bluuebunny/crossref_metadata_2025 huggingface dataset:
What is Balanced Pressure Drilling?
Authors: Bingham M.G.
Published: December 2007

Other things being equal the minimum footage drilling cost will ensue when penetration rates approach a maximum value. penetration rates approach a maximum value. One of the major factors controlling optimum penetration rates is the mud-column pressure. In penetration rates is the mud-column pressure. In planning a drilling program for drilling recent planning a drilling program for drilling recent sediments, it is critical to know whether a maximum penetration rate will occur when the differential pressure [difference between formation pressure and dynamic mud-column pressure] is overbalanced, balanced or pressure] is overbalanced, balanced or underbalanced.

A review of literature shows that from laboratory drilling tests the maximum penetration rate likely occurs at a balanced-pressure penetration rate likely occurs at a balanced-pressure condition. Rates tend to decrease when either an underbalanced or overbalanced condition is established. Results of single chisel tests tend to support these results.

Recently published field results are apparently incompatible with the above work in that they report drilling rates tending to increase as formation pore pressures exceed the dynamic mud-column pressure. The dynamic mud-column pressure has been defined in these reports as:

PP = PDYN = P STATIC + ABP PP = PDYN = P STATIC + ABP where pp = formation pore pressure, psiPSTATIC= static mud-column pressure, psiABP = annulus pressure drop due to flow, psi.

A review of known data suggests a balanced pressure drilling condition actually occur pressure drilling condition actually occur when

PP = PDYN = PSTATIC + ABP + PI + PR,

where PI = Impact pressure in a vertical direction under the bit due to bitrotation, psi. PR = impact pressure in a vertical direction under the bit due to bitrotation, psi.

Using this relationship, recently reported field tests become compatible with previously reported work and it is possible to conclude.

A balanced pressure drilling condition can be defined as: PP = PDYN = PSTATIC + ABP + PI + PR The maximum penetration rate under many drilling conditions occur when formation pore pressure and dynamic mud-column pressures pore pressure and dynamic mud-column pressures are equal.
Cementing Temperature Predictions Based on Both Downhole Measurements and Computer Predictions: A Case History
Authors: Honore R. S. , Tarr B. A. , Howard J. A. , Lang N. K.
Published: December 2007

To plan the cementing operations in a deep, high temperature well drilled in the Rocky Mountains, accurate circulating temperatures were required. Temperature measurements made while drilling were used to validate a computer predicted drilling temperature profile. Given the hole geometry, the geometry of the string to be cemented, the planned cementing fluids, and the planned pumping rates the computer model was used to predict the circulating temperatures while cementing. These predicted temperatures were then used to optimize the cement slurry design.
In-Situ Upgrading of Heavy Oils and Bitumen by Propane Deasphalting: The Vapex Process
Authors: Mokrys I. J. , Butler R. M.
Published: December 2007

Many of the Lloydminster-type heavy oil reservoirs are unsuitable for thermal recovery by steam injection because they are relatively thin and the heat losses to the under- and overburden are excessive. To overcome this difficulty, a new approach has been proposed which utilizes the injection of saturated hydrocarbon vapours at approximately reservoir temperature. There are several modifications of the basic principle under development in which the amount of extraneous heat injected varies from none to moderate, and the vapour chamber is maintained at reservoir temperature to 30°C above it. This flexibility allows the approach to be followed for the recovery of both conventional heavy oils and for bitumen.

The method, termed "Vapex", utilizes two horizontal wells and is closely related to the SAGD process but with the steam chamber replaced by a chamber containing hydrocarbon vapour near its dew point.

The quality of bitumen or heavy oil can be improved substantially by in situ deasphalting with propane vapour. The removal of asphaltenes reduces the viscosity of the produced oil and creates an oil that is more easily refined.

