bluuebunny/crossref_metadata_2025 huggingface dataset:
Inflow Predictions and Testing While Underbalanced Drilling
Authors: Larsen Leif , Nilsen Finn
Published: December 2007

With increased interest in underbalanced drilling, including coiled tubing drilling, the importance of realistic inflow predictions and the potential for formation evaluation based on rate measurements is also receiving increased attention. This paper addresses these points by introducing new models for inflow predictions at various levels of complexity and accuracy for spreadsheet and calculator applications. The methods can handle both homogeneous and layered reservoirs, and essentially traps the expected formation response within a narrow range based on drilling speed and the ratio of vertical to horizontal permeability.
Evaluation of Depressurisation, Miller Field, North Sea
Authors: Beecroft W. J. , Mani V. , Wood A. R. O. , Rusinek I.
Published: December 2007

This paper describes analysis of a potential depressurisation project for the Miller field, North Sea. Depressurisation is an option to enhance the late life reserves of the field. One challenge of the Miller depressurisation project is to mobilize the gas resources in an undersaturated oil reservoir.

Laboratory and simulation work were used to assess the possible benefits of depressurisation at Miller. Published work from the Brent depressurisation project provided a starting point to assess the potential risks of a project at Miller. Uncertainty analysis was performed to quantify the economic impact of each risk in the Miller project. The analysis was very flexible and provided a rapid assessment of the issues which had most economic impact. This approach minimized the number of reservoir simulations typically required to conduct an uncertainty study.

Mobilization of gas at Miller is found to have a significant impact on production profiles and project economics. A well test to measure critical gas saturation in the field is proposed. Strategies to mitigate the impacts of unfavorable critical gas saturation are discussed.
Using Artificial Intelligence to Corellate Multiple Seismic Attributes to Reservoir Properties
Authors: Balch R. S. , Stubbs B. S. , Weiss W. W. , Wo S.
Published: December 2007

Well data gives precise information on reservoir properties at specific field locations with high vertical resolution. 3D seismic surveys cover large areas of the field but reservoir properties are not directly observable due to poor vertical resolution. For this paper, a new methodology has been developed and tested for relating reservoir properties at the well-bore to sets of seismic attributes, in order to predict reservoir properties in two zones of the Nash Draw field in SE New Mexico. Over 350 seismic attributes can be used in regression analyses of reservoir properties. Since using all attributes is computationally unfeasible and labor intensive, fuzzy logic is used to select the most statistically significant attributes for developing regression equations for individual reservoir properties. Non-linear regressions were used, as individual attributes had low correlation coefficients when cross-plotted with reservoir properties, and neural network architectures were developed to relate the selected attributes to each property. In each case the output data used for training was a reservoir property, porosity (ϕ), water saturation(Sw), or net pay, from 19 wells in the field. Each property was estimated using a neural network trained to CC=0.8 or higher using the highest ranking seismic attributes as inputs. The validity of the solutions were tested by removing three wells from the training data, re-computing the weights, and predicting the three absent points. These tests were applied three times for each reservoir property, with different points removed. Each network accurately predicted these nine test points and the solutions are considered robust. ϕ, Sw, and net pay maps were generated using the regression relationships and the seismic attributes at each seismic bin location. Pore volume (ϕh) and hydrocarbon pore volume (hϕSo) maps were derived from those reservoir property maps. These new techniques maximize both the well control and seismic data and generated useful maps for targeted drilling programs in the field.
First Four Water Shut-Off Treatments in ONWJ Field: Design, Execution, Evaluation, and Strategy for the Next Treatments
Authors: Wibowo Wahju , Gould John H. , Munir Antares , Rich David A.
Published: December 2007

Water shut-off treatments have become an acceptable part of well service activities in the past few years for the purpose of controlling and/or decreasing water production and increasing oil production in watered out wells.(1–4) The results of applying polymer water shut-off treatments to several wells producing from a naturally fractured and vuggy limestone reservoir, the Batu Raja Formation, are presented in this paper. The field is located in the Offshore North West Java Field (ONWJ) in Indonesia. The production results show that the water shut-off treatments have proven to be an efficient, low cost method for enhancing oil production in wells which have severe water production problems.

The problem wells in this study were completed in the Batu Raja Formation, which has an underlying active aquifer. The limestone formation is characterized by fractures and vugs, and is connected to the surrounding reservoir through a complex system of fractures and channels. Since the vertical channels and fissures are the dominant feature of the reservoir behavior, and because very high permeabilities of up to 20 Darcies have been observed in some well tests, severe water production is the most common problem in this reservoir. Generally, the water cut increases from 0 to 70% within the first six months of production. Initial production rates are around 1500 BOPD and wells are finally shut in due to excessive water production.

