bluuebunny/crossref_metadata_2025 huggingface dataset:
Linked Tectonics, A Powerful New Paradigm for Deciphering the Structural Evolution of the Menggala North Oil Field
Authors: Baroek Maria Patricia , Heidrick Tom L. , Kelsch Ken D.
Published: December 2007

A recent structural synthesis of the North Menggala field, Central Sumatra, reveals deformation patterns which are unequivocal and portray in detail the field's tectogenetic development over the past 30 million years (Ma). The EDGE-Voxelgeo-Gocad++ work process (Kelsch et al., 1998) was used to pick the high quality North Menggala 3D seismic volume. Ninety-five faults were identified, named, gridded and smoothed. The character of each fault and its deformation style, mode, orientation and age were noted. Well logs and biostratigraphic control from the Mangga #1 was used to identify seven Mio-Pliocene sequence boundaries. Along with the timing of fault displacement, particular attention was paid to the character and orientation of associated syndepositional extensional rollover and compressional folds, pop-ups, unconformities and pull-apart depocenters. Tectonostratigraphic data suggest Menggala North is an anticlinal trap produced by inversion of the South Balam half-graben along the N-S-trending South Balam Border Fault (SBBF). The trap is compound having evolved under three contrasting episodes of transtensional (F1, Eo-Oligocene), transpressional (F1L/2E, ± 28 – 21 Ma) and compressional (F3L, 3.8Ma – Recent) deformation. The derived Eocene-Recent near field maximum principal horizontal stress axis rotated relatively through time bearing 340°,±10° 060°,±10°, 050°,±10° and 040°,±5° respectively during F1 (45-±28Ma), F1L/2E(± 28-21 Ma), F2L (21-12.5 Ma) and F3 (12.5-0 Ma).

Mapped faults and folds are organized into six unique structural families that share common geometrical, kinematic and dynamic characteristics. The spatial and temporal distribution of fault-fold styles and modes of deformation unequivocally demonstrate that the six structural families are not the result of isolated structural events; instead, syntectonic faults and folds at different locations within the 3D volume are in kinematic communication. Strain associated with displacement on the 30°-35°, east-dipping listric SBBF was repeatedly partitioned vertically through the hanging-wall along favorably oriented elements of the fault framework. The flat-lying, through-going SBBF is clearly the unifying master structure that efficiently links the five structural families through time and space. The outstanding Menggala North example of low-angle linked tectonics has widespread application within our industry.
A New Method for Effective Reservoir Recognition Using Principal Component Analysis of Conventional Well-logging Interpretation in Fractured Complex Lithologic Reservoir
Authors: Zhu Yixiang , Yuan Shiyi , Liu Mingxin , Mu Longxin , Song Xinming , Yang Qiuling
Published: December 2007

In view of the fact that many factors, such as lithology, physical property, pore structure and fracture, control the classification of effective reservoir in fractured complex lithologic stratigraphy, and considering any pair of bi-variables(such as porosity to resistivity or capillary pressure to porosity, etc.)can not distinguish different kinds of zones, a new method to recognize effective reservoir by conventional well-logging principal component analysis is present in this paper. In this method, first, eight feature parameters to reflect reservoir lithology, physical property, fracture and pore structure are drawn on the basis of sensor response analysis and interpretation of conventional well logs. Then principal component analysis is applied to draw two main factors(F1 and F2) which include 85 percent information of the eight feature parameters. Secondly, points which come from pay zones and nonproductive zones are classified successfully by the crossplot of principal component F1 and F2, and finally, effective reservoir can be identified by pattern recognition. This method has been proven correct in more than 100 well's applications.
Evaluation of Pseudo Functions
Authors: Cao H. , Aziz K.
Published: December 2007

To determine the range of validity of pseudo functions for upscaling of multiphase flow with gravity and capillary pressure, the performance of different kinds of pseudo functions is evaluated under different gravity numbers, capillary numbers and upscaling levels. The performance of pseudo functions can be measured as the percentage error between the results of fine grid simulation and the results of coarse grid simulation using pseudo functions. Furthermore, the performance can be shown as the bar graphs of percentage error for varying gravity number, capillary number and upscaling levels. A two-dimensional homogeneous water flooding case and a three-dimensional heterogeneous case have been studied using pseudo functions (Jacks et al.2, Kyte and Berry3, Pore Volume Weighted7, Flux Weighted Potential10, Modified Stone*4, Streamline5), and pseudo function performance has been evaluated under different conditions. Some guidelines for the use of pseudo functions are provided. The results show that (1) all of the pseudo functions have similar performance for the homogeneous case considered; (2) only the Jacks et al. pseudo function can be used in all cases; (3) using pseudo functions (except Jacks et al.) is unreliable, especially for the highly heterogeneous cases.
Fiber Optic Temperature Monitoring Technology
Authors: Carnahan B. D. , Clanton R. W. , Koehler K. D. , Harkins G. O. , Williams G. R.
Published: December 2007