In this paper we present new experimental results obtained in a scaled physical laboratory model and discuss the effect of factors such as injected G/O ratio, different saturation pressures and vapour chamber temperatures on the rate of oil production, the extent of in situ deasphalting and the quality of the recovered oil.
Production Performance of Hydraulically Fractured Gas Wells
Authors: Liao Yizhu , Lee W. J.
Published: December 2007

This study presents simulation results of fracture fluid cleanup and gas production behavior for hydraulically fractured gas wells. Isotropic and anisotropic, and single- and multi-layer reservoirs were studied. Systematic investigation revealed that formation damage near the fracture is a key factor affecting fracture fluid cleanup and gas production. Also, improper simplification of a multilayer reservoir may lead to overestimates of gas production.
An Integrated Laboratory and Field Study to Optimize the Hydraulic Fracturing Fluid System in a High-Permeability Reservoir
Authors: Keck R. G. , Hainey B. W. , Clausen R. A.
Published: December 2007

This paper presents results of an extensive laboratory and field program to optimize the fracturing fluid system used in the ARCO-operated Eastern Operating Area of the Prudhoe Bay Unit on the north slope of Alaska. This study focuses on the fracturing fluid rheology, fluid loss additives and retained proppant conductivity for this high permeability fracturing application. Results of 60 static fluid loss tests performed on filter paper led to optimization of degradable starch loadings and identification of 5% diesel as an effective fluid loss additive. Subsequent dynamic fluid loss tests on Prudhoe core discounted benefit of the diesel, but proppant conductivity testing showed the diesel did improve proppant pack clean-up. Results of mini-fracs performed showed diesel provided identical performance to the significantly more costly degradable starch additive. Laboratory tests of fluid rheology found that orders-of-magnitude increases in viscosity could be obtained by increasing the pH of the delayed-borate crosslinked guar systems used for the 200°F BHT. Despite recent changes in strategy due to smaller treatment sizes (as described by Martins et al1), the results of these laboratory tests have been used to dramatically lower fluid loss additive costs and improve fluid system performance in the high permeability Prudhoe fracturing program.
A Simple Algorithm for Analyzing Gas Pipeline Networks
Authors: Tian Shifeng , Adewumi M. A.
Published: December 2007

A novel algorithm is developed for analyzing and designing gas pipeline networks. The step-forward algorithm is very simple in that it does not require the use of matrix algebra as most existing algorithms do. The simplicity of the method is evidenced by the fact that smaller-sized pipeline networks can be analyzed with a programmable calculator. At the same time, the algorithm provides the means for analysis of any type of steady state gas network. The required input data structure is also quite simple in that no flow direction pre-assignment is necessary. In this work, guidelines are developed to enable the user to determine the minimum data required for analyzing a particular system and to help the user define a well-posed problem.
Naturally Fractured or Single-Porosity? The Importance of Reservoir Flow Model for Performance Assessment of Stimulated Tight Gas Wells
Authors: Carlson E. S. , Latham G. V.
Published: December 2007

We present here the first practical application of a discrete fracture network model, a new type of model for naturally fractured reservoirs. We show how the behavior of fractured reservoirs differs from single-porosity reservoirs, and give the results of several sample calculations. These examples clearly illustrate that the reservoir-flow model must be considered when evaluating flow improvements resulting from well stimulations.
Simulation of Skin Effects and Liquid Cleanup in Hydraulically Fractured Wells
Authors: Iqbal G. M. , Civan Faruk
Published: December 2007

An integrated model is developed to study the skin damage and liquid cleanup of hydraulically fractured wells during post-fracture production. The adverse effects of an injected liquid phase present in the invaded region adjacent to the fracture are simulated by the two-phase and threedimensional flow equations for gas and water in formation, fracture and damaged zone. A phenomenological model simulating the effects of clay swelling and migration of fines leading to skin in the liquid invaded region is incorporated in the study.

Simulation of liquid cleanup is accomplished by first considering the injection of fracturing fluid to study the extent of invaded region and the degree of permeability reduction. This is followed by simulation of liquid recovery and gas production under altered reservoir conditions.

It is found that the mathematical modeling of fluid injection and subsequent cleanup requires formulation of non-linear and coupled model equations, prudent numerical schemes, implementation of refined grids and curvilinear coordinates, and versatile solution methods. The model has been applied to typical field cases, and simulation results indicate that factors such as permeability alteration in the damaged zone and gas relative permeability in presence of a liquid phase must be considered in designing a successful hydraulic fracturing operation.
The Chemistry Prediction and Treatment of Scale Containing Naturally Occurring Radioactive Materials (NORM) in Antrim Gas Fields, Michigan
Authors: Oddo J. E. , Al-Borno Amal , Ortiz Isais , Anthony Robin , Pope D. H. , Hill D. G. , Linz D. G. , Frank James , Becker D. M. , Tomson M. B.
Published: December 2007