The polymer water shut-off treatments were performed on the wells with varying degrees of success. Water cuts decreased by 10–20% and the oil production rates increased from 0 to 175 BOPD. Overall, the water shut-off treatments were successfully performed in the ONWJ Field and the expenses of the treatments paid out within two months. This successful result demonstrates the viability of the treatments as an efficient low cost enhanced oil recovery project.

This paper also discusses injectivity analysis of the polymer solution using a modified Hall plot method. Detailed successful field results will be presented for each treatment. Also presented are a discussion of how to apply the treatments and recommendations for future work.
Porous Media Flow of Oil Dispersions in Polymers
Authors: Darwish Mohamed I. M. , van Boven Pim , Hensens Hans C. , Zitha P. L. J.
Published: December 2007

Polymer and polymer gels are well suited for reducing water production during oil and gas production, but there exist a risk that they reduce oil flow appreciably, together with water. The risk is smaller when water is reduced by disproportionate permeability reduction (DPR), but may be sufficient to instill caution about using the chemicals. This explains largely the frequent use of mechanical means to isolate oil layers and ensure that polymer enters only in the water layers where it is needed.

The use of mechanical isolation or, alternatively, dual fluid injection, is impracticable in most wells. This is particularly true for deviated, horizontal, and multilateral wells, which are being increasingly used in different parts of the world. In those wells there is a need of polymers and gel treatments that can be injected without the mechanical isolation of the oil layers (i.e., treatments that can be bullheaded).

This paper concerns the use of oil dispersion in polymers (ODP) to achieve low penetration of polymer in oil layers and, thereby, to ensure the diversion of polymers towards water layers, during bullheading treatments. Core flow experiments were conducted using sandstone cores saturated either with brine or oil. Thus far the following observations have been made.

The mobility reduction for the flow of oil dispersion in polymers (ODP) is stronger in oil saturated cores than in the water saturated ones. On the contrary, the permeability reduction is smaller for the oil saturated cores. This effect can be interpreted by a stronger viscous dissipation occurring during ODP flow in the presence of oil. The viscous dissipation arises primarily from droplet trapping and polymer adsorption.

The results show that the presence of oil droplets in the polymer solution may reduce the penetration of the polymer in the oil layers, and divert it from oil to water layers.
An Approximate Model for the Productivity of Non-Conventional Wells in Heterogeneous Reservoirs
Authors: Wolfsteiner Christian , Durlofsky Louis J. , Aziz Khalid
Published: December 2007

A semi-analytical method is presented for the approximate modeling of the productivity of non-conventional wells in heterogeneous reservoirs. The approach is based on Green's functions and represents an extension of a previous model applicable for homogeneous systems. The new method, referred to as the s-k* approach, models permeability heterogeneity in terms of an effective skin that varies along the well trajectory and a constant background permeability k*. The skin is computed through local, weighted integrations of the permeability in the near-well region and is then incorporated into the semi-analytical solution method. The overall method, which can also model effects due to wellbore hydraulics, is quite efficient in comparison to detailed finite difference calculations.

Results for the performance of non-conventional wells in three dimensional heterogeneous reservoirs are computed using the s-k* approach and compared to finite difference calculations resolved on the geostatistical fine grid. The new method is shown to provide an accurate estimate of wellbore pressure and production rate, as a function of position along the wellbore, for various well configurations and heterogeneous permeability fields. The possible use of the overall approach in a simulation while drilling (SWD) tool, in which the well path and trajectory are "optimized" using real-time data, is also discussed.
Sonic-Magnetic Resonance Method: A Sourceless Porosity Evaluation in Gas-Bearing Reservoirs
Authors: Minh Chanh Cao , Gubelin Greg , Ramamoorthy Raghu , McGeoch Stuart
Published: December 2007

For environmental reasons, there are times when the use of radioactive chemical sources for density and neutron logging is not possible. The inability to use these logging tools seriously affects porosity determination in gas-bearing reservoirs. Several tools, such as the nuclear magnetic resonance (NMR) tool, the sonic tool or a minitron-based tool, determine porosity without using a radioactive source. These tools, however, are influenced by many effects and, when used alone, cannot deliver an accurate gas-independent porosity.

A new methodology that combines sonic and NMR logs for improved porosity evaluation in gas-bearing reservoirs is proposed. The first variant of the method uses the sonic compressional transit time and the total NMR porosity (TCMR) to determine the total porosity, corrected for the gas effect, and the flushed zone gas saturation. In this approach, a linear time-averaged equation corrected for compaction is applied to the sonic compressional log. The simplicity of the solution (much like the previously published DMR1 Density-Magnetic Resonance Interpretation Method) allows fast, easy computation and a complete error analysis to assess the quality of the results.

