundary shapes, drainage areas and boundary conditions. The well performance model can be used to simulate performance in three different operating modes: (1) constant wellhead rate, (2) constant bottomhole pressure, and (3) constant wellhead pressure. The transient performance of vertical, vertically fractured and horizontal wells can be simulated with this well performance model. The well performance model uses mathematically rigorous transient solutions and not simply the approximate solutions for each of the well types, as do most of the other commercially available well performance models.
An Evaluation of a Method to Predict Unknown Water Levels in Reservoirs and Quantifying the Uncertainty
Authors: Haynes Byron
Published: December 2007

A technique developed by Hawkins, et.al.(l) which integrates log and core data to predict water levels in hydrocarbon reservoirs has been evaluated using Alaska, Gulf of Mexico and North Sea reservoirs. The method is based on the construction of a synthetic capillary pressure curve from porosity, permeability, and water saturation at each available data point in the rock column. Regression analysis is used to estimate the Free Water Level (FWL) and an associated confidence interval. Conversely, if the FWL is known, the model can be used to estimate porosity, permeability, or water saturation, when two of the three parameters are known.

Typically, water contacts are located by drilling down structure wells, by obtaining pressure information from RFT's or DST's, or by capillary pressure data. Unfortunately, estimating water contacts from RFT's, DST's and down structure wells requires the water contact be penetrated. Available capillary pressure measurements, although scarce, can be used to estimate the vertical distance to the FWL, defined as the point of zero capillary pressure for the hydrocarbon/water column.

This is performed by superimposing the estimation of the water saturation, at that depth, on the curve. The distance to the FWL (or water contact) from that point can be identified by converting the capillary pressure curve to height above the FWL. Although penetration of the water contact is not required with this method, it does assume homogeneity of the rock column.

However, the advantage of the capillary pressure model technique over the above technique is that it does not assume the rock interval is homogeneous but uses measured porosity, permeability, and water saturation data. Additional strengths of the capillary pressure model approach to determining water level are: reliable FWL estimation in a transition zone, prediction of rock properties and water saturations, and a consistency check of capillary pressure data. No analysis of data consistency was performed in this work. However, it is apparent that since the model is a functional form of capillary pressure behavior, estimates of displacement pressures can be checked along with the shape of the data in the high pressure region.
Viscosity Correlations for Gulf of Mexico Crude Oils
Authors: Petrosky G. E. , Farshad F. F.
Published: December 2007

New empirical viscosity correlations for estimating dead oil, saturated oil and undersaturated oil viscosities have been developed as a function of commonly available field data.

Results show that these viscosities can be predicted with average absolute errors ranging from 2.91% for undersaturated oil viscosity to 14.47% for saturated oil viscosity.
Economic Potential and Optimum Steamflood Strategies for Trough Reservoirs of San Joaquin Valley, California
Authors: Hong K. C. , Use D. J.
Published: December 2007

Many trough reservoirs in the Western San Joaquin Valley, California, remain undeveloped because reserve bases are relatively small and occur in areas where thermal recovery activities have been low. Reservoir models with different configurations and reserve bases were used to compare the economic potential of these reservoirs and to develop guidelines for selecting reservoirs that can be economically exploited. The models were also used for determining the optimum steamflood strategies for the selected reservoirs.

The study showed that, for a trough reservoir to be an economical prospect, it should contain a minimum oil-in-place of 300 MSTB per pattern length along the trough between the synclinal axis and the gas-oil contact. Optimum steamflood strategy for such reservoirs includes: (1) placing the injector away from the synclinal axis and gas-oil contact, (2) having a row of producers updip from the injector and another near the synclinal axis, (3) starting the steamflood with an intermediate rate and high quality of steam, and (4) shutting-in steam injection after 5.5 years of continuous injection at a constant rate. This strategy can result in a annual rate of return of 20%.
Monitoring Circulatable Hole with Real-Time Correction: Case Histories
Authors: Griffith James E. , Ravi Kris M.
Published: December 2007

This paper presents case histories that demonstrate the utility and economy of monitoring circulatable hole (CH) immediately before a primary cement job, and then taking real-time action to correct any deficiencies detected. Although it is well established that effective hole-cleaning is critical to the success of a cementing job, a reliable method has only recently been made available for continuously monitoring the volume of the casing-to-wellbore annulus. Accurately determining the annular volume involved in the circulation process is the key to verifying that the hole is clean. Traditionally, operators have circulated the annulus for an arbitrary length of time; CH monitoring, however, has allowed for accurate assessment of hole condition with as much as 75% less circulation time before cementing.

The case histories presented describe methods used to correct CH deficiencies once they are established. These methods include

Pumping at higher rates Rotating and/or reciprocating pipe Adding spacers/flushes to the mud system

Based on the case histories presented, the following benefits can be derived from the new measurement method:

Circulation times originally averaging 2 hours may be reduced to as little as 30 minutes. Pipe movement can contribute greatly to the amount of CH. Operators can save the expense of certain casing equipment traditionally used to increase CH since they know 100% of the annulus is in circulation.
Expansion-Contraction Cycles for Cement Optimized as a Function of Additives
Authors: Talabani Soran , Hareland Geir
Published: December 2007

An experimental study was carried out to investigate the addition of specific additives to cement in order to eliminate the micro-fractures and micro-annuli that cause gas migration.