BaSO4 scale containing Naturally Occurring Radioactive Material (NORM) as well as calcium carbonate scale has been reported in gas production facilities in conjunction with the Antrim play in northern Michigan. The scale study was undertaken by the Water Research Institute, Inc. (WRI) under contract from the Gas Research Institute. It was proposed in the scale study to conduct a two phase systematic characterization of BaSO4 scale from the Michigan Basin area both as to occurrence and environmental hazard, and to evaluate scale control methods using brines typical of the area. The initial study involved sample collection and analytical work-up to arrive at a correct theoretical analysis of the problems involved. The variability of the sulfate concentrations in the wells is addressed and scale prediction techniques applied to the reservoirs and the surface equipment to determine where scale was forming and where it is likely to form. The scale is proposed to be forming due to the commingling of produced waters from wells with high sulfate concentrations with waters from other wells relatively high barium concentrations. Inhibitor evaluations were done using a high temperature-pressure laboratory apparatus developed at Rice University and WRI (patent application pending with GRI) and effective chemicals and probable dose rates for inhibition were determined. Concurrently, studies were begun by Bioindustrial Technology, Inc. and United Exploration and Development Consultants to learn the sources of the high sulfate concentrations reported in some wells in the area and to determine the causes of souring in some others.

In addition to the scale forming in the surface facilities, NORM scale was predicted and found in production tubing from individual wells. The driving forces for scale precipitation in these wells is the temperature and pressure changes resulting from production Chemical squeeze of inhibitor into the reservoirs and surface injection are recommended to treat and eliminate the scale problem.
An Improved Method for Measuring Fracturing Gel Break with Resin-Coated Proppant
Authors: Harris P. C.
Published: December 2007

Significant gel break problems may exist when using borate crosslinked fluids with resin coated proppants (RCP). A test method was developed which measures proppant settling, fluid breakdown, and flow of broken fluid through the settled proppant pack. Generally, sand settling was nearly complete before the fluid showed significant signs of breaking. The degree of break was determined by measuring the rheological character of broken fluid flow in the proppant pack. This measurement discriminated whether the fluid was fully broken to water-thin or retained base gel character, and whether the proppant pack was partially plugged by broken gel residue.

Guar and HPG borate crosslinked fluids were examined with different breakers, including delayed release oxidizers, enzymes, and acids. Effects of uncoated proppants and resin coated proppants were tested. The dynamics of breaking borate fluids containing curable RCP, which release oxidizer consuming materials, suggests that the release of breaker chemicals must occur at the proper sequence for the polymer breakdown process to work.

The method presented in this paper is useful for observing the process which occurs after a fracturing process is pumped, i.e., proppant settling, fluid breakdown, and flow of fluid through a proppant pack. Concentrations of breaker materials for crosslinked fluids can be determined in the presence of RCP.
Acid Inhibition for Coiled Tubing: Laboratory Screening and Field Verification
Authors: Blount C. G. , Herring G. D. , Patterson W. W. , Walker M. L.
Published: December 2007

Questions concerning acid inhibitor effectiveness at high velocities and in the oxygen rich environments common to Coiled Tubing (CT) applications prompted laboratory testing of several acid inhibitors at various concentrations in common acid stimulation fluids.

Following the laboratory testing, special CT nozzles were manufactured to position standard corrosion coupons in the direct path of the stimulation fluid flow as it exited the CT during acid treatments. The data gathered from the corrosion coupons were used to validate the laboratory tests.

As a result of these studies, unnecessarily high acid inhibitor volumes and undesirable or even potentially hazardous field practices were discontinued. The information learned from the studies was incorporated into field practices, which resulted in safer, lower risk operations, reduced the chance of formation damage, and lowered the overall operating costs for acid stimulation treatments.

This paper documents the testing and results of the lab and field studies. In addition, the nozzles described in this paper provide an easily implemented and inexpensive quality control tool for CT acid work in virtually any area CT stimulations are performed.
Study of Helical Buckling of Pipes in Horizontal Wells
Authors: Wu Jiang , Juvkam-Wold H. C.
Published: December 2007

This paper studies helical buckling, and also critical (sinusoidal) buckling, of pipes (tubing and drillstring) in horizontal wells. The large frictional drag of helically buckled pipes is also studied.