In the second variant of the method, we show that the rigorous Gassman equation has a very similar response to the Raymer-Hunt-Gardner (RHG) equation for a water-gas mixture. This allows substitution of the complex Gassman equation by the much simpler RHG equation in the combined sonic-NMR (SMR) technique to estimate total porosity and flushed zone gas saturation in gas-bearing formations.

The technique is successfully applied to an offshore gas well in Australia. In this well, the porosity in the well-compacted sands is in the 20–25 p.u. range and the compaction factor is around 0.77. The sonic-magnetic resonance results compared favorably to the established density-magnetic resonance results and also to core data. In another offshore gas well from the North Sea, the porosity in the highly uncompacted sands is in the 35–40 p.u. range and the compaction factor is around 1.85. The SMR technique was able to produce a very good porosity estimate comparable to that estimated from the density-neutron logs.
Limited-Entry Frac Applications on Long Intervals of Highly Deviated or Horizontal Wells
Authors: McDaniel B. W. , Willett R. M. , Underwood P. J.
Published: December 2007

Long horizontal sections have been used increasingly in moderate-to low-permeability reservoirs. In these reservoirs, a successful program for applying fracture-stimulation treatments is a key component for commercial success. Historically, such wells have been stimulated with several separate fracture treatments, requiring expensive well operations between fracture stages. Successful zonal isolation for each fracture stage has been a primary reason for the success of this technique. This paper reports recent efforts by several operators to reduce completion costs by extending the application of limited-entry fracturing techniques to very long sections of highly deviated or horizontal wellbores, while ensuring effective fracture stimulation of each perforated section.

Many special innovations have been introduced recently for enhancing the applicability of limited-entry fracturing in long, openhole completions and in some uncemented liner applications. Some of these methods have been published; other unpublished methods are presented in this paper.

Case histories are presented for both sandstone and carbonate reservoir completions. Considerations that guided the wellbore azimuth, casing programs, perforating schemes, and fracturing program variables are presented. Known problems and unpredicted formation responses are also discussed.
Magnetic Resonance Relaxation-Tomography to Assess Fractures Induced in Vugular Carbonate Cores
Authors: Borgia G. C. , Bortolotti V. , Fantazzini P.
Published: December 2007

A method is presented to study fractures induced in full-size carbonate cores by means of Relaxation-Tomography (RT). This method combines nuclear magnetic resonance (NMR) relaxation and imaging techniques, and consists of obtaining, in addition to the usual 1H nuclei density (porosity) maps, images as relaxation time maps. By combining voxel-by-voxel signal intensity from the porosity map and relaxation time from the relaxation time map, one get the distribution of the signal intensity as a function of the relaxation time for selected internal regions of interest (ROI). The distribution of the signal intensity vs relaxation time gives information on the distribution of water in different structures inside the sample and therefore on the structure itself. One can compute the fraction of water in the ROI, relative to the total amount of water in the ROI, having relaxation time in a selected range. Also, average relaxation times, as the geometric mean, can be computed. In a previous paper (SPE 49294), we applied the method to quantify (following an operational NMR definition) matrix and vugular porosity in carbonate cores. In this paper we improve the computation of the relaxation time by introducing non-linear fitting of the data and extending the application to the study of fractures induced in carbonates. Several internal images from undisturbed vugular and microporous full-size carbonate cores saturated with water were obtained as porosity and longitudinal relaxation time (T1) maps. The T1 histograms from selected ROI's were obtained. Then, fractures were induced in the cores by repeated cycles of freezing and heating. The RT investigation was repeated on the treated cores after each step and the distributions of the relaxation times compared. The changes in the distributions suggest a twofold effect: the forming of new microfractures (increase of local surface-to-volume-ratio) and the expansion of pre-existing fractures (decrease of surface-to-volume ratio).
Determining Petrophysical Properties of Low Resistivity Reservoirs Using Nuclear Magnetic Resonance Logs
Authors: Hamada G. M. , Al-Blehed M. S. , Al-Awad M. N. J.
Published: December 2007

The combination of conventional logs such as density, neutron and resistivity logs is proven to be very effective in the evaluation of normal reservoirs. An accurate determination of the petrophysical parameters with the conventional logs for low resistivity reservoirs is very difficult. This paper presents the two cases of low resistivity reservoirs and low contrast resistivity reservoirs. The problem of these reservoirs is that conventional logging interpretation shows water zones, but water free hydrocarbon would be produced. In the case of low resistivity contrast reservoirs it is very hard to determine water hydrocarbon contact with resistivity logs.

