bluuebunny/crossref_metadata_2025 huggingface dataset:
A Study on Two Phase, Non-Darcy Gas Flow Through Proppant Packs
Authors: Jin L. , Penny G.S.
Published: December 2007

The effect of liquid phase on non-Darcy gas flow through proppant packs has been characterized by correcting the non-Darcy flow Forchheimer coefficient as a function of liquid saturation in the proppant pack in the past. Through an extensive experimental study it is found that at high liquid saturation, Forchheimer correlation does not hold anymore. A non-linear relationship appears that cannot be characterized by factor alone. Tests are focused on the investigation of the effect of proppant properties (permeability and porosity), liquid properties (density and viscosity), and gas properties (density and viscosity) on the non-Darcy, two phase flow behavior. An empirical model that uses the liquid to gas ratio to predict the effective permeability or conductivity of a proppant pack under two phase, non-Darcy flow conditions is discussed in the paper.

Based on the fact that proppant packs have relatively narrow pore size distributions, a simplified physical model has been developed to represent two phase (liquid and gas), non-Darcy flow through proppant packs. The purpose of developing the model is to understand the effect of gas flow on the velocity of liquid in a two-phase flow process. As a result, the model can calculate a mobile liquid saturation corresponding to each combination of gas-liquid flow rate. The relative permeability of a proppant pack at different conditions can then be calculated taking both non-Darcy and two phase flow effect into account.

P. 675
Development of Drilling Facilities for a Field Development in the Caspian Sea
Authors: Nichols J. , Scoular T. , Hagger P.
Published: December 2007

The Caspian region is currently the focus for the rehabilitation of existing fields and the development of new offshore fields. This is providing unique opportunities for both operators and contractors. New drilling facilities are currently being designed for these fields by an integrated operator and drilling contractor team. Ensuring that the lessons learned from previous projects, both from within the Caspian and other areas, is essential, so that the optimum technical and economic solution is selected. At the same time the limited transportation options into the region and current local infrastructure constraints add an extra dimension to be overcome.

This paper will discuss how the design for a platform drilling rig, complemented by a lightweight completion rig has evolved in preference to installing two full size drilling rigs on a single drilling jacket. This combination is planned to be deployed on two drilling platforms in the Caspian Sea during 2001. The involvement of operations personnel in the project from the outset has allowed many of the previous failings of simultaneous operations elsewhere to be eliminated during the design.

The arrangement will provide a significant Capital expenditure saving as well as reduced operating costs. The ramp up to peak production will only be marginally slower than if two full size twin rigs were installed. It is expected that the design will form the basic building block for the remainder of the field development.

P. 741
Slimhole Drilling and Coring - A New Approach
Authors: Bencic A. , Prohaska M. , de Sousa J.T.V. , Millheim K.K.
Published: December 2007

Over the past years, slimhole drilling has proved to be a cost effective way of drilling certain exploration and exploitation wells. However, one of the major downsides to slimhole drilling are poor penetration rates as compared to conventional hole sizes.

The paper presents the design and proof of a dual-body bit concept which gives the user the possibility to change the bit's characteristics (profile, cutting structure, hydraulics, etc.) and thus alter its performance significantly without the necessity of a round trip.

Additionally, with this approach, the purpose of the drilling mode can be easily switched from coring to full hole drilling and vice versa. This is done, similar to the process of adjusting the bit, from the surface with the use of a conventional wireline assembly, which gives a reasonable potential for improvement for the overall drilling process.

The idea for this new drilling approach emerged from a research project that initially had the aim of filling the gap of optimal slimhole PDC drill and core bit design. The studies confirmed that there is a limitation for the use of PDCs when drilling certain hard, heterogeneous multi-layered formations, no matter how sophisticated the bit design itself might be. After exhausting all conventional slimhole PDC bit designs it became evident that an entire new paradigm was needed. The mining industry had experimented with the two body bit, but had never seriously exploited the concept for sedimentary drilling. Today the possibility of easily running the inner bit and retrieving it is standard technology. This project has taken the mining technology to a higher level by introducing the concept of dynamically changing the properties of the bit downhole (without tripping) to optimize penetration rate performance for all kind of sedimentary rocks. Results from an in-house laboratory testing series are included, documenting first dual body bit design efforts, and performances achieved.