Fiber optic distributed temperature monitoring of downhole conditions is an emerging technology that can be used to obtain important reservoir temperature information where conventional methods have failed. Due to the development of fiber coatings and improved deployment techniques, fibers are now used reliably up to 480 °F in Aera Energy's California field. Case lis an installation on tubing in rod pump wells has been useful in detecting early steam breakthrough and is expected to reduce the need for temperature observation (TO) wells in the future. Case 2 is a permanent installation on the outside of casing in TO wells which is used to determine accurate reservoir temperature profiles. In one example, the fiber has shown fluid migration behind pipe which was remediated successfully before the steam reached the surface. Case 3 is a failed attempt to use fiber to continuously monitor multilateral horizontal well temperatures to determine relative fluid contributions of the wellbores without shutting in the well.
Dip Interpretation from Resistivity at Bit Images (RAB) Provides a New and Efficient Method for Evaluating Structurally Complex Areas in the Cook Inlet, Alaska
Authors: Ford Gary , Hartner John , Grether Bill , Waters Doug , Cryer Jesse
Published: December 2007

Many of the producing fields in the Cook Inlet area of Alaska are found in tightly folded, asymmetric, fault bounded, anticlinal structures that are not easily imaged with modern seismic. Historically, exploration wells have been drilled initially on the crest of these features, only to find at total depth that the bore holes had deviated off the crest and were several thousand feet down dip from the initial structural objective. In Cook Inlet, where difficult hole conditions prevail, a new approach to real time structural analysis was needed to evaluate complexly folded features as they were being drilled.

Acquisition of structural dips while drilling a potentially complex structure was critical in evaluating the position of the well on the structure and steering it if necessary. Measurement while drilling (MWD), coupled with logging while drilling (LWD) provided the data necessary to enable a successful drilling operation and well completion.

The Resistivity-at-the-Bit (RAB)* tool was used during drilling to acquire resistivity measurements close to the bit. These resistivity measurements were then used to produce images and calculate dips similar to a Fullbore Formation MicroImager (FMI)*. Modifications to the structural model were continually made based on interpretations from the RAB images, allowing the bore hole to be steered towards a preferred structural position.

FMI and RAB images and interpreted dips were compared in a shallow interval to evaluate the quality of RAB data. Excellent agreement in measurements between the tools resulted in the continued use of RAB for the duration of the well.
Prediction of Steamflood Performance Using Carbon Isotope Signatures of CO2
Authors: Juprasert Max S. , Haught Mark B. , Schoell Martin
Published: December 2007

The economics of a steamflood project are largely dependent upon the rates at which steam is injected and oil is recovered. One of the dominant features of the steam drive process is the tendency of steam to override the reservoir and break through in the producing wells. To accommodate this situation, engineers are challenged to achieve the balance between production of heated oil and by-passed steam. A significant effort is being made to overcome this difficulty with the aid of a by-product gas tracer, carbon dioxide. The isotopic signatures of this non-condensable gas can be used to predict the changes in reservoir dynamics resulting from the reaction of reservoir rock and fluids with injected steam.

Steam-enhanced oil recovery often produces large quantities of CO2. Two primary sources are oil derived CO2 and CO2 associated with injected steam. These two distinct sources can be differentiated by the carbon isotopic composition of the CO2. The CO2 generated from oil tends to be depleted in the heavy isotope of carbon, 13C, while water-derived CO2 is enriched in 13C. Results of isotope analyses of CO2 from the Cymric field steamflood show that CO2 in good flood response wells is primarily derived from oil and CO2 in steam breakthrough wells is mainly water/mineral derived. These results suggest that carbon isotopes of CO2 are useful natural tracers for its origin and may be used as a diagnostic and possibly predictive reservoir management tool for monitoring steamflood performance.
A Focus Development for Heavy Oil Reservoir: The Last Frontier At the South Belridge Field
Authors: Chiou C. S. , Badger S. D. , Carlsen M. M. , Pereira K. S.
Published: December 2007

The Tulare reservoir of the South Belridge field, CA has been under steam drive since the 1970s. A variety of field development opportunities remain in the southern portion of the field. Over the past two years, Aera Energy has implemented a focus development project to execute the growth strategy for the field. To date, 60 horizontal and 70 vertical producers and 120 steam injectors have been drilled and completed in a 640-acre area. This paper focuses on development strategy, development optimization using reservoir simulation, economic evaluation, and development implementation.