Nuclear magnetic resonance (NMR) has been only available as a supplement tool, to provide additional information on the producibility of the reservoir. The main limitation of NMR, however, has been the cost and time of acquiring data. This paper shows that in the case of low resistivity reservoirs NMR is very cost-effective tool and helps to accurately determine the reservoir rock petrophysical properties. In the analysis of NMR data, several aspects of NMR technique have been used; 1) T1/T2 ratio for fluid identification, 2) the difference between NMR derived porosity and total porosity to determine the types of clay minerals, 3) NMR relaxation properties to identify fluids nature and rock properties

This paper presents four examples of low resistivity reservoirs. Analysis of NMR data of low resistivity reservoirs has helped to identify the producibility of these zones, to determine lithology independent porosity and to distinguish between bound and free water. For the case of low contrast resistivity reservoir where there was little resistivity contrast between water bearing formation and oil bearing formation, NMR has been able to identify the fluid nature of the two formations and then accurately the height of the oil column. This was based mainly on high contrast of NMR relaxation parameters.
A New Method to Interpret Two-Phase Profiles From Temperature and Flowmeter Logs
Authors: Li H. , Zhu D. , Lake L. W. , Hill A. D.
Published: December 2007

The conventional method to measure two-phase flow rates downhole combines flowmeter and holdup measurements. This method requires assumptions about slip velocity to interpret the flow profile for both phases. Uncertainty about the slip velocity and errors in both holdup and velocity measurements often reduce the reliability of the method. As a consequence, there has been substantial effort concentrated on developing new tools for two-phase flow well measurements.

This paper presents a new way to use conventional tools, a temperature and a flowmeter log, to determine the flow rate of each phase for wells producing oil and water. The method is based on a simultaneous solution of mass and energy balances, which provides independent sets of information, if the oil/water heat capacities are different, to infer the flow rates of both phases with depth. The new method does not depend on slip velocity assumptions. This paper presents the mathematical model of the new method, and discusses the feasibility and reliability of the method. We illustrate the method with both synthetic and field cases with satisfactory results.
The Relation of Pore Size to NMR T2 Diffusional Relaxation in Porous Media
Authors: Xu Xinwei , Davis Lorne A.
Published: December 2007

A thorough understanding of the NMR relaxation mechanisms of fluids in rocks is of central importance to modern NMR log interpretation. The T1 and T2 bulk fluid response and surface relaxivity are currently better characterized than is the T2 diffusional relaxation. This latter T2 relaxation mechanism is a phasing incoherency which develops as the molecules that bear the proton spins diffuse across strong internal field gradients generated by the susceptibility contrast between rock and pore fluid when a sample is placed in a magnetic field. The CPMG T2 measurement pulse sequence is unable to refocus the spins effectively when they are subject to such a time-varying internal field, and the observable signal decays.

To characterize this diffusional loss mechanism, the proton T2 relaxation rate at 2 MHz in synthetic mono-disperse porous media was studied as a function of pore size, pore fluid and CPMG inter-pulse spacing τ. The results are compared to higher field data (85 MHz) and to relaxations in Berea sandstone and Bedford limestone. In addition, the effects of a static applied gradient G were investigated.

Over the entire range of τ, the T2 diffusional relaxation rate had a well-defined inverse dependence on pore radius. As expected, mono-disperse samples were adequately characterized by a single exponential decay. For small values of the refocusing time τ (the CPMG inter-pulse spacing), the T2 diffusional relaxation rate was proportional to τ. For large τ, this relaxation was independent of τ. The relationship of the effects of τ and G on T2 relaxation are developed to quantitatively explain how the CPMG T2 measurements in static field gradients of logging tools differ from the results done with lab spectrometers without gradients.
Enhanced Wellsite Technique for Oil Detection and Characterization
Authors: Delaune P. L. , Spilker K. K. , Hanson S. A. , Wright A. C. , Quagliaroli R.
Published: December 2007

Fluorescence has been used as a means of detecting oil while drilling since first introduced in the 1930s. The visual technique is recognized to be subjective, making it unreliable for consistent detection of oil in formation samples. The Quantitative Fluorescence Technique (QFT™) introduced in the early 1990s uses a portable fluorometer to measure the fluorescence of crude oil extracted from a formation sample. The intensity of the fluorescence is proportional to the amount of oil in the sample. QFT™ was a substantial improvement over the visual technique for detection of oil in drill cuttings or cores, but still provided only a relative measure of oil in the sample.

An enhanced technique called QFT2™ has been developed that provides improved estimates of oil quantity and character from measurements made on drill cuttings or core samples. QFT2™ involves a two-point fluorescence measurement that yields estimates of both quantity (Weight % Oil) and oil type (API gravity). While these estimates are not a substitute for laboratory analysis, the speed, accuracy and ease of application make QFT2™ a practical tool for the determination of oil concentration and API gravity at the well site. QFT2™ can be used effectively on fresh drill cuttings or cores, or older samples from wells previously drilled. Results can be combined with wire-line hydrocarbon porosity data to estimate volume percent oil in the formation, and resultant data can be further evaluated to estimate oil mobility.