Helical buckling is developed from critical (sinusoidal) buckling as the axial load keeps increasing. But fully developed helical buckling of pipes will not occur in horizontal wellbores until the axial load becomes very large, about 1.8 times the critical buckling load that predicts the onset of sinusoidal buckling, and about 1.3 times the so-called helical buckling load that appears in the current literature. The so-called helical buckling load in the current literature is actually the average axial load in the helical buckling development process. This means larger bit weight or tubing packer load may be applied to increase the drilling rate or to ensure a proper seal, before helical buckling of the pipes can occur.

However, once fully developed helical buckling occurs, the frictional drag may become much larger than it was before the onset of helical buckling. The pipe could even become "locked-up" so that the bit weight or packer setting load can not be increased any more by slacking off weight at the surface.
Analyzing Old Electric Logs in Shaly Sand Formations
Authors: Walsh J. W. , Brown S. L. , Asquith G. B.
Published: December 2007

Analyzing shaly sand formations is complicated even with modem logging suites accompanied with core or CEC data. However when only older logs are available the analysis must be made with fewer models and comparative calculations. This paper outlines several methods for analyzing older electric logs including: computing effective porosity computed from resistivity curves, computing water saturation using the No Porosity Automatic Compensation Model (Asquith, 1990), and Dual Water No Porosity Model (Elphick, 1988), using statistical crossplots, and correlating GR and SP curves to curves from new wells having Cation Exchange Capacity data to utilize the Waxman-Smits Method for estimating water saturation. Examples from two wells are presented to illustrate a procedure for obtaining reliable results from old electric logs.
Integrating Wireline Data With Three-Dimensional Hydraulic Fracture Simulators in the Spraberry Trend
Authors: Barba R. E. , Meyer B. R.
Published: December 2007

Two-dimensional hydraulic fracture simulators are used to design the majority of hydraulic fracture treatments in West Texas. These models assume a fixed hydraulic fracture height. In many cases, hydraulic fracture treatments often do not stay confined within a fixed height as the two dimensional models assume. In the Spraberry/Dean siltstones of West Texas there are no strong barriers to vertical fracture migration, and two dimensional models are clearly inappropriate. Three dimensional hydraulic fracturing simulators overcome this limitation of a fixed height by calculating the fracture height. The inputs required are considerably more involved, and the 3D models require data from both the pay sands and boundary layers. If the raw input data are not available or if sufficient engineering effort is not invested the model output may be misleading. Wireline logs can provide valuable inputs to these three dimensional simulators. These inputs will be discussed, along with case studies where the inputs helped optimize the completion design.
Proven Logging Technology for High-Bottomhole Temperatures
Authors: Gonzalez M. E. , Archuleta J. R. , Polly R. E.
Published: December 2007

This paper describes how a commonly encountered problem with logging deep, hot holes throughout the United States was overcome through the cooperation of a major oil company, service company, and national laboratory. First, we review the past, unreliable performance of standard industry tools during long logging runs at high bottom hole temperatures through actual field examples. Next, we discuss the innovative tool redesign that keeps the inside of the tool cool without increasing the outside diameter of the tool. Finally, we present a comparison of the hot hole and standard tool operating performance in both the laboratory and numerous field examples.
Integrated Field Development Planning Using Risk and Decision Analysis to Minimise the Impact of Reservoir and other Uncertainties: A Case Study
Authors: Stripe J. A. , Arisaka Kazuyoshi , Durandeau Marc
Published: December 2007

The development strategy for a new field is based on the data available from seismic surveys and exploration and appraisal wells. Limitations in this information may still leave large uncertainties in field performance predictions leading to a low confidence in ranking of reservoir recovery methods. Typical development planning based upon single point deterministic reservoir modeling may not be sufficiently flexible to cover all possible outcomes in an optimum manner. This problem may be largely overcome by adopting a more geostatistical approach in which the data uncertainties are reflected within probability distributions for relevant reservoir parameters.

In addition to reservoir uncertainties the importance of fully integrating drilling, surface facilities, and economic constraints is sometimes not obvious during the initial reservoir screening exercise. The ranking of reservoir recovery methods and related development strategies may be radically altered by imposition of these constraints.