Reservoir modeling has been proved to be a powerful tool for (1) assessing alternative development strategies between horizontal and vertical wells for a multi-sand reservoir, (2) planning optimum pattern configuration and well spacing, and (3) assessing reservoir performance impacts of various operating policy options.
Production Optimization Using a Dynamic Gas-Lift Simulator, History Case
Authors: Muñoz Efrén A. , Quintero Nylian
Published: December 2007

Gas injection is a very popular artificial lift method, at present a very high percentage of wells produce under this mechanism, hence it is very important to understand all operational and practical effects that are associated when an oil well is producing under gas-lift. Its optimization is critical to maximize oil production using the optimum amount of gas required and to justify the use of this technology as nowadays other artificial lift methods are very efficient too. Although, commercial softwares can simulate a gas-lifted well, all of them consider steady-state conditions, however the injection of gas through orifices or valves is a totally dynamic situation1.

This paper shows some real examples where the use of a dynamic simulator was necessary to understand both well behavior and model simulation specifically when trying to optimize wells producing under unstable conditions.

The generation of realistic performance curves under those circumstances becomes critical, as they are the bases of any gas-lift optimization project as shown in this paper.
A Field Application of Lateral Drilling from an Existing Well for Improved Recovery in Low Permeability Sands
Authors: Bigno Y. , Coombes T. , Lheure S.
Published: December 2007

The Dunbar Field, lying in the East Shetland Basin in Block 3/14a (U.K.C.S.), contains a significant proportion of its volatile oil in thick (90 m), low permeability sands (1-2 mD) of the Brent Group/Upper Massive Sands. To achieve secondary recovery from these ‘tight’ formations, high productivity horizontal or multi-lateral drains had to be designed as withdrawal points. The drilling of such wells in a highly compartmentalized and complex reservoir was not without significant risk, particularly in relation to the known levels of lateral and vertical heterogeneity.

An early development well, D05, originally planned as a water injector, provided an opportunity to evaluate the benefits of such horizontal drains within the ‘tight’ zones. This vertical well also contained thin, high permeability (100 mD) layers below the thick low permeability ‘Upper Massive Sands’. A lateral drain (D05Z) was planned within the Upper Massive Sands whilst the original vertical hole would be retained. The two sections would be completed in order to produce from both the permeable and ‘tight’ zones.

This paper presents the full process of the evaluation of the pre-drill vertical well and the reservoir studies that followed. These studies led to the recommendation to drill a lateral drain of very complex geometry while retaining the production from the existing vertical section. The 960 m lateral drain that was subsequently drilled complied with very strict recommendations and guidelines and constituted a major drilling achievement. The production performance of the lateral drain was also a success and increased Total and Elf's confidence in the use of such complex wells (horizontal, dual drains, multi-lateral drains). In fact, they are now the chosen option for the development of the Dunbar tight zones.
Strategy Optimization for Matrix Treatments of Horizontal Drains in Carbonate Reservoirs, Use of Self-Gelling Acid Diverter.
Authors: Bazin B. , Charbonnel P. , Onaisi A.
Published: December 2007

Matrix treatments of horizontal drains in carbonate reservoirs require large amounts of acid, leading to economic-cost and pumping-time considerations. Therefore it is essential to improve candidate selection and to optimize treatment design, especially acid volume, placement and diverting technique.

This paper discusses first, on a theoretical basis, the formation damage effects on horizontal well productivity. Hence, a stimulation strategy is being defined.

The effectiveness of a Self-Gelling Acid Diverter (SGAD) is evaluated by screening the crosslinking conditions with single core flow tests. In particular, the effects of the acid strength in both the diverter stage and the neat acid stage are scrutinized. The diverting effect is also analyzed with a dual core flow apparatus specially designed to reproduce down-hole injection conditions in horizontal wells. The efficiency of the self-gelling agent is evaluated from fractional flow measurements and X-Ray CT visualization of the wormhole penetration. Finally, the study is completed with radial core flow experiments, previously damaged with a drilling fluid.

Design and operational guidelines are deduced from the experimental results and a case history is presented.
Prediction of Wormhole Population Density in Carbonate Matrix Acidizing
Authors: Huang T. , Zhu D. , Hill A. D.
Published: December 2007

The efficiency of a carbonate matrix acidizing treatment relies strongly on the dominant wormhole channels formed during the treatment. We have developed and confirmed a theory to predict when the dominant wormhole channels are most efficiently created. Based on this theory, a wormhole population density model was developed.

