bluuebunny/crossref_metadata_2025 huggingface dataset:
Severe Slugging Attenuation for Deepwater Multiphase Pipeline and Riser Systems
Authors: Tengesdal J.Ø. , Sarica Cem , Thompson Leslie
Published: December 2007

Recently, exploitation of offshore petroleum reservoirs has moved to ever increasing water depths. Production from fields in water deeper than 1800 m is now a reality. The use of long deep-water risers that conduct production from multiple wellheads on the sea floor to the surface predisposes the system to severe slugging in the riser for a wide range of flow rates and seabed topography. Considering the length of the deep-water risers, the problem is expected to be more severe than in production systems installed in shallower waters. Severe slugging could occur at high pressure, with the magnitude of the pressure fluctuations so large as to cause a shorter natural flow period with subsequent consequences such as premature field abandonment, loss of recoverable reserves and earlier-than-planned deployment of boosting devices.

In this study, a novel idea to lessen or eliminate severe slugging in pipeline-riser systems has been thoroughly investigated. This idea was first proposed by Barbuto3, and later developed independently by Sarica and Tengesdal9. The principle of the technique is to transfer the pipeline gas to the riser at a point above the riser-base. The transfer process will reduce both the hydrostatic head in the riser and the pressure in the pipeline, consequently lessening or eliminating the severe slugging by maintaining the steady-state two-phase flow in the riser.

An experimental study has been conducted using a 7.62 cm. inner diameter riser (14.63 m high) and pipeline (19.81 m long) system. A broad range of data was collected from the facility both in the severe slugging and stable regions. It was found that currently available severe slugging models do not predict the severe slugging region accurately for larger diameter pipes. Data acquired with the external gas bypass have proven the proposed elimination technique.
Surface Gravity Monitoring of the Gas Cap Water Injection Project - Prudhoe Bay, Alaska
Authors: Brady Jerry L. , Ferguson John F. , Seibert John E. , Chen Tianyou , Hare Jennifer L. , Aiken Carlos V. L. , Brown Fred J. , Klopping John M.
Published: December 2007

The world's first 4-D surface gravity surveillance of a waterflood is being implemented at Prudhoe Bay, Alaska. This monitoring technique is an essential component of the surveillance program for the approved Gas Cap Waterflood Project (GCWI) at Prudhoe Bay. A major factor in the approval of the waterflood was to show that water movement could be economically monitored with a very limited number of wells. Conventional monitoring techniques would have been cost prohibitive due to the requirement for drilling numerous new surveillance wells. Modeling studies indicate that density changes associated with water replacing gas can be detected using high-resolution surface gravity measurements. Field tests at Prudhoe Bay have demonstrated that sufficiently accurate gravity data can be obtained.

This paper will discuss both inverse modeling of time differenced gravity maps and four test surveys that have been completed to perfect the gravity measurement technique. Forward and inverse gravity modeling was carried out on a suite of reservoir simulations of the GCWI. Differences in the gravity field with time reflect changes in the reservoir densities, which in turn reflect pore fluid content. A constrained least squares method was used to invert synthetic gravity data for the subsurface density distribution. The modeling procedure has been formulated to allow testing for sensitivity to gravity sampling patterns, noise and various constraints on model parameters such as density, total mass, and moment of inertia.

These simulation results have shown that greater than 95% of the injected water can be accounted for in the inverse model. These estimates include reasonable assumptions concerning the noise level in the measurements of both the gravity data and the location data using the Global Positioning System (GPS). The average flood front can be reliably detected within 2000 - 3000 ft. for the Prudhoe Bay reservoir that is buried at 8200 ft to 8800 ft tvd. Time differenced surface gravity and GPS data were gathered over the Arctic Ocean in typical winter conditions (-40 F) accurately enough to monitor the waterflood (gravity = ± 10 ìGals and GPS = ± 1 cm elevation, a íGal is about one billionth of the Earth's normal gravity).
Waterflood and Production-Induced Stress Changes Dramatically Affect Hydraulic Fracture Behavior in Lost Hills Infill Wells
Authors: Minner W. A. , Wright C. A. , Stanley G. R. , de Pater C. J. , Gorham T. L. , Eckerfield L. D. , Hejl K. A.
Published: December 2007

Water injection and reservoir fluid production result in poroelastic stress changes that can dramatically alter the created fracture geometry on infill wells. This basic conclusion is not new. It has been documented in many different environments, and is supported by theoretical modeling. However, this paper presents for the first time a large data-set of 76 fracture treatments in a concentrated area that not only shows stress reorientation, but also shows how fracture reorientation depends critically on the pattern of injectors and producers and their interaction. This knowledge can be used to improve recovery in water injection projects that depend on closely spaced fractured wells.