QFT2™ was developed by Texaco and finalized in a joint development project with ENI-Agip Division. The project evaluated a world-wide suite of oils to determine relationships between surface measurements and in-situ conditions.
Optimal Locations and Performance Prediction of Horizontal Oil Wells in the Oil Rim at Mahogany Field, Offshore Trinidad
Authors: Ali-Nandalal J. , Staines M. , Bally Y. K. , Finneran J. M.
Published: December 2007

The 21 Sand reservoir in the Mahogany field has a 63-75 ft oil leg overlain by a gas cap and underlain by water. In order to utilize reservoir energy and efficiently develop the field, the oil reserves must be recovered prior to producing the gas which is dedicated to the Atlantic Liquified Natural Gas plant in Trinidad. A horizontal well program was planned to develop the oil leg. An in-house reservoir simulator was used to predict performance of the oil wells.

The 21 Sand is 400' thick and has been segregated into 7 stratigraphic intervals. One hundred and twenty feet (120 ft) of core was acquired through these intervals and the petrophysical properties were measured on representative plug samples. This data was then correlated to well log data. Porosity-permeability flow units were then derived for optimum well placement. Modified-Lorenz plots (Ref. 1) were used to identify the units that would contribute to the flow and those that would act as baffles. Three dimensional visualisation models were then used to place the horizontal wells in high quality reservoir rock. Additionally, placement of the development wells for the deep gas reservoirs was designed to provide vital structural and stratigraphic information for potential heel and toe points for horizontal drilling.

This paper describes how all this work was compiled into a simulation model which has successfully predicted the current well producing rates and pressure draw down.
Object-Based Modeling of Fluvial / Deepwater Reservoirs with Fast Data Conditioning: Methodology and Case Studies
Authors: Shmaryan L. E. , Deutsch C. V.
Published: December 2007

This paper presents a new method for fast fluvial and deepwater stochastic simulation. Sinusoidal channels and attached levees and crevasse splays are generated to honor global net-to-gross ratios, vertical and areal proportions and well data.

Fast conditioning to well data is achieved without resorting to time-consuming iterative procedures such as simulated annealing. The undulating channel centerline is created by 1-D conditional sequential Gaussian simulation. Direct conditioning is also used for the reproduction of 2-D areal proportions.

The method has been applied to a fluvial reservoir in the North Sea with 16 wells and to a braided channel reservoir with 110 wells in Mexico. The dependence of CPU time to a number of different factors was explored. The CPU time for the proposed method and annealing based algorithm are compared. The method with direct well conditioning is an order of magnitude faster than annealing based method.
New Insights into Proppant-Pack Damage Due to Infiltration of Formation Fines
Authors: Blauch Matt , Weaver Jim , Parker Mark , Todd Brad , Glover Mark
Published: December 2007

Many wells completed in soft, poorly consolidated formations tend to underperform because of drilling and completion prac-tices in which formation-incompatible fluids are lost to the formation, resulting in significant near-well permeability loss. Advances in soft-rock stimulation technology have made frac-packing the preferred method for bypassing this formation damage. Choosing a suitable proppant for frac-packing soft formations is often paramount to overall stimulation success because many soft formations produce fines that can plug screens or packs.

Numerous studies describe the optimization of proppant size as a way to minimize fines invasion into the proppant pack and maximize conductivity. A recent study suggests that the conventional proppant-sizing criteria can be increased to pro-vide increased conductivity while maintaining sufficient fines invasion properties by the simple application of a tackifier to the surface proppant grains. This work indicated that the formation of a stable proppant-pack formation interface is key in preventing formation fines invasion into the proppant pack.

The data presented in this paper show the long-term maintenance of permeability and conductivity for packs that are invaded by fines. The proppant-pack data compare packs treated with a tackifier to untreated packs. Laboratory model study results are provided for a variety of materials and flow regimes. In addition, this paper addresses finer-sized fines infiltration that can cause deep proppant-pack damage. It is generally believed that finer particles produce through the proppant pack without causing significant permeability reduction. The impact of adsorbing finer particles onto a tackified proppant surface is addressed.
MTU - The Multi Test Unit for Investigating Offshore Separation Problems and Optimizing the Gas/Oil/Water Separation Process
Authors: Gramme P. E. , Dybdahl B. , Holt Ø. , Friedemann J. D. , Riise B.
Published: December 2007

Multiphase separation and flow is governed and influenced by phenomena and mechanisms that are strongly dependent on fluid specific properties. A typical example is phase dispersion which is composed of mechanisms like droplet breakup, droplet coalescence, phase inversion and sedimentation/ flotation, which in turn depends upon the nature of the oil/water interface determined by the surface active components of the oil.