Analysis of key decision points and the risks associated with them may be utilised to assist in the formulation of field development strategies that minimise the impact of uncertainties in the limited data. Many strategies may be tested and levels of associated risk and value quantified. Measures to reduce unacceptable risks may be specified. Ultimately an optimal development strategy may be selected.

This paper describes application of the above considerations within an integrated development planning study carried out for an undeveloped field offshore Abu Dhabi.
A Comparison of Existing Multiphase Flow Methods for the Calculation of Pressure Drop in Vertical Wells
Authors: Espanol J.H. , Holmes C.S. , Brown K.E.
Published: December 2007

The estimation of pressure drop for multiphase flow in a vertical pipe is one of the more complex problems in oil field practice. The most successful solutions to this problem involve trial and error calculations in problem involve trial and error calculations in subdivided sections of flow patterns. No two methods yield identical results for a given set of flow conditions as the multiphase flow problem is extremely difficult to analyze. Fortunately the introduction of the computer in the petroleum industry has enhanced the investigation of the multiphase flow problem. Rapid computation provides a means for comparison of individual provides a means for comparison of individual methods and an instrument for the development of new correlations. Three of the best correlations were chosen and evaluated; the Hagedorn and Brown, Duns and Ros, and Orkiszewski methods. The accuracy of these new correlations was determined against multiphase flow pressure drop data from 44 wells. The best solution which was both general and gave satisfactory accuracy for all possible ranges of well conditions was determined. The method of Orkiszewski was found to be most accurate for engineering design usage and was the only correlation which could evaluate a three phase flow condition when water is simultaneously being produced with the gas-oil mixture.

Introduction

Accurate prediction of the pressure drop to be encountered during the multiphase flow of fluids in a vertical well is desired for good engineering data. The lack of reliable pressure drop data and experimental flow pressure drop data and experimental flow apparatus for correlation data gathering represent the inherent problems of obtaining a general multiphase flow model. During multiphase flow in vertical tubing at least four distinct regimes of flow are identifiable. These are usually described as the bubble, slug, transition, and mist flow regions. Figure 1 illustrates the geometrical configuration of the four regions of flow. Bubble flow consists of a continuous liquid phase with little free gas present. As greater quantities of gas evolve present. As greater quantities of gas evolve from the liquid phase, the gas bubbles agglomerate, forming slug-like gas pockets characteristic of the slug flow region. As still greater amounts of gas are released, the transition flow region forms in which droplets of liquid become entrained in the gas pockets. The gas pockets become distorted and approach a continuous gas form.
Dukhan Field (Onshore Qatar) Uwainat Reservoir Optimum Development Scheme
Authors: Hussain Ahmed
Published: December 2007

This paper is a case study that discusses evaluation approach used in determining the development scenario for the Uwainat Reservoir in the Dukhan Field in Qatar. Reservoir simulations performed in support of the project evaluation are presented and results are reviewed.

The simulation study was conducted in two distinct phases. During the first phase, a 3D full field model was constructed and the production history of the Uwainat Reservoir was matched in order to estimate a number of reservoir parameters. The second phase of the study consisted of several 2D cross-sectional models to evaluate the reservoir performances under various exploitation schemes using the history-matched reservoir description. Once the most favourable recovery mechanism was identified from the results of the cross-sectioiial study, several prediction runs were made using the above history matched 3D full field model to determine a number of production forecasts based on selected reservoir development strategies.

The 3D FFN was history-matched through January 1990. Satisfactory matches were obtained both on a field and well basis with relatively limited refinements to the initial reservoir data. The history match indicated the likely presence of two partially sealing faults dividing the reservoir in three separate blocks, a moderately active aquifer and gave an estimation of Kv values across the stylolitic intervals which control the reservoir layering. The results of the cross-sectional study indicated reservoir performances to be influenced by heterogeneity and completion practices, and confirmed peripheral water injection scheme to be more favourable than crestal gas injection giving the highest practical recovery.