Data is presented from 76 fracture stages in 16 infill wells completed within a one-year period in Chevron's Lost Hills diatomite waterflood. Surface tiltmeter fracture mapping determined the fracture orientation (azimuth and dip) of the induced fractures, consisting of a vertical fracture component and a secondary sub-horizontal fracture component. This dataset clearly shows that the interaction between injectors (located in a line along preferred fracture azimuth) and producers results in a large-scale stress perturbation, producing a "room-and-pillar" stress structure. Both the fracture azimuth and the degree of secondary sub-horizontal fracturing are controlled by the location of infill wells with respect to nearby injector wells. Infill wells "inline" with injector wells yield fractures that grow close to the initial preferred fracture orientation. In contrast, infill wells that are "offset" from the line of injector wells yield highly variable fracture azimuths (often rotating towards injector wells) and greatly increased secondary sub-horizontal fracturing – both of which raise the risk of "short-circuiting" waterflood sweep. The data is presented and phenomenologically explained. A geomechanical model explains the observed stress changes, allowing predictive modeling of various infill-drilling scenarios in waterfloods to optimize recovery.

For a number of project treatments, downhole tiltmeter fracture mapping was also used to evaluate fracture dimensions, and fracture pressure analysis was performed to link tilt observations with treatment pressure behavior. Poroelastic effects have resulted in increased stress magnitudes in some layers and decreased stress in others, impacting the created fracture dimensions (height, length, and width). A summary of the mapped fracture dimensions and pressure analysis findings is presented together with a brief discussion of the poroelastic impacts on fracture geometry.
Logistic Approach in Using an Array of Reservoir Simulation and Probabilistic Models in Developing a Giant Oil Reservoir with Super-Permeability and Natural Fractures
Authors: Pham T. R. , Al-Otaibi U. F. , Al-Ali Z. A. , Lawrence P. , Van Lingen P.
Published: December 2007

The development of a large oil increment with super-permeability (super-K) layers, and natural fractures such as Haradh Arab-D poses many challenges, including the optimization of the number of start-up oil producers and injectors, and the selection of depletion mechanism which is preferably peripheral injection in this case. The type of well (vertical or horizontal), and completion intervals have to be investigated. In the case of horizontal wells, direction of the horizontal trajectory is always a difficult issue to decide as well as the optimized length of the horizontal section.

Due to time constraints and the sheer size of the field areal extent (tens of kilometers) and the complex geology of the reservoir, it is not practical to construct a single full-field model which is expected to serve as an all-purpose simulation model that includes all of the reservoir attributes encompassing super-K layers, faults and fractures. This paper will discuss how to use an array of different reservoir simulation models to achieve the objectives within a time-limit dictated by the business plan requirements. Issues such as the number of start-up wells, the production plateau, type of wells, choice of completion intervals, optimized horizontal length, direction of horizontal trajectory can not be answered by one single model. However, each issue can be addressed by a specific model constructed for a single purpose. The development of an oil increment in Haradh is used to illustrate this concept.
Wax Deposition in North Sea Gas Condensate and Oil Systems: Comparison Between Operational Experience and Model Prediction
Authors: Labes-Carrier Catherine , Rønningsen Hans Petter , Kolnes Johnny , Leporcher Emile
Published: December 2007

Control of paraffin deposition is addressed in early phase of new field developments, as part of the fluid-related effects on the flow performance of the multiphase transportation system. Paraffins are precipitated by a decrease of the fluid temperature. During the design phase, a combination of experiments and modeling is used to predict potential wax related problems and determine possible solutions for wax control. High reliability is required from wax deposition models in order to avoid over protective operational guidelines, over design of the transportation system and thereby reduce cost in terms of insulation, pigging and chemical injection.

The main objective of this study is to compare wax deposition predicted by a simulation model to operational data for two different North Sea fields. The first case contemplates a 10-inch, approximately 21 km long multiphase and subsea production pipeline from the High Pressure gas condensate field A to the central gas-processing complex. The production has now come to an end. The second case is a single phase, stabilized oil being transported through a 16 inch, approximately 43 km production pipeline from a processing platform at field B to field C for storage and offloading.

OLGA 2000 with wax module has been used for the dynamic wax deposition simulations. The physical and thermodynamic fluid properties used in the simulations are also presented and discussed. Various model parameters and their influence on modeling results are evaluated.

Field experience after many years of production is available from the gas condensate field A. Although wax deposition was predicted in the gas condensate line, no significant deposit has ever been observed. Wax control for the field B pipeline is currently based on regular pigging every few days combined with continuous injection of wax inhibitor.

There has not been sufficient field data available for a very detailed comparison with modeling results. Anyway, operational experience from two very different fields gives some important insight into the strengths and weaknesses of current modeling tools and practice. A main conclusion of this paper is that wax deposition under field conditions seems to be less severe than predicted by the model for the multiphase gas condensate line, while it seems to be reasonable agreement between modeling and field experience for the single-phase oil case.
Phase Behavior Modeling of Hydrocarbon-Methanol-Water Mixtures by Peng-Robinson and SAFT Equations of State
Authors: Ayyalasomayajula Padmakar , Sharma Ravi , Walker Jacob G. , Sharma Mukul M. , Pope Gary A.
Published: December 2007

The phase behavior of mixtures of hydrocarbons, methanol and water is important in gas-condensate reservoirs as well as in gas hydrates. Gas-condensate wells frequently show reduced productivity when operated below the dew point due to the build up of condensate near the well. A combination of high water and condensate saturation results in a significant reduction in the gas relative permeability. Recently, methanol has been used to remove liquid blocking around such wells and restore well productivity. The phase behavior of such fluid mixtures is difficult to model using currently available equations of state.