There exists a vast number of surface active components in a crude oil comprising of original components like asphalthenes, waxes, inorganic particles and napthenic acids and foreign components like production chemicals (demulsifiers, anti foam chemicals, asphalthene inhibitors, scale inhibitors etc). The composition of an oil is therefore highly specific and therefore also the separation and flow properties of the oil.

In this paper it will be shown how large the variations in the behavior of crude oils can be with respect to their individual separation and flow characteristics. This paper will also focus on what fluid specific information is needed for characterizing the separation and flow properties of an oil and serve as basis for process selection and design.

Tentatively, several methods can be used for obtaining such information. This paper presents a new proven approach for performing separation tests at real conditions, by using a multi test unit (MTU). The use of the MTU will be compared to other methods like "bottle tests", laboratory scale tests, flow loop testing and full scale testing. The advantages and limitations of the various methods will be discussed. By comparing data from oil fields and corresponding test results it will be shown that some of these methods can be used to predict the real process behavior of a fluid. One of the most realistic methods is the use of the MTU. The details of performing a MTU test will be presented, as well as how this test unit can be applied in order to reveal the separation and flow properties of a fluid. Currently, two main areas of interest have proved the suitability of performing tests with the MTU: Firstly, it can be applied in process optimization and as a trouble-shooting tool. Hence, testing and optimization of production chemicals (such as demulsifiers and anti foam chemicals) can be done in a realistic and effective manner. Secondly the MTU can be used in the exploration phase in order to get valuable data as input to process design for new field developments.
Eastern Trough Project Heron Cluster Operations and Producing from Complex HP/HT Subsea Fields
Authors: McClung G. , Coote L. , Davidson W.
Published: December 2007

This paper examines some novel aspects of operating an integrated multiple ownership development operated by BP Amoco consisting primarily of subsea tiebacks to a central processing facility. The complexity factor is high, as some of the reservoirs are high pressure/high temperature (HPHT).

Reservoir conditions for the Shell/Esso fields within this operating regime are particularly severe and a significant amount of Production Chemistry research was carried out up front to meet this challenge.

This earlier research work has now been built on with the benefit of experience and utilizing a methodology known as Focused Results Delivery (FRD) to create a paradigm shift in projected operating expenditure costs.

The producing potential of the wells has also been significantly increased by the use of Finite Element Analysis (FEA) to model critical component stresses.
The Applications of Advanced Computing Techniques to Oil and Gas Facility Optimisation
Authors: Murray A. , Neuroth M. , Stronach A. F. , MacConnell P. F. A.
Published: December 2007

This paper considers the potential impact of advanced computing techniques on oil and gas facility optimisation. Specifically, the application of Artificial Intelligence (AI) techniques is considered. Following a brief introduction to the AI techniques available, possible applications in the oil and gas industry are considered.

The paper builds on the assertion that AI can offer substantial savings to facility operation by citing two case studies of AI application. The first study considers the use of Artificial Neural Networks (ANNs) for the prediction of chemical injection for pipeline operation, and the possible saving that are available. The second study considers the use of a Fuzzy Logic System (FLS) for the optimisation of a pipeline pump station control strategy. Finally, the problems and possibilities offered by AI are discussed.
Deepwater Tie-ins of Rigid Lines: Horizontal Spools or Vertical Jumpers?
Authors: Corbetta Giovanni , Cox David S.
Published: December 2007

Movement towards deeper waters and harsher environmental conditions has, and will, require the continuous development of new technologies. Especially the design and operation of remote tooling to complete subsea field developments.

One of the principal problems faced during both the design and operational phases of a project is the definition of methods and systems to perform the tie-in of production lines to subsea facilities. This, in fact, influences some critical decisions such as:

Type of lines (rigid/flexible); Structure layout (tie-in porches and interfaces); Installation method (first- or second-end connections).

Sonsub International has developed different systems to perform remote connections of either flexible or rigid lines.

Among these, special attention was paid to rigid line connections since this is the preferred option of the industry because of both technical and economic reasons. This has led to the development of a dedicated set of tooling able to perform tie-ins of rigid lines using standard spool pieces and bolted flanges.

Sonsub simultaneously investigated the concept of vertical jumper installation in deep water as part of a larger development study.

This paper presents a comprehensive comparison between the horizontal (spool piece) tie-in versus the vertical jumper method.