In a carbonate acidizing treatment design, the acid volume needed to bypass the near wellbore damage area or penetrate a distance away from the wellbore depends not only on wormhole propagation distance but also on how many wormholes are created. This study investigates the wormhole population density, which means how many wormholes per area of rock surface or per wellbore length will be created. The study is based on the following strategy. For a given rock/acid system, the optimal acid injection flux at which dominant wormholes are initiated is obtained from the wormhole propagation theory. For a given formation, a corresponding pressure gradient at the optimal acid flux is calculated. This pressure gradient is also called the wormhole initiation pressure gradient. When a wormhole is initiated at an arbitrary point along the wellbore, the local pressure distribution is disturbed, resulting in lower pressure gradients into the formation in the region surrounding the wormholes. In this region of reduced pressure gradient and hence, reduced flux, initiation of other wormholes is suppressed. At a sufficient distance from the initial wormhole, the pressure field is undisturbed and other wormholes will develop.

We numerically simulated the flow field around a wellbore with a wormhole extending into the formation to quantify this phenomenon. From this study, we predict the wormhole population density along a wellbore as a function of the acidizing conditions. An example is provided to show the application of the wormhole population density model in a treatment design. Fluid loss through the walls of the wormholes and wellbore, optimal acid injection flux, and wormhole propagation rate are also taken into account in this example. The example shows how the wormhole population density model is used to predict the required acid volume (gal/ft) to yield the desired productivity improvement.
Permeabilities and Skins in Naturally Fractured Reservoirs: An Overview and an Update for Wells at Any Deviation
Authors: Lietard Olivier
Published: December 2007

Though matrix and secondary porosity permeabilities of a naturally fractured reservoir are generally well-known since the work of Muskat (1949), notions of skin remain extremely vague to a majority of reservoir engineers. This paper aims at alleviating a problem which considerably impairs the understanding of such complex reservoirs.

A detailed mathematical study, similar to Muskat's, is first presented as a reminder of his equation giving the permeabilities of a rock with no primary porosity and a pattern of natural fractures, either conjugated (two parallel systems at an angle) or not. The same tool is then used to demonstrate that a vertical well connected to the natural fractures does show up a negative skin, which is a simple function of the well radius and the spacing of the fractures.

The Hawkins’ definition of (positive) damage skin is then applied to vertical wells. Both a "missed target" skin (well not connected to the fractures) and a fracture invasion damage skin (by drilling mud or heavy ends deposition) are defined. The missed target skin explains why Dennis Beliveau's Productivity Improvement Factor is much better in naturally fractured reservoirs. The mechanism of mud invasion into fractures is reviewed and the related skin calculated as a function of the mud loss volume per unit of drilled length.

Though Hawkins’ skin can also be defined in deviated wells (as Renard and Dupuy did in horizontal ones), the partial completion skin approach (e.g. Brons and Marting's) is shown to be more applicable after production has been initiated. Such a skin is calculated as a function of the number of fractures connected to the well at any time, and of their spacing in the reservoir.
Completion Efficiency Measures for High-Permeability, Unconsolidated Sand Environments
Authors: Pahmiyer R. C. , Fitzpatrick H.J. , Dugan J.
Published: December 2007

This paper describes, discusses, and compares the relative value of different completion-efficiency or completion-quality measurements that the industry currently uses to grade the technical success ofhigh-permeability sand-control completions. Some of the measures discussed are flow rate, total drawdown, productivity index, skin factor, and a permeability-adjusted skin factor. The paper presents the advantages and disadvantages of each measurement, along with a discussion of the variables that affect the measurement.

Although most people in the industry can agree on the variables, procedures, and methods that affect completion efficiency, how to best measure the completion efficiency is often debated. This paper presents an effective method to determine completion efficiency, a detailed method of estimating the completion efficiency measure, and the targets and values being achieved within the industry.

The methodology discussed includes corrections for turbulence effects, partial completion effects, and friction losses between the measuring point and perforations. Guidelines and procedures for collecting the required data are also presented.
The Development and Application of a Method for the Evaluation of Sand Screens
Authors: Ballard Tracey , Kageson-Loe Nils , Mathisen Anne Mette
Published: December 2007

This paper describes the development and application of a laboratory procedure for the evaluation of screens for sand control. The driving force for this study was to provide an independent evaluation of all screens on the market, in particular, the new generation of premium screens. The test addresses both aspects of screen performance, namely sand retention efficiency and plugging potential. The difficulties in setting up such a test are discussed, with particular attention paid to the elimination of experimental artefacts. Some of the pitfalls that may be encountered in laboratory evaluation of screens are highlighted.

The developed method has been used in screen selection tests for a particular field, and these results are also presented. The data illustrate the sensitivity of the technique for evaluating a range of screens on the same sand, and reasons for the differences in screen performance are explored. Furthermore, it was observed that the method of particle size analysis will affect the apparent particle size distribution of a sand. As a result such parameters as the uniformity coefficient may be completely different for the same sand depending on the method of size measurement.
Rigless WSO Treatments in Gas Fields. Bullheading Gels and Polymers in Shaly Sands: Italian Case Histories
Authors: Burrafato G. , Pitoni E. , Vietina G. , Mauri L. , Chiappa L.
Published: December 2007

Gels are used worldwide to control water co-production in gas and oil wells (WSO treatments) but the criticality of a correct placement in the Italian scenario had strongly limited their use in this Country. For instance, in gravel packed wells or in wells where the "ID casing/ID tubing" ratio is over 2.5, inflatable packers cannot be efficiently used for gel diversion; moreover, dual injection has to be usually applied with these tools, making a treatment very often too expensive and, as a result, unacceptable.