In this study, phase behavior data were measured both to help interpret coreflood experiments and for testing of equation-of-state models used in compositional simulation studies of methanol well treatments. The Peng-Robinson equation-of-state and the SAFT equation-of-state were used to model this new phase behavior data. The Peng-Robinson equation-of-state does better than the SAFT equation-of-state for hydrocarbon mixtures. The binary interaction coefficients had to be adjusted in both models to match the experimental data when methanol and water are in the mixture. The SAFT EOS required less tuning to match data from hydrocarbon-methanol mixtures. SAFT EOS, as expected, agrees with the data better than the Peng-Robinson EOS when water is in the mixture.
A New Degree Program in Oil and Gas Engineering
Authors: Ronalds Beverley F.
Published: December 2007

The oil and gas industry is experiencing an ageing workforce and skills shortages, while petroleum engineering schools are struggling and many industry recruits are coming from other degree disciplines. This paper describes how these challenges are being addressed in a Western Australian (WA) context. The overall aim of the oil & gas engineering program at The University of Western Australia (UWA) is to give students an orientation to the extraction, processing and infrastructure requirements of the oil and gas industry. This is achieved by offering maximum flexibility in course offerings (entry level, duration and subject matter) and through maximum utilization of existing teaching resources. Strong industry interaction is another key feature of the program.
Analysis of Generated and Reflected Pressure Waves during Fracturing Reveals Fracture Behavior
Authors: Surjaatmadja Jim B. , Stephenson Stan , Bhaumik Champak , Thompson Stewart , Cheng Alick
Published: December 2007

Fracture behavior is an important aspect in fracturing technology. Many techniques are available for prestimulation simulations and post-stimulation analysis of fracture behavior. However, very few techniques address fracture behavior during the stimulation process itself. Various fracture behaviors, such as fracture extension, ballooning, and tip screenout are often not known to the operator until after it is too late or even after the job is completed. Therefore, it is important to create and evaluate different real-time analysis techniques that can be used to capture the critical information available from data gathered during jobs.

During the stimulation process, many types of information are available to the engineer. Pressure, flow, and temperature are basic information evaluated by many in the past. However, surface-pressure measurements are heavily influenced by friction, densities, proppant concentrations, and flow fluctuations, which makes conventional analyses difficult, if not impossible. In spite of this, analysis of dynamic pressure fluctuations has not been actively pursued. Certain changes in the downhole configuration, such as fracture extension, may send different pressure frequency spectra and wave intensities to the surface. The signature of these pressure waves is believed to carry such information to the surface. It is also believed that signal degradation due to friction may not influence the outcome of this type of analysis.

Capturing and evaluating generated and reflected pressure waves during fracturing may be a new approach to monitor what happens downhole during fracturing. This paper discusses different real-time analysis approaches, such as frequency analysis and wavelet technologies, and evaluates their results and compares them to real job data. These analysis results and the successful stimulation results are presented in this paper.
A Study of the Friction Pressure and Proppant Transport Behavior of Surfactant-Based Gels
Authors: McElfresh P. M. , Wood W. R. , Williams C. F. , Shah S. N. , Goel N. , Zhou Y.
Published: December 2007

Surfactant-based gels (SBGs) exhibiting viscoelastic properties have been introduced recently for sand control and stimulation applications. However, limited data are available on their friction pressure losses through tubing and proppant transport behavior. Therefore, an experimental investigation was performed to study the friction pressure and proppant transport behavior of SBG fracturing and sand control fluids. The friction pressure of the clean and slurry fluids were evaluated in tubing of various configurations and lengths up to 1000 ft. The proppant transport behavior of the fluids was observed through a transparent slot and a High Pressure Fracture simulator, and proppant settling in small-scale laboratory tests. The friction pressure results show that the SBGs exhibit stable and significant drag reduction under most of the flow conditions. The presence of sand in the solutions increases the friction losses through tubing, but to different amounts depending on tubing geometry and configuration. The proppant transport behavior of the SBGs was observed to be comparable to the behavior of the 35- and 40-lbm/Mgal crosslinked gels evaluated under similar slot flow conditions.