P. 771
Control of Shale Swelling Pressures Using Inhibitive Water-Base Muds
Authors: Chenevert Martin E. , Pernot Vincent
Published: December 2007

Over the years wellbore stability in shales has been achieved using oil base muds, however water base muds still plague the industry. Up until now it was not obvious what mechanisms were in operation during such shale/water base mud interactions. The research reported herein discusses the development of swelling pressures when water base muds are in contact with a troublesome North Sea shale. A mechanistic theory is presented that focuses on increases in total pore pressures that are reflected in swelling pressures. The results obtained showed that different mud filtrates produce swelling or shrinking pressures that are related to the type of salt present and its ionic concentration. Fluids tested included de-ionized water and solutions of CaCl2, Potassium Formate, Glycerol, Methyl Glucoside and NaCl/Methyl Glucoside. The range of swelling pressures measured were from +2800 psi (swelling) to -1400 psi (shrinkage). In addition to swelling pressures, the compressive strength of the shales was also measured under downhole insitu stress and conditions after the chemical interactions were complete. Strength reductions as high as 35% were measured for certain fluid systems.
Determination of Gas-Condensate Relative Permeabilities from Field Production Data
Authors: Sumnu-Dindoruk M.D. , Jones J.R.
Published: December 2007

Gas condensate reserves are increasing in size worldwide as more and more deep wells are drilled. Increased modeling efforts to optimize the performance from gas condensate reservoirs need accurate and reliable determination of condensate relative permeability curves. The use of nonrepresentative relative permeability curves may result in over/under estimates in performance predictions.

Laboratory measurement of relative permeabilities is the most common method used in relative permeability determinations. However experiments by using field representative cores and fluids at reservoir conditions are expensive and difficult to conduct. That is the reason why laboratory measured relative permeability curves are scarce and contradictory in nature.

On the other hand field automation data such as production rates and recoveries are usually available from the field. In this paper we propose a quick and reasonable method to estimate the gas and condensate relative permeabilities using this type of data. Our procedure is a modification of a method presented by Fetkovich et al. for black oil systems. Our modifications allow us to deal reasonably well with the nonuniform saturation distributions which play a unique role in the performance of gas condensate systems. The method requires flowing pressures, gas and condensate production rates and PVT properties of the condensate fluid. The new method was tested via simulation for a rich condensate fluid and it worked well in estimating the relative permeabilities. The major advantage of this approach is that the relative permeabilities calculated are representative of field performance. Hence the relative permeability curves obtained represent a naturally upscaled set of curves which can be used directly or as a guide in upscaling laboratory measurement curves.

P. 655
Uncertain Cap Rock Geometry, Spill Point, and Gross Rock Volume
Authors: Abrahamsen Petter , Hauge Ragnar , Heggland Knut , Mostad Petter
Published: December 2007

The geometry of the cap rock of a petroleum reservoir is never exactly known so that the depth and lateral location of the spill point are uncertain. Therefore, the gross rock volume of a filled structure is uncertain due to uncertainty in cap rock geometry and the depth to the hydrocarbon contact determined by the spill point. A method for evaluating this uncertainty has been developed. First, the geometry of the cap rock is simulated using established Monte Carlo simulation techniques for surfaces based on Gaussian random field models. Secondly, a new fast algorithm finds locations of spill points and trapping areas of the simulated structures. Finally, gross rock volume of the traps can be calculated and volume distributions can be quantified in terms of histograms and quantities. The spill point detection algorithm is fast and reliably even on complex and irregular structures.

A synthetic example and an example from the North Sea illustrate the possibilities and properties of combining a fast spill point detector with Monte Carlo simulation of surfaces.

P. 723
Simulation of Permeability Field Conditioned to Well Test Data
Authors: Srinivasan Sanjay , Journel Andre G.
Published: December 2007

Well testing provides critical information about the effective permeability value around the well being tested. That information must be integrated with higher resolution, smaller scale, well log data. The difference of scale is handled by kriging with "block" averages, while the non-linear averaging of permeability values is addressed by working on specific non-linear power transform of the original permeability data. A case study shows the simulated permeability fields to honor, in expected value, the well test-derived effective permeability values in addition to honoring the smaller scale well log data and statistics. Ignoring the well test information would result in permeability fields that are imprecise around the well being tested and which display too large uncertainty. The necessity of data integration, even when data are of widely different scales, is demonstrated. The paper also discusses cases when the well test-derived effective permeability appears inconsistent with the well-log derived smaller scale permeability data. The paper points out the limitation of the linear power-averaging formulation for capturing the dynamics of fluid flow.

P. 731
Improving Field Economics Through the Use of Modern Casing-Corrosion Logging Tools and Techniques
Authors: Wheeler Ralph R.
Published: December 2007

Because casing integrity is vital to the success of sidetrack, workover, recompletion, and enhanced-recovery operations, it is important to use reliable means of examining casing downhole. Modern casing inspection tools provide valuable diagnostic information for planning future work in a single well or an entire field.