The evaluation will include an overview of the systems considered and will outline advantages and drawbacks, both technical and financial, of the two solutions.
The Alwyn North Triassic Development: Developing a Large Gas-Condensate Reservoir While Making Maximum Use of Existing Facilities
Authors: Murray H J , Schirrer L , Anfray R , Bordmann V
Published: December 2007

The Alwyn North Triassic reservoir is a deep gas condensate accumulation underlying the currently producing Alwyn North Brent and Statfjord reservoirs in quadrant 3 of the Northern North Sea. Two early exploration wells in quadrant 3 had encountered Triassic gas-bearing sands with only the second one, a subsea well, tested but at a non economical rate. However, in 1995 a third well, drilled from the Alwyn North platform, successfully tested at 1.3 Mscm/d of gas and 3,300 stb/d of condensate. A platform extended well test (EWT) was then performed by simply connecting the well to the Alwyn North gas manifold and gas processing train to obtain long term production performance.

Following encouraging results from this well, an extensive appraisal programme was embarked on consisting of drilling three further platform wells and connecting them to production to provide information on long term reservoir performance. In addition, sand frac jobs were performed on two of the wells to assess productivity improvement, access to additional reserves and technical feasibility.

Successful results from the appraisal programme were then used as the basis for a full field development plan for the Triassic, the main element of which is the drilling of additional wells to optimise recovery of the Triassic fluids. The new platform wells will be challenging (total drilled lengths of up to 7800m with depleted sands above Triassic) and an upgrade of the Alwyn North drilling facilities is required. The first platform development well was spudded in April 1999 and peak Triassic production rate is anticipated to be around 5 Mscm/d.

Given the relatively poor reservoir quality and well productivity and encouraging results from sand frac jobs performed during appraisal, improved recovery techniques of hydraulic fracturing and multi-lateral wells are being considered in the development plan. All Triassic wells will be produced via the existing Alwyn North production facilities which require only minor modifications.

It is also planned to debottleneck the high pressure gas train on the Alwyn North platform to ensure that the significant volumes of additional gas brought by the Triassic development can be produced without facilities constraint.

This paper describes how information from the extensive appraisal programme was used to define and optimise the full field development plan whilst making full use of the existing Alwyn North facilities, and upgrading where necessary. Integrated field development aspects (reservoir, drilling and facilities) are presented in this paper.
Synergies between two Neighboring Major Developments
Authors: Stubbs John , Fort Joel
Published: December 2007

The Elgin/Franklin and Shearwater Developments represent a combined investment of over £2 billion to exploit the HP/HT reserves in the Central North Sea. The parallel development of these two major projects and the associated infrastructure has presented the project teams with a set of new and unique challenges, which have required a combined approach in many areas to produce new answers that have yielded substantial reductions in overall development costs.

The results of this synergy are summarised in the paper and cover the work completed to date. The paper summarises the options examined leading to the selected development concepts, the common gas and liquid evacuation systems, and the associated commercial agreements necessary to define the current and future relationship between the 10 co-venturers involved in the combined developments. The paper rdso summarises the future opportunities for further synergies between the two operators Elf Exploration UK plc and Shell UK Exploration and Production.
Increased Oil Recovery by Economical Pilot Hole Delineation of Reservoirs Using 3D Rotary Drilling Technology
Authors: Gaskin George J. , Laastad Harald , Garvik Ina
Published: December 2007

This paper will focus on the problems encountered directionally when drilling with conventional directional equipment, and demonstrate how, by use of a three dimensional rotary steerable system, successful, cost efficient reservoir delineation was attained, resulting in increased oil recovery and allowing improved field development, both technically and financially.

Two completed wells, F-4AH completed end of 1997 and G-2H drilled late 1998, with similar reservoir faulting and reservoir delineation requirements, will be compared to demonstrate the technical and financial gains made by use of a three dimensional rotary steerable system versus conventional and two dimensional steerable technology.

Resulting increase in oil recovery, future potential for more radical directional profiles and planned improvements will be presented, in the pursuit of further cost saving and increased oil recovery in this challenging drilling environment, where extended reach ‘designer’ type directional profiles well configurations are standard requirement.
Optimization of Mud Temperature and Fluid Models in Offshore Applications
Authors: Kårstad Eirik , Aadnøy Bernt S.
Published: December 2007

High pressure high temperature deep-well drilling is often associated with several unusual problems. Some important factors are pressure control and interpretations of well signals. Mud ballooning, or apparent mud loss during circulation and a pit gain after stopping the circulation, is known to complicate the interpretation of the pore pressure.

In this study, an analytical model is developed by describing the energy balance in a circulating well. Input of energy due to rotation of the drillstring and pumping of the mud are included. The effect of having a riser in offshore applications is also included.

It is shown that for most cases there is a net flow of energy from the formation to the surface. In offshore applications there will always be a heat loss in the riser.

It is also shown that heat transfer from the well is strongly related to the average fluid temperature in the well. Calculating the energy balance provides important information on temperature- and fluid density behavior.
Enhanced Deoiling Hydrocyclone Performance without Resorting to Chemicals
Authors: Sinker A B , Humphris M , Wayth N
Published: December 2007

There are many produced water deoiling hydrocyclone systems operating today that do not meet the required overboard discharge water quality specification. Common reasons for this include long term changes in field conditions, adverse interfacial chemistry (generally caused by a "cocktail" of chemical additives), small inlet dropsizes or sub optimal deoiling hydrocyclone liner types (e.g. large diameter geometries).