A review of water problems and displacement data collected during past matrix treatments performed in Italian gas fields led to the study of possible alternatives for treatments to be performed using standard crosslinked polymer and unusual displacement techniques. Relative Permeability Modifier (RPM) polymers were also considered and lab tested for WSO in shaly sands because the use of gels is still considered too risky. In fact, most of the treatments performed in Italy have to be performed bullheading in order to reduce the cost of the operations, making WSO treatments more attractive.

In this paper a brief summary of laboratory activities for a correct selection of polymers and gels, suitable for shaly, low permeability sands are reported as well as field treatments data and results.

Bullheading technique seems to be the only cost-effective and field proven placement method for rigless WSO treatments to produce marginal gas reserves from shaly, depleted, low temperature, multilayered reservoirs.
Testing of Down Hole Oil/Water Separation system in Lacq Superieur Field, France
Authors: Chapuis C. , Lacourie Y. , Lançois D.
Published: December 2007

As water production in mature oil fields continues to increase, we as an industry are continually challenged with how to handle the ever-increasing volumes of produced water. Downhole separation is attractive but needs further investigation about oil in water content after separation and its effect on formation damage of injection zone This paper is a description of field testing of Down hole Oil/Water Separation technology in well LA 90, Lacq Superieur field, SW France where oil and water streams are separately produced to surface in order to control fluids quality

The deviated well produces an heavy oil with high water cut from a carbonate reservoir. The new well completion consists of a hydrocyclone for oil/water separation and of electric submersible pump. The system can handle a flow rate from 150 to 270 m3/d with a water cut of about 97%. All parameters including the two well head string pressures, flow rate and pump speed were investigated during the flowing periods. Water cut, oil in water and droplet size were measured

Issues revolving around the quality of produced fluids are reviewed and preliminary results from the field trial are presented, specially the remaining oil in the water stream The improved knowledge of emulsion characterization leads to a better use of downhole separation system and a more accurate prediction of formation damage in the injection zone
Numerical Simulations of Hydraulic Fracture Link-up of Perforations at Deviated Wellbores
Authors: van de Ketterij R. G. , de Pater C. J.
Published: December 2007

A fracture starting from one perforation might fail to link-up with adjacent perforations and the fracture may break up into multiple fractures. Failure to link-up neighbouring perforations and the occurrence of multiple fractures reduce the communication between a propped fracture and the well.

Many experiments have been performed to study the near wellbore fracture geometry. They give a good insight in the impact of the treatment parameters on the near wellbore fracture geometry. However, they urge the need for a detailed numerical study of the first stages of fracture propagation as the processes that cause the near wellbore fracture geometry are not well understood.

The stress distribution on the wall of the perforations plays a decisive role as to where fractures initiate. In this paper we discuss the stress distribution around perforations around an arbitrary oriented borehole. We will present the results of an analytical model and a numerical model. Although the calculations give a fairly good description of the stresses near the wall of the perforations they do not always reproduce the site from which the major fractures initiate and give no explanation for the existence of multiple fractures.

This paper discusses numerical fracture propagation simulations from a perforated deviated borehole. We discuss fracture propagation as function of in-situ stresses, pressure, and perforation orientation. We will also discuss the link-up of starter fractures from adjacent perforations. The simulations provide a way to get a better insight in the processes that lead to the near wellbore fracture geometry. With this insight the fracturing treatments can be optimised and the formation of multiple fractures can be limited.
Impact of Formation Damage on Sand Production in Deep Eocene Reservoirs, Lake Maracaibo, Venezuela: A Case History
Authors: Tovar J. J. , Zerpa L. , Guerra E.
Published: December 2007

In the deep and layered Eocene reservoirs of southern Lake Maracaibo, Western Venezuela, some of the most productive fields such as Ceuta were discovered in 1978. Sanding problems are common in VLG 3676, Block VII, one of the most important reservoirs in the area where hydrocarbon production is from various intercalated thin. A major initiative was started in 1996 to evaluate the geomechanical, reservoir, drilling and production profile of the field in order to identify the problems and the options available to maximise production and final recovery. Intensive laboratory and field testing programs were carried out to develop the geomechanical model required and identify potential formation failure mechanisms. A review of drilling and completion practices indicated that formation damage contributed significantly to the sanding problem, while collapsed casing and, severe equipment erosion made, loss of production and well integrity common in the area. The evaluation of reservoir and production data from five (5) wells in order to quantify formation damage revealed skin values > 80. The well model that was developed indicated that optimising drilling and completion practices could minimise and in some cases eliminate the sanding problem. A number of recommended changes to existing practices are now being implemented.
Reversible Invert Emulsion Drilling Fluids: Controlling Wettability and Minimizing Formation Damage
Authors: Patel Arvind D. , Growcock Frederick B.
Published: December 2007