An operator wished to improve economics in a field where casing corrosion and water production was becoming a significant problem. The goal was to increase overall production and reduce production costs by (1) performing remedial work on wells that still had production potential and could be repaired, and (2) discontinuing production from the remaining wells.

A critical component in the operator's plan was the selection of wells in which corrosion problems were not severe enough to preclude remedial operations. Complete histories were not available for every well, so the operator chose to use the latest technology and techniques in electromagnetic, acoustic, and video logging for corrosion detection and evaluation.

Electromagnetic logs were used to grade casing, create pipe tallies, and identify pipe anomalies on the inner and outer casing surfaces. Acoustic logs were used to image the interior of the pipe, analyze internal corrosion, and study cement bonding to the casing. Video logs provided real-time views of the downhole casing environment for assessing casing problems, locating fluid entry points, and identifying fluid phases.

This paper discusses the corrosion-logging program that was developed for this field. Examples are presented of different problems encountered, the solutions recommended, the results obtained from those solutions, the current status of the wells, and the economic impact of the casing evaluation program. The paper discusses the logs used in this program, and includes comparisons of different log types. Furthermore, photographs of casing pulled from one well are compared with an electromagnetic log run in that well.

P. 761
A Robust Permeability Estimator for Siliciclastics
Authors: Herron M.M. , Johnson D.L. , Schwartz L.M.
Published: December 2007

A permeability estimator is constructed from the lambda parameter, A, which is the size of dynamically connected pores. For simple pore geometries at high permeabilities, A should theoretically be proportional to the pore volume-to-surface area ratio. Further, at high permeabilities, the permeability is proportional to A2/F, where F is the formation factor. Core data are used to establish the proportionality constant. For permeabilities less than about 100 mD, this formula overestimates the actual permeability by a factor related to the original estimate. Thus, a corrected second estimate can be readily made, and the combined estimate is shown to match measured permeabilities on a diverse set of sands and shaly sands with a correlation coefficient of 0.89 for log k. The estimate can also be made using NMR relaxation time data, instead of the surface-to-pore volume ratio, with a correlation coefficient of 0.92 for the same data set. The estimate can also be made from mineralogy or lithology data, in which each mineral or lithologic fraction is assumed to have a fairly constant specific surface area. Examination of the data suggests that only about 10% of the total clay mineral surface area normally influences fluid flow. For Fontainebleau quartz arenites, the resulting estimate has a correlation coefficient of 0.99 with the measured permeabilities. For Utah sands and shaly sands, the mineral-based estimate has a correlation coefficient of 0.84 with the measured permeabilities; the lithology-based estimate had the same correlation coefficient. Using the lithology-based form of the equation, accurate permeability logs are derived from geochemical logs in Utah and from conventional logs in Venezuela..

P. 777
Improved Resistivity Interpretation Utilizing a New Array Laterolog Tool and Associated Inversion Processing
Authors: Smits J. W. , Dubourg I. , Lüling M. G. , Minerbo G. N. , Koelman J. M. V. A. , Hoffman L. J. B. , Lomas A. T. , Oosten R. K. v. d. , Schiet M. J. , Dennis R. N.
Published: December 2007

In many situations the traditional dual laterolog does not supply sufficient information in thinly bedded formations to unambiguously determine true formation resistivity (Rt). In addition, the laterolog-deep measurement may be affected by the presence of highly resistive layers, especially when logging close to the casing (Groningen effect) or when the tool is conveyed on drillpipe. These limitations of the traditional dual laterolog measurement can lead to sub-optimal development decisions and even to missed production opportunities.

A recent array laterolog tool, combined with inversion processing, provides answers to these issues. The tool makes several focused measurements with different depths of investigation, in concept similar to an array induction tool. The hardware is optimized to supply maximal measurement-information. The data is interpreted by inversion software using formation models of varying complexities to best approximate the true formation resistivity. All measurements use bucking currents returning to the tool rather than to surface, effectively eliminating the Groningen and drillpipe effects.

At the wellsite, Rt is provided by a fast one-dimensional (1D) inversion that takes into account only radial resistivity variations and is strictly applicable only in thick beds. The input-curve reconstruction identified inconsistencies between this simplified model and the true formation that would go unnoticed when inverting conventional dual laterolog data. A typical example is the proximity effect of a cap rock in a horizontal well, which produces curve separation that is qualitatively distinct from the separation caused by invasion.