This study of SBGs provides unique results obtained in a large-scale test facility and in a small-scale laboratory environment. These experimental results, in turn, provide information to aid field personnel in designing gravel packs, frac packs, and other completion and stimulation treatments. These data also will aid in the eventual development of friction pressure and proppant transport prediction methods for SBGs.
Adaptive Fuzzy Clustering for Efficient Segmentation of Wellbore Resistivity Images
Authors: Finol Jose , Romero Carlos , Valbuena Johnny
Published: December 2007

Resistivity image segmentation allows mapping of similar regions in a scene leading to the recognition of distinct geological features such as rock fractures and thin beds. Recognition of similar patterns embedded in resistivity image data is the basis of clustering regions in an image. Therefore an efficient clustering technique is a natural choice for image segmentation. Efforts to develop algorithms for adaptive and less computationally complex classification of data have led to the implementation of neural network classifiers of both supervised and unsupervised learning. Such neural network architectures are ways to achieve autonomous processing of patterns but are not considered to incorporate intelligent decision processes offered by various techniques of fuzzy clustering. Integration of fuzzy membership values of objects into neural network processing generates more robust models for intelligent pattern recognition.

This paper presents and efficient object extraction method for resistivity image segmentation based on neuro-fuzzy clustering algorithms. The neuro-fuzzy approach retains the basic properties and architectures of neural networks and fuzzifies some other elements, enhancing the learning speed and generalization capabilities.
Expanding the Envelope of Coiled Tubing Collapse Ratings in High-Pressure/High-Temperature Wells
Authors: Luft H. B. , Wright R. , Bouroumeau-Fuseau P.
Published: December 2007

It has been recognized for some time that recommended practices for determining the collapse strength of coiled tubing (CT) predict conservative ratings (see API 5C7-1996). As well, the effects of plastic fatigue cycling and elevated temperatures on CT collapse resistance, are currently not being incorporated in any collapse prediction models. This paper summarizes all of the major findings of an extensive experimental and theoretical research program on collapse of coiled tubing conducted jointly between TotalFinaElf Exploration UK PLC and BJ Services Company. The research studied the effects of temperature and changes in tensile properties induced by low cycle bend fatigue, that are presently not considered with respect to coiled tubing collapse. Changes in CT geometry, wall thickness and collapse pressure were accurately measured as functions of plastic bending cycles and applied axial loading.

The results of this research showed that the effects of loading history on coiled tubing collapse strength can not be neglected. It also showed that the collapse ratings of coiled tubing can be significantly increased above those obtained by the method described in the current issue of API 5C7. A better understanding of the collapse failure mechanism enabled a new formulation to be derived for plastic collapse of CT having a D/t ratio less than 14. Several examples are presented to illustrate the application of the research results and to compare these with existing theoretical models currently in use for the prediction of CT collapse.
Influence of Bit-Rock Interaction on Stick-Slip Vibrations of PDC Bits
Authors: Richard T. , Detournay E. , Fear M. , Miller B. , Clayton R. , Matthews O.
Published: December 2007

This paper describes a new approach to understand the causes of stick-slip vibrations experienced by PDC bits. This new model takes into consideration not only the axial and torsional modes of vibration, but also the coupling between these two modes through bit-rock interaction laws, which are consistent with laboratory results from single cutter experiments. These interaction laws, which account for both frictional contact and cutting processes at the bit-rock interface, are formulated in terms of the depth of cut, a variable that brings into the equations the position of the bit at a previous a priori unknown time. They also account for potential loss of frictional contact between the wear-flats and the rock. The delayed and coupled nature of this interaction is ultimately responsible for the occurrence of self-excited vibrations, which can degenerate into stick-slip oscillations under certain conditions. The features of the torsional vibrations that are predicted with this model are well in accordance with field observations. Furthermore, the results reveal that the model predicts apparent rate effects as an inherent outcome of the nature of the bit-rock interface.
Use of Downhole Production/Reinjection for Zero-Emission Well Testing: Challenges and Rewards
Authors: Hollaender Florian , Filas Jim G. , Bennett Curtis O. , Gringarten Alain C.
Published: December 2007

In recent years, HSE concerns have been a driving force pushing towards emission-free well testing. Several methods have been proposed in order to attain that objective, the two most known being closed-chamber testing and downhole production/reinjection. With closed-chamber testing being of limited interest because of the reduced radius of investigation it offers, and harmonic testing being impractical due to time requirements, downhole production/reinjection appears as the only way of fully replacing conventional well testing.

Planning such a test requires greater care than for a conventional test because the selection of an adequate injection interval is of major importance to the success of such an operation. The injected fluids must be contained within the disposal zone so as to avoid surface leakage but also so that the test data are not affected by an interference effect due to the injection process. There is also a great concern regarding the quality of the data because of hard downhole conditions.