The experiments performed monitored the change in the cement slurry pressure during the setting of the cement. During the setting period of the cement, two time cycles of cement expansion and contraction were observed. This is due to the individual contributions of each part of the cement mixture. To obtain the optimum tightness of the cement, final optimum concentrations of the additives were obtained experimentally, where the cyclic pressure behavior of the cement was optimized for the best final cement results.

By utilizing the correct amount of Anchorage Clay, XC-Polymer, Ironite Scavenger, Ultrafine cement and Synthetic Rubber powder in a class G mixture at a given temperature and confining pressure, an impermeable cement mixture can be obtained. The correct amount of Synthetic Rubber used for cyclic pressure reduction is a function of cement setting temperature and pressure as well as the elastic properties of the rubber.

By using laboratory testing at different pressure and temperature with different rubber concentrations and elastic properties, it is estimated that the entire annulus can have an impermeable cement from surface to total depth. The difference in temperature and pressure with depth dictates the concentration and elastic properties of the rubber as the required expansion and contraction changes with depth.
Field Experience With Application of Blast Furnace Slag to the Drilling and Cementing Program in the Stratton Field, South Texas
Authors: Daulton D. J. , Bosworth S. J. , Pumphrey Bill , McCathy Scott , Cantu Rene , Clendennen John
Published: December 2007

In an attempt to provide better annular zonal isolation between productive (gas producing) and nonproductive (water bearing) intervals an unorthodox program was proposed and implemented based upon the incorporation of Quick Quenched Blast Furnace Slag (QQBFS) to both the drilling mud (universal fluid) and cement slurries. To date this is the deepest 7500 to 7900 ft (2345 to 2407 m) and hottest (225 F / 107 C bottom hole static temperature) dual application of QQBFS in the industry. A four phase program of progressive steps were taken with respect to field application during this project to implement cost saving measures without sacrificing quality services. During this project, fourteen dual 2 7/8" (7.30 cm) 6.5 lb/ft (9.67 kg/m) N-80, EUE production strings were successfully completed within 9.875/8.75 inch (25.08/22.225 cm) hole. A dramatic reduction in remedial squeeze operations has been reported with no squeeze jobs being performed on the last seven (7) wells completed. This type of success will benefit not only operators but state and federal regulatory bodies who are seeking to determine the "field worthiness" of QQBFS as a hydraulic material alternative for the oil and gas industry.
Water Shutoff Through Fullbore Placement of Polymer Gel in Faulted and in Hydraulically Fractured Producers of the Prudhoe Bay Field
Authors: Lane R. H. , Sanders G. S.
Published: December 2007

Selective shutoff of undesired water influx by nonselective (fullbore) placement of treating chemicals has been successfully demonstrated in production wells of the Prudhoe Bay field. This was accomplished through: (1) careful choice of candidates with known high conductivity water influx pathways (fault, hydraulic fracture, thief), (2) placement that exploited conductivity differences without zonal isolation, and (3) use of established polymer gel chemistry with previously demonstrated ability to shut off water preferentially to oil.
Large Scale Oil Lease Automation and Electronic Custody Transfer
Authors: Price C. R. , Elmer D. C.
Published: December 2007

Typically, oil field production operations have only been automated at fields with long term production profiles and enhanced recovery. The automation generally consists of monitoring and control at the wellhead and centralized facilities1,2. However, Union Pacific Resources Co. (UPRC) has successfully implemented a large scale automation program for rapid-decline primary recovery Austin Chalk wells where purchasers buy and transport oil from each individual wellsite. This project has resulted in two significant benefits. First, operators are using the system to re-engineer their work processes. Second, an inter-company team created a new electronic custody transfer method. This paper will describe:

The progression of the company's automation objectives in the area. The field operator's interaction with the system, and the related benefits. The research and development of the new electronic custody transfer method.
Downhole Emulsion Breaker Injection into the Lift Gas Stream
Authors: Lagerlef David L. , Sindelar Scott T. , Lelland William G. Me , Blumer David J.
Published: December 2007

A program is in operation at Prudhoe Bay, Alaska which injects emulsion breaker downhole with lift gas to enhance production. This paper addresses the reasons emulsions can limit production in a gas lifted well and the benefits that can be realized by breaking the emulsion downhole. A discussion of the simple but effective produced fluids emulsion screening test and the field implementation of downhole emulsion breaker in wells at Prudhoe Bay are included in this paper.

The emulsion breaker inhibits the formation of highly viscous emulsions by acting downhole. Along with increased production of nearly 3000 bopd for 22 wells, gas lift efficiency has been enhanced, heading of these wells has decreased, and less back pressure in the produced fluid gathering lines to the processing facility has been observed. The processing facilities have also experienced a reduction in the amount of emulsion breaker usage and a reduction in the volume of unbreakable emulsion pads going to produced water disposal.

Wells that are gas lifted, produce small fines, and generally are above 50% water cut may be susceptible to production of high viscosity emulsions. Downhole emulsion breaker injection can result in lower friction losses in the tubing string and other benefits in the entire production system. Downhole emulsion breaker injection can provide system wide benefits when tight emulsions are being produced.