In thinly bedded formations, inverting a two-dimensional (2D) axisymmetric formation model improves the interpretation by simultaneously accounting for radial and vertical resistivity variations. The inversion can handle complex invasion profiles and produces a 2D image of the formation resistivity.

These methods were applied to surveys of a number of wells drilled in clastic formations, ranging from vertical to highly deviated and horizontal. Comparison with tools operating according to the dual laterolog principle clearly showed the benefit of this new technology. Interpretation improvements were obtained mainly from the increased information content of the array signals. Also, the absence of artifacts associated with distant current returns (such as Groningen-type effects) improved the saturation evaluation.
Solvent-Acid Dispersions Solve Difficult Stimulation And Clean-Up Problems
Authors: Coffey M.D. , Thompson J.L. , Carney M.J.
Published: December 2007

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

This paper was prepared for the Rocky Mountain Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Billings, Montana, May 15–17, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is granted upon request to the Editor of the PETROLEUM ENGINEERS JOURNAL is granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

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

Acid stimulation or clean-up treatments of producing and injection wells are often complicated producing and injection wells are often complicated by hydrocarbons which prevent intimate contact between acid and acid-soluble materials. The use of hydrocarbon solvent-in-acid dispersions to simultaneously dissolve both the hydrocarbon and acid soluble deposits has proved highly effective. This allows one-stage cleanup of hydrocarbon coated formations and avoids costly multi-stage treatments.

Introduction

The production of oil and gas wells is often seriously hindered by the presence of hydrocarbon and inorganic scale deposits in the tubing, the wellbore, formations and downhole equipment. Only acid soluble inorganic scale will be discussed in this paper. These accumulations of hydrocarbons and inorganic scale cause a gradual decline in production which is often mistaken for the natural production which is often mistaken for the natural decline of a well. These same deposits also lower the injection rates of water injection wells. To obtain full production or injectivity capacity it is often necessary to remove the deposits.

Hydrocarbon removal techniques are numerous and may be divided into three categories:Mechanical — scrapers and abrasivesChemical — solvents and surfactantsThermal — hot oil and heaters

All of these categories have been used commercially. Numerous paraffin inhibitors have also been used to help control the problem. Only the chemical removal techniques will remove an appreciable amount of hydrocarbons from within the rock matrix. Solvent removal differs from surfactant removal in that the solvents dissolve hydrocarbons while surfactants only disperse hydrocarbon deposits.
The Design and Early Performance History of Two Waterflood Pilots in the Mauddud Carbonate Reservoir, North Kuwait
Authors: Al-Anzi Ealian , Mousawi Ahmed , Malik Satinder , Blackburn Neal , Reddick Chris , Rothwell Nigel , Young Perry , Haynes Byron
Published: December 2007

The Mauddud formation is a major oil bearing carbonate reservoir in North Kuwait. Historical Production (spanning over 40 years) has confirmed that the reservoir receives very little natural pressure support. This has resulted in a declining reservoir pressure and low recovery factor. The forward development plan is to waterflood the Mauddud, increasing production rate and ultimate recovery. An assessment of the reservoir suggests that a pattern waterflood will be required to achieve the aggressive production profile while meeting targets for increased, ultimate reserve recovery.

The waterflood pilot project (WFP) was planned to gather actual field data on waterflood performance in representative areas of the reservoir. A thorough screening of the available reservoir data was conducted in order to select suitable locations for the pilots. A limited area 3D seismic survey was shot over these locations to further check that no major reservoir anomalies were present in the planned pilot areas.

Two inverted five spot pattern waterfloods were planned and constructed, one in each of the Raudhatain and Sabriyah fields. Production wells were completed with artificial (gaslift) lift capability to allow continued production as watercuts increased. A novel twin ESP source water system was constructed to take water from a deep aquifer source and pump this into the injection well at the necessary rate and pressure. A comprehensive data acquisition programme during the well construction and commissioning phase of the project allowed the essential base reservoir data to be acquired.

A multiwell interference/Pulse test was conducted in both pilot areas prior to the start-of full production/injection, this confirmed good connectivity within the pilot areas.