But if these challenges can be overcome, downhole production/reinjection can provide the same information as a conventional well test but with improved safety, no direct emission of pollutants and at reduced cost and test duration.
Subsea Well Testing at the Subsea Tree
Authors: Waldman Nathan , Fair Chris , Tyrrell Charlie , Kumar Rakesh
Published: December 2007

Operators are often presented with a dilemma when installing instrumentation in a subsea well. Do they install permanent downhole gauges? If so, is there a back-up plan in the eventuality that the downhole gauge fails. In the past, when a downhole gauge on a subsea well failed, the back-up plan has either been to "fly blind" or to rely on low-accuracy measurements from subsea tree gauges or pipeline gauges (which can also fail). While tree or pipeline gauges may be adequate to determine if the well is flowing, they are rarely of sufficient accuracy and resolution to optimize production from the well. The need for high resolution, accurate pressure data is greatest in high permeability wells and in unconsolidated sandstones, where the production of sand can be catastrophic.

In 2001, a solution to this problem was developed. It allows an operator to temporarily install a highly accurate pressure recording system on the well in order to perform diagnostic tests on the well bore, completion and/or reservoir. This option is available to any subsea tree equipped with an Industry Standard "Hotstab" port. Typically, subsea trees are fitted with at least one female hotstab port conforming to ISO/CD 13628-8 enabling a remotely operated vehicle (ROV) to connect instrumentation specifically designed for this application. The ROV is then used to operate the isolation valves to allow well bore communication via the hotstab port. Once pressure communication with the well bore is established, diagnostic tests may begin.

The purpose of this paper is to introduce a mobile high-precision, high-accuracy pressure recorder for pressure transient testing at subsea well heads. First, the instrument and subsea tree specifications will be discussed. Then, a detailed procedure for installing this instrument on the subsea tree will be presented. Next, the issue of wellhead to bottomhole pressure conversion will be addressed. Results from field tests with the system will be presented. This new tool makes it possible to test subsea wells in which downhole gauges were not installed or where they have ceased to operate. The tool has also proven useful for pressure integrity tests when commissioning sub sea pipelines.
Real-Time Petrophysical Analysis in Siliciclastics From the Integration of Spectroscopy and Triple-Combo Logging
Authors: Herron Michael M. , Herron Susan L. , Grau James A. , Seleznev Nikita V. , Phillips John , El Sheriff Ahmed , Farag Sherif , Horkowtiz John P. , Neville Thomas J. , Hsu Kai
Published: December 2007

There is a long history of wanting to provide a petrophysical answer, comprising at least porosity and saturation, either in real time or within, at most, a couple of hours after logging. Past attempts to provide such a product have been plagued by the need to define numerous parameters and well zonations that would ordinarily be selected by a skilled interpreter. With the introduction of elemental concentration logs obtained from nuclear capture spectroscopy tools, the number of interpretation parameters can be dramatically reduced. This is because the accuracy of the lithology and matrix properties is a significant advance over values determined from conventional techniques. Consequently, it is much easier to directly apply scientific conductivity and permeability models for petrophysical evaluation.
The Development Of Bottom Discharge Submersible Pumps
Authors: Al-Jeboury F.A.
Published: December 2007

Abu Dhabi Company for Onshore Oil Operations (ADCO) employs water injection for pressure maintenance in its three major oil-producing fields. An auto-dump injection scheme is used to naturally inject water from overlying aquifers into the reservoir due to the differential pressure. A paired water supply/injection well system is also used, by which the water is lifted to surface by Reda electric submersible pumps and injected by surface pumps driven by electric motors.

ADCO has tested a unique approach to boost the dump flood in the field. A bottom-discharge submersible pump has been designed to increase the water available from the aquifer for dump flooding, providing a combination of both dump and power injection.

The approach offers the advantage of reduced power requirements and eliminates the need for a water supply well and surface injection equipment. Also it utilises the natural dump when a pump fails.

A proto type M 675 (26-stage) bottom discharge submersible pump was ordered from Reda and was first tested in February 1975. This pump, powered by a 500 HP motor developed a pressure boost of 1000 psi and increased the natural dump of 5000 bw/d to a powered injection rate of 15,000 bw/d.

Selection of pump size with the appropriate number of stages showed that most well requirements could be met by J-600 or J-400 bottom discharge pumps which can be set inside 9.5/8 inch casing.

In order to carry out more tests a 55-stage J-600 submersible bottom discharge pump was installed in well Bu-114. Many changes in the design of the downhole equipment were carried out to simplify running and improve reliability and, although further improvements may be necessary, it is clear that the bottom-discharge concept of injection is a highly viable and economic proposition where surface water is not available or at a premium for other uses.

Introduction

Abu Dhabi Company for Onshore Oil Operations (ADCO) is currently injecting some 1,600,000 barrels of water per day for reservoir pressure maintenance in the three main producing fields. Powered injection is by means of a paired water supply/injection well system, with water lifted by 18 stage N-1050 Reda pump powered by a 500 HP motor (fig. 1). The water is injected into the reservoir using surface pumps up to a pressure of 2400 psi.

The typical installation of a Reda N-1050 submersible pump is shown in fig. 2. The pump has an operating range from 22,000–35,000 bw/d.