Novel emulsifiers in reversible invert emulsion drilling fluids offer a unique opportunity for operators to control the wettability properties of the mud. Reversibility of the invert emulsion will provide economic advantages in drilling and completion and increased productivity. Optimal drilling performance and formation damage control are usually achievable by oil wetting the drill solids, formation and drillstring. On the other hand, optimal completion of a well - filtercake removal and cement bonding -- and disposal of drilled cuttings are best achieved by maintaining all surfaces water-wet. Filtercake removal is especially critical in the completion of horizontal openhole wells.

The reversible invert emulsion drilling fluids can be readily and reversibly converted from a water-in-oil emulsion to an oil-in-water emulsion and back to a water-in-oil emulsion using an acid-base chemical switch. This drilling fluid system is simple and easy to run without any drastic changes in current invert-emulsion technology. A novel surfactant package forms an invert emulsion in the presence of lime and a direct emulsion in the presence of acid. Reversible emulsion technology uses new emulsifiers that allow the drilling fluid to cycle between oil-wetting and water-wetting as frequently as one desires. Protonation and deprotonation of the surfactant is used to control the emulsion phase without drastic and uncontrollable viscosity swings.

The reversible invert emulsion drilling fluid has been successfully run in a North Sea well. The paper presents field data illustrating the economic benefits of this system and discussion on how the ability to change wettability can influence drilling and completion performance.
Role of Polymers on Formation Damage
Authors: Audibert Annie , Argillier Jean-François , Ladva Hemant K. J. , Way Paul W. , Hove Arvid O.
Published: December 2007

The filter cake is critical in preventing reservoir invasion by mud filtrate. This is of particular importance in open hole completions where damage cannot easily be bypassed. However little is known about the selectivity of the filtercake in controlling which components will invade the reservoir. An EC funded consortium between Statoil, Schlumberger Cambridge Research, and Institut Frangais du Petrole has focussed on the fundamental mechanisms of formation damage in order to design wellbore fluids for minimizing fluid losses and optimizing reservoir productivity.

Polymer invasion of the reservoir has been shown to have a great impact on permeability reduction. Possible damage with a typical polymer based drilling fluid was evaluated in terms of static and dynamic filtration, determining cake permeability, filtrate composition, and oil permeability reduction after mud exposure. The effects of polymers on filtercake properties and filtrate composition were found to be related to their incorporation into the filtercake and more specifically to their interactions with solids and solutes present in the fluid. Filtration conditions were also found to have significant effects. Measurement of polymer adsorption and retention in cores as a function of polymer structure, and formation saturation were also made to characterise the effects of mud filtrate on producing formations. This was correlated to the observation of rock invasion and damage using computed tomography (CT) imaging.

The improved understanding of formation damage caused by polymers is used to discuss criteria for effective and non-damaging fluid loss polymer architectures.
The Near-Term Supply and Demand Outlook for the Petroleum Industry
Authors: Winger John G.
Published: December 2007

This paper is in two parts. The first will deal with the current statistical position of the petroleum industry and the supply and demand outlook for the remainder of 1955 and the year 1956. Supporting the conclusions reached will be an explanation of forecasting techniques used.

The second portion is a discussion of several economic factors operating in the direction of chronic oversupply for the industry. Brought into focus is the impact of these elements on postwar developments and their probable effect in the near-term future.

The title of this paper announces that I am to discuss the near-term supply and demand outlook for petroleum. Near-term in this instance is intended to include the current year and 1956.With three-fourths of 1955 now history, we have a reasonably good idea what the final results will be - providing no abnormal factors suddenly enter the picture. But for 1956 it becomes necessary to bring into play various forecasting techniques.

While even the most carefully prepared forecast is admittedly subject to considerable error, it remains nevertheless a useful tool. For policy guidance a look-ahead is necessary. Actual conditions which subsequently deviate from the original estimate as a result of abnormal factors or faulty conclusions usually cast their shadows sufficiently early to permit timely adjustment in operating procedure.

Although specific volumes and rates of change will be discussed today, I shall consider the forecast successful if actual results in 1956 are within 2 percentage points of the predictions. Our primary objective is the direction in which the industry will move rather than the exact course.