Full pilot operation commenced in June 97, with first water breakthrough (in some of the production wells) being observed 2–3 months after start-up. this was within the range of earlier predictions

The pilot waterflood has already given a valuable insight into the performance of the Mauddud under waterflood conditions and the pilot results indicate the Mauddud can be successfully developed by adopting a pattern waterflood approach. Injectivity and productivity have been better than expected and the implications for sweep efficiency /directionality and reserve recovery look encouraging.
The Effect of Cloud Point Temperature on Wax Deposition
Authors: Sadeghazad Ayoub , Christiansen Richard L.
Published: December 2007

The main object of this paper is to evaluate and discuss wax deposition problem. It can vary from minor to extremely sever depending on the cloud point temperature, the operating temperature, and the wax content of crude oil. On the other hand, cloud point temperature is related to the solution apparent molecular weight. In other words, cloud point temperature is a function of solute and solvent apparent molecular weights and their mole fractions.

Two sets of experiments were performed to analyze the effect of cloud point temperature on wax deposition. The first was solute mole fraction (weight fraction) dependence and the second was solvent dependence experiments. The results indicate that as the apparent molecular weight of solution decreases, the cloud point temperature decreases. So, the lower cloud point temperature, the later precipitation and deposition of wax.

As the apparent molecular weight of solute and its mole fraction decreases, the cloud point temperature decreases. Moreover, as the mole fraction of the solvent increases and its apparent molecular weight decreases, the cloud point temperature decreases.
Litho-Facies and Permeability Prediction from Electrical Logs using Fuzzy Logic
Authors: Cuddy S. J. , Putnam T. W.
Published: December 2007

Several areas of the geosciences have benefitted from the application of the new mathematics of "fuzzy logic" (Nordlund1; Cuddy2). BP routinely uses new interpretation techniques, based on fuzzy logic, to predict permeability and litho-facies in uncored wells. Litho-facies and permeability prediction have presented a challenge to formation evaluation due to the lack of tools that measure them directly.

Fuzzy logic is simply an application of recognised statistical techniques. Whereas conventional techniques deal with absolutes, the new methods carry the inherent error term through the calculation rather than ignoring or minimising it. This retains the information associated with the error and gives surprisingly better results.

One clear application is to litho-facies determination. Litho-facies typing is used in well correlation and is important for building a 3D model of the field. The technique makes no assumptions and retains the possibility that a particular litho-facies type can give any log reading although some are more likely than others. This error or fuzziness has been measured and used to improve the litho-facies prediction in several North Sea and Middle East fields. In one study, descriptions from 10 cored wells were used to derive litho-facies descriptions in 30 uncored wells. This technique gave near perfect differentiation between aeolian. fluvial and sabkha rock types. In addition, it went some way towards differentiating between sandy, mixed and muddy sabkhas. Using the fuzzy logic technique gives better predictions than more complicated methods.

A second application is permeability prediction. Knowledge of permeability is important in determining the well completion strategy and resulting productivity. The problem with permeability prediction is derived from the fact that permeability is related more to the aperture of pore throats rather than pore size, which logging tools find difficult to measure. Determining permeability from logs is further complicated by the problem of scale; logs having a vertical resolution of typically 2 feet compared to the 2 inches of core plugs. The new techniques quantify these errors and use them, together with the measurement, to improve the prediction. This new approach has been used in several fields around the world to obtain better estimates of permeability compared to conventional techniques. In addition, the method relies on basic log data sets such as gamma-ray and porosity rather than depending on new logging technology.
New Classification of Carbonate Rocks for Reservoir Characterization
Authors: Marzouk I. , Takezaki H. , Suzuki M.
Published: December 2007

Several classifications of carbonate rocks are known to the oil industry. The most recent one is the Dunham Classification, 1962, more than 33 years ago. In these classifications, several descriptive names were used to identify different types of Limestones which have created a lot of confusion specially for non-geologists. Rock typing is one of the main challenges in reservoir characterization. Defining porosity and permeability finger prints for each rock type is a subject of increasing interest in reservoir geology. This will help defining permeability distribution, better understanding of fluid flow behavior which will lead to more realistic • production forecast. Unfortunately, previous classifications of carbonate rocks are not enough to satisfy this objective since conventional rock types have wide range of porosity and permeability. Detailed core description and petrographic studies on the Thamama and Arab Carbonate reservoirs of Abu Dhabi have significantly contributed to the internal architecture, the building blocks and other parameters used in carbonate rock classification. Scanning Electron Microscope, Nuclear Magnetic Resonance and Mercury Injection Capillary Pressure were used to differentiate between the different rock types. The main objective of this work is to find out a practical classification of carbonate rocks to be used in reservoir characterization and to match with the petrophysical and dynamic data. The building blocks of carbonate rocks used in this study are the micrite crystals, the micrite particles and the carbonate grains. The Micrite particle is a new component introduced by the authors to the building blocks of carbonate rocks. It represents an aggregate of micrite crystals ranging in size between 10–20 microns which create inter-particle porosity of approximately 4 microns. This new finding has explained the major deflection on the Ø/K cross plots of the Thamama reservoirs of Abu Dhabi.