ADCO is expanding its water injection capability by equipping some existing dump injection wells with bottom-discharge submersible pumps. They offer the following advantages over the conventional "up and over" paired injection/water supply well configuration:–Very low capital investment, in respect of power generation, overhead transmission lines, surface pumping equipment and elimination of a separate water supply well.–A higher overall operating factor since many wells will continue to dump if a pump fails.
The First Successful Fracture Treatment Campaign Conducted in Japan: Stimulation Challenges in a Deep, NaturallyFractured Volcanic Rock
Authors: Weijers L. , Griffin L. G. , Sugiyama H. , Shimamoto T. , Takada S. , Chong K. K. , Terracina J. M. , Wright C. A.
Published: December 2007

In the summer of 2001, the first multi-stage completion in a deep, hot, and naturally fractured volcanic rock of the Minami-Nagaoka Field, Niigata Prefecture, Japan, was successfully completed using six propped fracture treatment stages.

While successful development of the northern part of the Minami-Nagaoka reservoir could significantly impact Japan's domestic natural gas production, successful proppant placement in this field has proved extremely difficult in the past1–2. During two propped fracture treatments pumped more than a decade ago, treatments failed miserably with only about 20% of the designed proppant placed before job termination due to premature screen-outs. These treatments exhibited net pressures up to 4,000 psi before pumping any proppant - the highest net pressure level that we have ever observed, indicating extremely complex fracture growth. Post-frac evaluation confirmed that proppant placement problems mainly occurred due to simultaneous propagation of very narrow multiple hydraulic fractures. Detailed pressure build- up and production test analysis confirmed the diagnosis of narrow multiple hydraulic fractures, which resulted in extremely poor (and vanishing) propped fracture conductivity and non-economic gas production.

The new treatments in Minami-Nagaoka focused on the ability to mitigate the adverse effects of multiple hydraulic fracture propagation and the accompanying severe near- wellbore fracture tortuosity. Major equipment mobilization was required for this treatment to be possible as part of this concerted effort. Many unconventional changes, including completion changes to obtain highest possible injection rates to enhance proppant placement, aggressive proppant slug strategy, real-time fracture treatment analysis, gel testing for minimization of proppant damage, careful perforation placement, quality control, extreme overbalance perforating, and use of small-grained proppant, resulted in successful stimulation and favorable production response. This paper discusses all these design changes in detail, and provides final results regarding the fracture geometries obtained.
Quantification of Displacement Mechanisms in Multicomponent Gasfloods
Authors: Johns R. T. , Yuan H. , Dindoruk B.
Published: December 2007

Local displacement efficiency in gas floods depends strongly on the minimum miscibility pressure (MMP) or minimum miscibility enrichment (MME). The values for these design parameters depend in turn on the displacement mechanisms, vaporizing, condensing, or a combination of the two known as a condensing/vaporizing (CV) drive. Characterization of the displacement mechanism, however, is currently limited to these broad categories with little reference to the degree to which a CV displacement is condensing or vaporizing. The focus of this paper, therefore, is to present a method to quantify the fraction of a multicomponent gas flood that is vaporizing or condensing as the pressure or gas enrichment is increased.

The approach relies on finding key tie lines for a dispersion-free one-dimensional displacement using method of characteristic theory (MOC). We quantify the displacement mechanism for any number of oil or gas components by calculating the displacement path lengths along ruled surfaces bounded by these key tie lines. Several multicomponent fluid characterizations are considered, including a twelve-component enriched-gas flood and a thirteen-component CO2 flood. The results show that as the pressure or enrichment is increased condensation occurs at the expense of vaporization. We also show by numerical simulations that the sensitivity of the local displacement efficiency to dispersion depends on the condensing fraction of the displacement.
A Critical Overview of Artificial Neural Network Applications in the Context of Continuous Oil Field Optimization
Authors: Saputelli L. , Malki H. , Canelon J. , Nikolaou M.
Published: December 2007

A number of new technologies introduced into the oil field over the last couple of decades now provide the hardware basis for continuous field-wide optimization (CFO). CFO will require computer integration of field hardware (e.g., downhole sensors, remotely activated completions, surface facilities) for continuous decision-making in a feedback fashion (data acquisition, data processing, actuation). We introduce a hierarchy of oil field operations that identifies various levels of detail and time-scales for decision-making processes. We propose to use this hierarchy in a multi-level / multi-scale approach to CFO. An important element in that approach is the availability of predictive models that can be used at various levels of the hierarchy, so that optimal actions can be continuously selected through optimization over a moving horizon.. In this context, artificial neural networks (ANN) are a tool that has been used to build data-driven models. This paper is structured in two parts: (1) elements of CFO, and (2) brief review of ANN basics, known ANN applications in the petroleum industry, and a critical view of ANN capabilities.
Maximizing Production for Horizontal Wells in Hassi R'mel Field (Algeria) with Resistivity Interpretation and Modeling
Authors: Kloos Jannes , Munkholm Mette , Benallegue Fatiha , Bencherif Djaouid , Rabinovich Michael , Tabarovsky Lev
Published: December 2007

Water flooding and gas coning are potential problems in the horizontal wells drilled to penetrate the oil column in the channel sands of the Hassi R'Mel field. This field is operated by Sonatrach, the Algerian National Oil Company. High Definition Induction Logging (HDIL) in such environments has been used to build a reliable geological model along the wellbore, identify potential problem intervals, and minimize the risk of perforating and producing gas and/or water.