The most common solution to these PWT problems is to implement a chemical injection programme which although can be successful, has a high operating expenditure requirement and can often be more harmful to the environment than the oil it was designed to remove. There is also a general industry initiative to minimise the use of production chemicals in a response to the belief that new legislation governing toxic chemical and dissolved hydrocarbon discharge is imminent.

This paper describes a technology which has been developed by Cyclotech to significantly improve the performance of produced water deoiling hydrocyclone systems without resorting to chemicals. The concept is based on precoalescing the inlet oil dispersion to produce a coarser drop size distribution prior to hydrocyclone entry. Field trials have demonstrated that the technology can improve the deoiling performance by as much as 220%. It requires no external control or power source; displays a marked insensitivity to solids fouling and can be easily retrofitted into existing systems without the need for any major vessel or pipework modifications.

The technology is aimed at existing systems which do not meet discharge specification, or require excessive chemical dosing to do so and at new-build systems by extending the applicability of hydrocyclone based solutions to heavy oil, condensate and other historically marginal applications.
Numerical Modeling of a Triple Porosity Reservoir
Authors: Gurpinar O. , Kalbus J. , List D.
Published: December 2007

The triple porosity reservoir investigated is unique with its highly heterogeneous carbonate characteristics. The largest hydrocarbon bearing formations are not only naturally fractured, but also highly vuggy. Special relative permeability, capillary pressure, and compressibility relationships were developed to simulated multi-phase flow in this triple porosity system. Well and interference tests were re-analyzed at several stages in the project to provide input to geology on fracture properties and later to condition the fracture properties coming from the geologic model. The calibrated model acceptably matched the historical pressure and the production of oil, water, and gas for the reservoir complex.
Another Waterfrac Scenario: An Effective Way to Stimulate Shallow Oil Reservoir
Authors: Gu Fagang , Yang Hong , Liu Yongshan , Jiang Jianxun , Wu Shuqiang
Published: December 2007

The successful use of waterfrac to tight gas reservoirs was presented by M.J. Mayerhofer et al[1–3]. However, its application to stimulate permeable oil reservoirs is not reported to our knowledge scope. This paper presents the application of waterfrac to a shallow oil reservoir with low permeability, reservoir M of Laojunmiao oil field (the oldest oil field of China). The average permeability of reservoir M is 24.2 mD. The use of waterfrac to the permeable reservoirs is a different scenario from that to tight reservoirs because the higher fracture conductivity is required in order to ensure the fracture's flow capability. The more than forty-year history, development, optimization and application effect of waterfrac to reservoir M are given out in this paper.
Feasibility of Downhole Oil/Water Separation and Reinjection in the GOM
Authors: Suárez S. , Abou-Sayed A.
Published: December 2007

A study of the feasibility and applicability of Downhole Oil/Water Separation and Reinjection Systems (DOWS) for the GOM is presented. According to reservoir simulations, oil production increases when applying DOWS. Also, an additional pressure boost at the exit of DOWS is enough to lift the separated volume to surface. In contrast, without DOWS, it is necessary to rely on artificial lift to achieve well production. Targeting reasonable injectivity can provide commercial and available equipment capable of injecting water above the injection zone.
Determination of Injection-Production Ratio Size by Type-curve Analysis
Authors: Dong Jianxia , Zhai Yunfang , Yang Jing , Zhao Chunshen
Published: December 2007

Many oil and water wells are distributed over the all developing reservoirs, of which one well's pressure test data are controlled by multiple well system. People used to solve this problem by taking testing well as a single well system with constant pressure or closed outer boundary. This paper touches upon the outer boundary with constant rate, that is, the effect of multiple well system on testing well is reflected on the injection rate at the outer boundary of testing well, whose relation with the production rate of testing well is Injection-Production Ratio (IPR) of the drainage area. Obviously, such dealing reflects the mutual relationship of oil wells and water wells more truly and universally. For example, closed boundary can be regarded as a special case of outer boundary with constant rate (when IPR=0).

A new type-curve is presented for considering IPR. Using it on well test analysis, not only the usual well and reservoir parameters can be obtained, such as permeability, skin factor and wellbore storage constant etc., but only yield IPR in drainage area of testing well. The practicality of this type-curve is proved by the illustration of test data from Daqing Oil Field.

This paper has successfully solved the well test analysis problem of multi well system, and it is of great importance in guiding well test data interpretation, pattern modification and injection-production balance analysis for present waterflooding reservoirs.