The new classification proposed in this work is mainly based on pore throat size distribution. The other components used in this classification are the micrite particles, grain/micrite ratio and core porosity and permeability. The proposed classification has explained several unique cases related to mis-matching among descriptive rock types, measured petrophysical data and dynamic data. Significant variation in permeability at constant porosity and the changing capillary pressure and relative permeability behavior for one and the same rock type are good examples.
A Micromodel Study of Acidization Foam
Authors: George D. S. , Islam M. R.
Published: December 2007

The generation of foam in porous media is believed to be through a series of snap-off and bubble/lamella processes. Even though this hypothesis explains the generation of foam in porous media, the propagation of foam through the same series of phenomena is not properly explained. In an effort to develop a theory, generation and propagation of foam in porous media were visualized in a micromodel. The generation and transport of foam were observed as a function of pressure, flow rate, the presence of acid, the presence of oil, and surfactant concentration. It was found that for most cases the generation process itself is chaotic. However, a narrow band of parameters was detected for which periodic and even quasi-periodic behaviour was observed. Interestingly, the range of periodic and quasi-periodic behaviour was broader in the presence of acid. The presence of oil led to easier attainment of the chaotic state.

The role of geometry was found to be important. For instance, periodic behaviour was observed more easily in the pore neck as compared to the pore body. Flow rate and pressure both enhanced the chaotic state and narrowed the band of the existence of the periodic and quasi-periodic state. The existence of quasi-periodic behaviour in multiphase systems has rarely been identified in the past. The relevance of these so-called theoretical states to the petroleum engineering aspect is discussed in the paper. It is shown that these observations lead to valuable clues for the design of a foam diversion process.
Formation Damage and Near Wellbore Flow in Reservoirs – An Experimental Study
Authors: Al-Marhoon N. O. , Grattoni C. A. , Dawe R. A. , Carter J. N.
Published: December 2007

The most important region of a producing reservoir is the zone within 5 meters of a wellbore. All fluids have to flow through it, usually at high flow rates compared to that in the deep reservoir away from the wellbore. Exactly how and what route the fluids flow to the perforations and hence into the wellbore is not well understood. The near wellbore formation permeability significantly affects pressure profiles and hence well deliverability and production rates. This near wellbore area is usually damaged in that its averaged permeability is less than the average of the reservoir; such effects are often termed ‘skin effects’.

This paper aims to improve our understanding of near wellbore flow by experimental demonstration of the differences in flow and displacement behaviour between heterogeneous and homogeneous porous media. The heterogeneities under investigation are permeability and wettability contrasts. We believe that the differences are very significant and their neglect in the past has led to the many reported (and unreported) failures in well-bore stimulation, and which have proved very costly. In our experiments we have used visual models packed with Ballotini glass beads. The permeability/wettability contrasts were carefully controlled and tested. The experiments provide visual evidence of the flow patterns occurring within such heterogeneous porous media in the vicinity of the wellbore. Pressure distributions around this heterogeneous area show where the flow restrictions are likely to occur.

If the understanding of the near wellbore flow can be incorporated into simulation, then the accuracy of the reservoir simulation and the characterisation of the reservoir itself should be improved. This may provide a reduced range of uncertainty when interpreting history matches, well tests and well logs. Also a better appreciation of near wellbore flow patterns before well clean-up should improve the reliability of the chemical placements.
Static and Dynamic Reservoir Rock Compressibility at High Pressure
Authors: Macini Paolo , Mesini Ezio
Published: December 2007

The paper reports measurements of rock compressibility performed by means of an equipment capable to operate up to 150 MPa confining pressure. Measurements have been performed on 32 samples from 3 sandstone and 3 carbonatic reservoirs. The experimental apparatus was designed to perform both static investigations (deformation tests, to calculate bulk and pore compressibilities) and dynamic investigations (acoustic tests, for the evaluation of undrained compressibility). Results show that compressibility is not constant, but is a function of reservoir pressure. In particular, compressibility of sandstones follows an exponential trend, decreasing rapidly in the first part of the loading cycle, and remaining almost constant at high pressure. Compressibility of carbonatic samples shows the same behaviour, but increases for stresses close to the yield point. The attempt to correlate dynamic and static tests reveals the necessity of additional investigations; in fact, it has been noticed that undrained compressibility measured by dynamic tests yields inconsistent results for non-elastic rocks, and, generally, dynamic measurements do not correspond to the static ones.
Organizational Learning and Management of Change
Authors: Khoori Ahmed
Published: December 2007

This paper introduces the theory of a learning organization and management of change followed by their practical applications in the Abu Dhabi Company for Onshore Oil Operations(ADCO).