The new generation of induction tools – array induction tools – has an advantage of acquiring unfocused data that can be numerically focused to any part of the formation at the post-acquisition stage. Operating at low frequencies with relatively large transmitter-receiver spacings, the wireline array induction measurements can provide reliable information from geological targets up to a 6-m (20 ft) distance from the borehole, depending on resitivity contrasts.

In horizontal wells, the induction data may be influenced by adjacent layers located above or below the reservoir. In such cases, when evaluating the water saturation in the near wellbore region, we must, firstly, correct for the influence of the remote layers. Secondly, after correcting the deep HDIL measurements for the presence of the borehole and invasion, we use them to determine both the distance to and the resistivity of remote beds.

To integrate the HDIL results into the geological model, a number of issues must be considered. First of all, in the Hassi R'Mel field remote conductive shoulder beds may be either conductive shales or water-bearing horizons. Therefore, to distinguish between the two, their resistivities must differ and, in the interpretation stage, be compared with that of the remote shoulder bed interpretation. In addition, as the measurements do not have a sense of direction, they cannot distinguish between remote beds above or below. Interpretation of the location of an identified remote layer must therefore be based on the geological model for the field as well as other log data. Finally, although an interface between two resistive layers is more difficult to resolve, remote oil-gas contacts may in some cases be found from the interpretation.

Presently, every logging job in Hassi R'mel includes an HDIL tool in a string, and the data are usually processed within 48 hours. Providing the geological model and perforating recommendations prior to well completion improves the economics of the well due to increase in oil production and the reduced cost of well recompletion.
Resistivity in Carbonates: New Insights
Authors: Fleury Marc
Published: December 2007

A detailed explanation of the non-Archie behavior of the resistivity index vs Sw curves in carbonates is proposed. The model is based on resistivity index (RI) curves measured at ambient and reservoir conditions, on double or triple porosity micritic and oolitic carbonates. We used the Fast Resistivity Index Measurement (FRIM) method to obtain accurate and continuous RI curves down to very low water saturation (5%). In general, the measured RI curves cannot be described by an Archie's law and the measurements at very low saturation are often a key observation to confirm a non-Archie behavior. A large variety of shapes is observed and the local saturation exponents can vary from 1 up to 3.

These shapes can be explained qualitatively and quantitatively using two new models (DPC and TPC) in which the different porosity systems are connected together either in series or in parallel, or a combination of both. The second key feature of the models is the use of NMR and mercury injection curves to estimate the pore volume fraction of each population and the sequence of invasion of each population by oil during the primary drainage process. Hence, only two of three adjustable parameters are needed to model the experimental results. In particular, the saturation exponent of the dominant pore system can be extracted from the analysis. For field applications, we also propose a simple procedure to calibrate resistivity logs with variable saturation exponent.

From the experimental results and the model, we conclude that the pore structure plays a key role. In particular, the microporosity can be responsible for the low resistivity contrast in carbonates, although it may represent less than 10% of the total pore volume. The water contained in the microporosity forms a continuous path for the current. When invaded by oil, the conductivity of the microporosity system is weakly modified.
A Novel Approach for Incorporating Physical Dispersion in Miscible Displacement
Authors: Shrivastava Vijay K. , Nghiem Long X. , Moore R. Gordon
Published: December 2007

Physical dispersion is one of the main mechanisms responsible for controlling the gas-oil mixing that occurs in a miscible flood process. Many conventional reservoir simulators do not explicitly account for the physical dispersion and presume that it may be compensated by numerical dispersion arising out of the finite difference scheme with single point upstream weighting of mobilities for the reservoir grid block sizes used in field-scale simulations. This assumption may lead to erroneous results.

The multi-point flux approximation (MPFA) schemes developed in recent years provide improved treatment of the convective flux and allow the handling of tensorial permeabilities for non-uniform and skewed grids. These grids are often required for proper representation of the reservoir geometry. The physical dispersion coefficient in the dispersive flux is tensorial in nature and amenable to a treatment similar to the permeability in the convective flux. We have applied a multipoint control-volume method together with a total variation diminishing (TVD) scheme to calculating the dispersive flux in a compositional simulator. The TVD scheme was used to minimize the effect of front smearing caused by numerical dispersion.

This paper presents a method for calculating the full physical dispersion tensor in a compositional simulator using corner-point grids. The proposed formulation accurately handles dispersive flux for non-orthogonal grids, and along with the TVD scheme provides a means for distinguishing physical dispersion from numerical dispersion.