Our forecasting is facilitated by the abundance of statistical data available. Consumption records from the past plus reliable figures for the number of petroleum consuming units expected to be in use permit satisfactory end-use studies. Barring some international incident, weather and general business conditions are the factors most likely to throw a forecast off.

Because oil heating represents such an important portion of petroleum demand, a change from normal winter weather conditions has a pronounced impact on consumption rates. With the last 8 winters averaging warmer than normal, there is the temptation to assume a continuation of that trend next year.
Improved Cementing of High Temperature Oil and Gas Wells Through Computer Applications
Authors: Crinkelmeyer Oliver W.
Published: December 2007

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

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

One of the primary problems in designing cement systems for deep, hot wells is the wide variation in performance of oil well Portland cements. Thickening times between Portland cements. Thickening times between similar API cements may vary by more than 100 per cent under severe well conditions. To help minimizes this problem, a special computer program was used to compare the working time of eleven oil well cements with their chemical analyses. This resulted in the isolation of the chemical factors which have the greatest effect on cement thickening time at a particular set of conditions. The equations developed provide the capability to predict cement working times under specified well conditions when a few chemical parameters of the cement are known.

Introduction

The trend toward deeper and hotter oil wells and the expanding search for geothermal energy has made it necessary to examine the performance of Portland Cement at higher performance of Portland Cement at higher temperatures and higher pressures. Under these conditions, slurry working times have not been as predictable as they are at lower temperatures and pressures.

Studies have been made which identify the compounds formed in set cement, and the physical and chemical conditions required to develop physical and chemical conditions required to develop stable compressive strengths at higher temperatures. However, very little has been done to define the parameters that determine the working time of retarded Portland Cement systems used in oil and gas wells. To help develop better high temperature retarders, and to explain fluctuations in existing data, the computer has been incorporated into high temperature cement testing. The results presented here show that not only can the computer be used to predict working times at various retarder concentrations, but it can also be used to define the parameters most important in determining the parameters most important in determining the working time of a particular cement system.
Simulation of Water- and Vapor-Dominated Hydrothermal Reservoirs
Authors: Mercer James W. , Faust Charles R.
Published: December 2007

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

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

A two-dimensional (areal), two-phase (steam-water) model for the numerical simulation of both water- and vapor-dominated hydrothermal reservoirs is presented. The model describes transport of heat and flow of compressed water, steam-water mixtures, and superheated steam in a porous medium. The continuity equations for porous medium. The continuity equations for steam and for water are combined and, assuming that capillary pressure is negligible and that conditions of local thermal equilibrium prevail, are reduced to two nonlinear partial differential equations in which the dependent variables are fluid pressure and enthalpy. The mass transfer (vaporization) terms are also eliminated when the continuity equations are combined.

The two partial differential equations are solved simultaneously using a Galerkin-finite element technique for the spatial terms and finite-difference techniques for the temporal terms. The model is applied to example problems consisting of a hypothetical hot-water reservoir and a hypothetical two-phase reservoir. Model calculations are compared with calculations from other numerical work involving a finite-element model that is restricted to the flow of compressed water, and a finite-difference model that is restricted to the vapor-pressure curve (that is, steam-water mixtures). Results indicate that this numerical model can be used to evaluate both types of reservoirs.

Introduction

Interest in new sources of energy has produced recent concern in the potential of produced recent concern in the potential of geothermal energy. Although evaluating this potential is important, even more important is potential is important, even more important is estimating the quantity of recoverable energy and the rate at which this energy may be recovered, for these values will ultimately aid in determining the economic feasibility of developing a geothermal reservoir. The recoverable energy in a geothermal reservoir may be estimated by using a mathematical model. In general, the model utilizes numerical techniques because of the complex nature of the equations and boundary conditions describing a geothermal or hydrothermal reservoir.

Hydrothermal reservoirs are classified according to the dominant fluid as either (1) a hot-water system or (2) a vapor-dominated system. Examples of hot-water reservoirs include the Wairakei, New Zealand, field and the Cerro Prieto, Mexico, field; vapor-dominated Prieto, Mexico, field; vapor-dominated reservoirs include the field at Larderello, Italy, and The Geysers, California.
Performance of the Hemlock Reservoir-McArthur River Field
Authors: Diver C.J. , Hart J.W. , Graham G.A.
Published: December 2007

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

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

The pressure maintenance program by water injection in the Hemlock Reservoir of the McArthur River Field - Cook Inlet, Alaska - has been extremely successful. This is one of the largest offshore water injection projects in North America. Constant engineering study and surveillance coupled with an aggressive attitude on the part of the owners has resulted in a program which will maximize productivity and ultimate recovery from the reservoir.