The paper highlights the meaning of a learning organization and the management of such organization together with the measurement criteria necessary to measure progress. It also explores why some change initiatives have failed to provide the necessary results.

Furthermore, distinctive policies and practices that are responsible for the success of learning organizations and the forming of the five building blocks of a learning organization, namely systematic problem solving, experimentation with new approaches, learning from their own experiences and best practices of others in addition to dissemination of knowledge, is introduced.
Rock Type and Permeability Prediction from Mercury Injection Data: Application to a Heterogeneous Carbonate Oil Reservoir, Offshore Abu Dhabi (United Arab Emirates)
Authors: Al-Aruri Ahmad , Ali F. Baba , Ahmad Habib A. , Samad Saleh A.
Published: December 2007

Present study highlights reservoir engineering contribution to a reservoir characterization study.

Subject reservoir is a heterogeneous limestone and dolomite carbonate reservoir, with a huge gas cap, producing under peripheral water injection.

Available conventional and SCAL data were screened, filtered and introduced in spreadsheets.

Measured permeability and porosity values were corrected to reservoir conditions in order to bring all relevant data to the same conditions.

The main objective of analyzing Mercury Injection Capillary Pressure (MICP) data was to come up with conceptual reservoir flow-model from integrating the rock fabrics of the depositional facies with the MICP measurements.

Distinguishing dolomite from limestone plugs was the first step taken in the rock typing exercise based on petrography findings. MICP curves were sorted based on various criteria to come up with 16 rock types using Excel 7.0 spreadsheets equipped with macro facility to speed up analysis. Water saturation versus pore throat distribution and R35 ( Inverse of capillary pressure at 35% mercury saturation) parameters were found to be the most useful tools in this exercise.

Second campaign of mercury injection data (99 samples) was carried out in order to capture more samples in low populated rocks. This brings total mercury injection samples to 568 taken from 15 wells, in which around 50% were dolomite.

The 16-rock-model has been successfully correlated to distinctive flow units (such as FZI: Flow Zone Index and RQI: Reservoir Quality Index) and in light of the results it was possible to upscale the 16-rock-type model into 9-rock-type model. The 9 rock types consist of 4 dolomite rock types and 5 limestone rock types.

A stochastic model has been developed and applied successfully on cored wells, using Random Number Generator function in Excel 7.0, to predict rock number (type) at a given porosity and permeability for every foot.

Capillary pressure end points were used to predict water saturation and comparison against water saturations from logs revealed a good relationship.
Use of an Economic Incentive Factor in the Correlation and Projection of Discovery and Production Rates of Natural Gas in the Lower 48 States
Authors: Linden Henry R. , Parent Joseph D.
Published: December 2007

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

An economic incentive factor has been found whose trend has closely paralleled that of annual gross additions to proved reserves of natural gas in the lower 48 states for the last 20 years. This factor is the weighted average price at the well for hydrocarbons (natural gas and oil) divided by the square of the average cost of drilling and equipping new wells (oil, gas and dry). For convenience, the well cost is put on a relative basis referred to the 1946–50 average. All prices and costs are expressed in constant 1972 dollars. The economic incentive factor has been a leading indicator of discovery rate by 2 years.

The factor can be used to modify the IGT model for U.S. natural gas discovery and production to make it responsive to yearly changes in economic incentives to search for new supplies. Using the modified model and a projected trend of the economic incentive factor, future natural gas supplies in the lower 48 states have been calculated. Some projections have also been made on the basis of three possible scenarios in terms of annual possible scenarios in terms of annual gross additions to proved reserves.

All indications point to the need of promptly reestablishing and maintaining promptly reestablishing and maintaining much higher annual additions to proved reserves by sharply increasing the weighted average wellhead price of oil and gas. Otherwise, production of natural gas in the lower 48 states will decline soon.