A number of cases are presented to show the improvements in simulation results that could be obtained with the proposed method.
Use Of The Noise Log As A Downhole Diagnostic Tool
Authors: Koerner H.B. , Carroll J.C.
Published: December 2007

Introduction

Flow of aquifer water into a dry oil production stream, contamination of fresh water aquifers production stream, contamination of fresh water aquifers due to casing leaks or crossflow behind pipe, and loss of oil, natural gas, or injection fluids due to downhole equipment failures are examples of everyday problems in a large oil producing operation. These problems must be detected, confirmed, diagnosed and solved - quickly and economically. Collection of useful downhole information is the key to meeting this requirement.

Conventional logging techniques such as temperature, flow-meter and radio-active tracer (RAT) are used effectively for detecting undesirable fluid flow in a wellbore. However, in ARAMCO operations, situations are frequently encountered where these techniques are partially or totally inadequate, for example:Oil producer waters out. Temperature profile is normal. Tubing is set to TD. Source of water is questionable.Producer with tubing run to TD develops pressure on a casing - casing annulus. Temperature profile shows no anomalies.Supply wells producing 120 MB/D of 170 deg. Saline aquifer water by electrically driven submersible pumps hung at 500 ft on a watercolumn must be monitored routinely to prevent contamination of fresh water aquifers.Power water injection well develops awell-bore obstruction. The obstruction is opposite the top of a large aquifer whose temperature is the same as that of the water being injected.

In all these cases the flow stream is in accessible, which rules out the use of a flowmeter or RAT. The temperature log is ineffective because either the flow rate is too small to effect a gradient change or the temperature of the flowing fluid is indistinguishable from the wellbore temperature. Since 1976, however, ARAMCO has been using a noise logging technique to successfully evaluate problems similar to these.

NOISE LOGGING

The diagnostic value of downhole noise was recognized as early as 1955. It was not until 1972, however, that the results of an extensive laboratory investigation the nature of downhole noises were reported. Using these results two important conclusions were drawn:That order of magnitude flow rates can be estimated using peak noise; andThat certain flow situations can be distinguished from others if the frequency structure of the noise can be obtained.

The development of a downhole noise logging technique ins undertaken based on these conclusions. The groundwork has been laid for quantitative interpretation of downhole noise, but, to date, most interpretations are still qualitative.

ELEMENTS OF THE TECHNIQUE

Peak Noise Peak Noise Our observations indicate that absolute noise amplitude is the key to qualitative noise log interpretation, since noise peaks are usually detected opposite a noise source, and the energy levels of these peaks indicate the severity of the problem.
Phase Envelope Calculations for Hydrocarbon-Water Mixtures
Authors: Lindeloff Niels , Michelsen Michael L.
Published: December 2007

The present work describes how the pressure-temperature phase diagrams for hydrocarbon-water mixtures can be calculated. This requires a thermodynamic model that can account for the polar interactions caused by the aqueous compounds and an algorithm that can trace the two- and three-phase boundaries encountered is such systems. Models and algorithms that can handle this task are described. The paper further describes a number of examples where the methods are applied.
Primary and Secondary Porosity Estimation of Carbonate Formations Using Total Porosity and the Formation Factor
Authors: Kazatchenko Elena , Mousatov Aleksandr
Published: December 2007

A technique for the primary and secondary porosity estimation is proposed. This technique is based on a resistivity model of carbonate formations with double porosity and the analysis of numerous core data. The resistivity model consists of an isotropic conductive matrix with a primary porous system and inclusions, which represent secondary porosity (vugs and fractures). Fracture systems are described by oblate ellipsoids of different sizes (which have the same orientation and aspect ratio) or by thin plates. These rock structures are characterized by an anisotropy of electrical properties. The components of the resistivity tensor have a nonlinear relationship with the matrix porosity and parameters of fracture systems (orientation and porosity). The model with spherical inclusions (Maxwell-Garnett approach) is applied to obtain the resistivity of vugular formations. The fluid type, saturation of matrix and secondary pores influence significantly the formation resistivity and anisotropy coefficient. When both pore systems are completely saturated by the same conductive fluid (the case of core analysis), the effective formation factor depends only on the matrix formation factor and the secondary porosity value. The statistical analysis of core data has shown that Archie's equation with cementation exponent m=2, is the best approximation to describe the matrix formation factor for carbonate formations in Mexico. For verification of the porosity separation technique, the fracture and vuggy porosities have been estimated for core with detailed description of pore structure.
Scale Prevention, a Magentic Treatment Approach
Authors: Farshad Fred F. , Vargas Silvia M.
Published: December 2007

Sixty experiments have been conducted to study the effects of magnetic fields on calcium sulfate scale (also known as gypsum scale). For this purpose, three magnetic systems were designed using NdFeB (Neodymium Iron Boron) magnets of different geometry arranged in open and closed magnetic circuits. The statistical analysis of the data obtained indicates the potential effectiveness of this technology to prevent and treat scale formation problems.