Introduction

The McArthur River Field is located about 70 miles southwest of Anchorage, Alaska, in Cook Inlet (Fig. 1). The field was discovered in 1965 by the Union-Marathon Grayling Well No. 1-A. The field outline was subsequently delineated by ten additional exploratory wells drilled by four operators over a period of two years.

Current production is 104,000 BOPD from 49 wells which have been drilled from three platforms. Initial oil-in-place was in excess platforms. Initial oil-in-place was in excess of one billion barrels and cumulative production through June 1975 was about 250 production through June 1975 was about 250 million barrels.

The field was unitized as the Trading Bay Unit in August 1967 before development drilling operations had commenced. A unique feature of the Unit Agreement provided for equity redeterminations at specified intervals. This was a necessary and desirable vehicle to encourage unitization prior to development drilling and recognize subsequent data derived from development drilling. Union Oil Company of California is Unit Operator with Union, Marathon Oil Company and Atlantic Richfield Company as Suboperators for the three drilling and production platforms. The field has been effectively platforms. The field has been effectively engineered through the Unit Engineering and Planning Group which was formed in 1967 and has Planning Group which was formed in 1967 and has taken an active and continuing part in reservoir management throughout the life of the field. Engineering guidance led to the early installation of pressure maintenance facilities and to the installation and subsequent expansion of artificial lift on board the platforms. Engineering evaluation of the field-wide injection pressure maintenance project has been continuous pressure maintenance project has been continuous since its inception and engineering study led to the introduction in 1973 of an extremely successful infill drilling program which is still in progress.
Performance Matching for a North Sea Gas Field
Authors: Willcox P.J. , Riley H.G.
Published: December 2007

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

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

The offshore Leman Field is a complex, low permeability, highly faulted reservoir. Cluster development from platforms and uncertainties in the structural interpretation complicate matching of past performance with a simulation model. This paper sets out in detail the development of a history match proceeding by logical steps, each supported by independent evidence.

Introduction

The Leman Field is one of the world's largest offshore gas fields with nearly 14 TCF of gas originally in place. It was discovered in 1966, 30 miles offshore in the U.K. North Sea in 100 feet of water (Figure 1). Production commenced in 1969 and by Production commenced in 1969 and by mid-1975 the field had produced 1.5 TCF from 130 producing wells completed from ten platforms. Amoco (U.K.) Exploration Company is the operator for the East Leman Unit which comprises approximately the eastern half of the field (Figure 2).

Design and construction of a platform and the drilling of 12 to platform and the drilling of 12 to 16 wells there from requires two to three years. Compression facilities must also be ordered three years in advance to ensure timely delivery. These long lead times, combined with the ultra-expensive offshore operation in an hostile environment, require accurate long range predictions of reservoir performance.

The Rotliegendes Formation of Lower Permian age in the Leman Field is a highly faulted, low permeability, heterogenous sandstone, averaging 800 feet in gross pay thickness. The wide areal variation in rock characteristics and the cluster type development necessitated by offshore platform operations present a difficult problem in constructing a mathematical model that matches the observed pressure production performance. Wide vertical production performance. Wide vertical variations in porosity would normally require a three-dimensional model if a conventional permeability correlation were to be used. Synthesis of a two-dimensional model was made possible by use of the statistical parameter, coefficient of variation of porosity, parameter, coefficient of variation of porosity, correlated with the well test data.
Field Polymer Stability Studies
Authors: Bilhartz H.L. , Charlson G.S.
Published: December 2007

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

This paper presents the highlights of the results obtained from a field test designed to study shear degradation of polyacrylamide polymers. Recently, most major research polymers. Recently, most major research laboratories have been studying shear degradation in the laboratory; however, no extensive field testing has been reposed.

The field test consisted of injecting Pusher 700 into a well at four different rates Pusher 700 into a well at four different rates and back producing the polymer fluid. Laboratory measurements were made on location to determine polymer quality. These measurements were made in an oxygen-free environment in order to minimize chemical degradation of the polymer. Both surface and bottom hole sampling techniques were employed. Fluid samples were bottled under controlled conditions and brought back to our research laboratory for core flood experiments. Fluid entry profiling of the well was done before, during, and after polymer injection; and pressure transient tests were; conducted to pressure transient tests were; conducted to determine in situ polymer effectiveness. These tests indicated that the combined effect of shear degradation and calcium ion contamination due to anhydrite dissolution could reduce polymer effectiveness to an economically unattractive level.

Introduction

The influence of mechanical or shear degradation on the effectiveness of partially hydrolyzed polyacrylamides as mobility control agents has been receiving considerable attenbon. One of the earliest papers indicative of the importance of this involved the use of these polymers to control water production in oil polymers to control water production in oil wells. More recent studies have involved laboratory experiments designed to predict the degree of mobility control loss to be expected during the injection of polymers into a porous medium.