Note: This study was based on historicaldata for the period 1946 - 1972.Since its completion, natural gas discovery and production data for 1973 have become available. None of the correlations or projections would be materially affected by inclusion of these new data, which are discussed briefly at the end of the text

Introduction

The United States has now had 6 years of inadequate natural gas discoveries in the lower 48 states and 3 years of substantially less than required natural gas production. production.
LNG Imports and FPC Regulation
Authors: Mathura Randolph E.
Published: December 2007

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

The United States Federal Power Commission's approval must be obtained for the importation of LNG, which has been considered as natural gas, and for the transportation and resale of imported LNG in interstate commerce and the facilities associated therewith. Longterm base-load LNG imports are a potential source of significant potential source of significant supplemental natural gas supply. The required applications for approval of these imports must contain certain descriptive information and are processed, reviewed, and decided according to administrative procedure. The Commission has approved procedure. The Commission has approved several of these applications to date and has decided some of the issues raised therein.

The views expressed herein are the views of the author and do not necessarily reflect the views of the Federal Power Commission or its staff.

Introduction

The technology for the production and handling of liquefied natural gas (LNG) is well established. The benefit of liquefaction is the volume reduction advantage in converting from the gaseous to the liquid phase. This affords a greater degree of flexibility for the transportation and storage of natural gas in many areas of gas utility operations. In addition, liquefaction makes possible the transportation of overseas gas reserves to the United States. These potential LNG imports could have a potential LNG imports could have a significant impact on United States gas supplies.

United States LNG imports can be characterized as short-term and long term.
Plunger Lift Correlation Equations And Nomographs
Authors: Beeson Carrol M. , Knox Donald G. , Stoddard John H.
Published: December 2007

The operation of the 2-in. and 2 1/2-in. expanding cycle-controlled plungers, has been placed on a quantitative basis by means of equations obtained from correlations of field data gathered throughout the United States. For each size plunger, three basic correlation equations express the requirements of gas and pressure as functions of size load and depth. A fourth equation gives the maximum production rate in terms of the same variables.

Using the equations, nomographs have been constructed to permit graphical solution of the problem of plunger lift performance for a given well. The solution is obtained by plotting the "(efficient) operating line" for the well, thereby relating the size load to the gross production rate. Examples of use of the nomographs have been included.

Methods have been described in the Appendix that were used in obtaining the correlation equations from four plots of data for each size plunger. The data represent the operation of plunger lift in 51 wells (or well conditions) with 2 7/8-in. tubing and 33 wells (or well conditions) with 2 3/8-in. tubing. In plotting the figures to determine the correlation equations for pressure build up, data were used only from the 38 wells with 2 7/8-in. tubing in 7-in. casing and the 22 wells with 2 3/8-in. tubing in 5 1/2-in. casing.

No measurable distinction was found between wells operating on formation gas alone and those operating on additional circulated gas. The wells (or well conditions) were about equally divided between these two types. Although it is believed that tailpipes lower the efficiency of plunger lift, the data from the few wells with tailpipes did not show any trend with tailpipe length, providing all calculations were made for the bottom of the tailpipe. Water cuts varied from 0 to 89 per cent, with an average of 23 per cent, and water cut was not found to be important in the operation of plunger lift. Oil gravities were mainly in the mange from 25 to 50 API, averaging 36 API, and no correlation was found between oil gravity and the gas or pressure requirements.

Introduction

One of the most efficient methods of producing oil involves the use of the expanding cycle-controlled plunger. The expanding segments make contact with both the small and large portions of regular API tubing strings, thereby forming an effective seal between the lifting gas and the lifted liquid.
Production Strategy Yields Unique Perforating, Cost-Efficient Multilateral Drilling Solution in the Beryl Field
Authors: Sadek Hani , Williams Charles R. , Smith Michael
Published: December 2007

The Mobil-operated Beryl Field in the North Sea has been producing from the Alpha and Bravo platforms in excess of 20 years. As the field has matured, conditions have changed, necessitating investigation of new solutions to meet the resulting challenges. This paper will discuss the design, development and testing of a new multilateral-type drilling and completion system that was developed to economically address specific drilling and producing requirements. Investigation of various types of completion strategies determined that the general concepts of multilateral technology would have application in providing for field needs. However, currently available technology presented several problems. While access and maintenance of production from two wellbores from one well slot can enhance economics and project risks, existing multilateral technology would significantly increase costs of projects and introduce significant operational risks.

A solution that allows full-bore access to laterals and capability to resume production from the main bore by perforating a sealed hollow whipstock was developed to address one of the Beryl Field needs. Technological advancements of the system include a specially designed whipstock/packer configuration and a specific perforating gun and charge. The equipment has been fully developed, tested and is now available for field application in the North Sea. The new system has the capability of meeting Mobil North Sea, Ltd. objectives of economically maintaining production from mature wells without subjecting side-tracked wellbores to unnecessary risks or access constraints that could compromise project efficiency.

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