Finally, the history-matched full field model was used for predicting reservoir performance at various withdrawal rates. Three development scenarios were studied with plateau rates of 10,000, 15,000 and 20,000 BOPD. A field development plan on the basis of 15,000 B/D plateau production rate appears to be the optimal development scenario.
Application of the First Two Horizontal Wells in Egypt
Authors: El-Rafie E. A.
Published: December 2007

Horizontal wells have been shown to increase productivity, reduce coining tendencies and increase recovery. Until few years ago, the usefulness of horizontal wells has been demonstrated only in North America and Western Europe. In Egypt, not since quite recently has there been several serious horizontal well projects under studies and planned to be drilled. Currently two horizontal wells have been drilled and put on production in Egypt.

This paper reviews the production and reservoir engineering aspects of these trial horizontal wells. Also it illustrates the comparison between the predicted and actual performance of these horizontal wells. Finally, the estimate of the expected critical rate from the horizontal well is compared to that of a vertical well to estimate the possible gain in rates.

In summary, the two wells, although one has not been successfully drilled for enough far from the contact level, has shown potential productivity around ten times that of a conventionally completed comparison well and further productivity increase in similar wells are thought to be possible.

Also critical coining rate comparisons between the vertical and the horizontal wells indicated that horizontal wells are quite suitable for reservoirs that are this, shown high vertical permeability and exhibit water coining problems.
Evaluation of the Effects of Multiples in Seismic Data from the Gulf Using Vertical Seismic Profiles
Authors: Fryer Andrew
Published: December 2007

Surface seismic data can be affected to varying degrees by multiples. However, the exact source and true extent of these multiples are difficult to determine with surface data alone. Vertical Seismic Profiles (VSPs), in which the depth of the reflectors is known, provide a full account of the source and magnitude of multiples. These results are directly applicable to surface seismic processing and to seismic interpretation.

Studies of data sets from the Gulf indicate that different types of multiples affect the seismic data. Long-period events are generated from a few strong reflectors, both shallow and deep. Their period, origin and strength can be directly determined from VSPs. Thinly-bedded, highly reflecting formations, such as the Lower Pars formation, generate short-period multiples, which can affect the shape of the wavelet.

The effects of the short-period multiples can be quantified from the analysis of the downgoing VSP wavelet. It was identified that there was a significant change in the phase of the downgoing wavelet as it passed through the Lower Fars formation. With further analysis of the data, it was shown that this accounted for a two-way travel time delay about 20 msec. A mistie of this magnitude could prove critical to the interpretation of the more subtle reservoirs.

A synthetic VSP was derived from a velocity model calculated from the openhole logs to confirm the effects that the short-term multiples have on the seismic wavelet. By processing the synthetic data in the same way as the measured data, it provided the analogy that short-period multiples are not only generated from within the Lower Fars, but also affect the behaviour of the downgoing wavelet. When the data was processed without the effect of multiples, there was no change in the phase of the propagating wavelet.
Effectiveness of Low-Salt Cement Opposite Salt Bodies
Authors: Ismail S. A. A. , Khalaf Fouad
Published: December 2007

High-salt cements (HSC) have been extensively used across salt formations, mainly because they are supposed to ensure effective bond-ing. However, HSC slurries have serious drawbacks: they require excessive wait on cement, develop late compressive strength, and have high free-water content.

This paper rehabilitates low salt cements (LSC) for use across mas-sive salt formations: LSC have excellent properties that warrart consideration for cementing pipe opposite "moving" salt bodies . For this purpose, conventional API cement laboratory tests were run on class "6" neat cement and on "6" cement plus 35% silica flour mixed with various salt concentrations in the mix-water. The tests compare the basic operational properties of slurry and set cement properties of HSC and LSC. The analysis of these tests shows that the properties of LSC are more effective than those of HSC, and are to be used opposite salts deeper than 3000 feet ss. Below that depth, early compressive strength becomes critical: it is essential for casing support and for stopping salt creep. LSC can be easily tailored to achieve good early compressive strengths that can help stop early salt flow.
Special Horizontal Completion Designs Enhance Running Procedures and Openhole Cleaning Techniques
Authors: Restarick H. L.
Published: December 2007

Horizontal openhole completion equipment requires special design considerations for each application since every well presents a unique set of downhole conditions. Operators who drill horizontal wells must address problems such as frictional drag, screen plugging, openhole cleaning, key seating, and fluid loss that can occur during the final stages of well completion and compromise the efficiency of the well. By careful selection of tools and completion techniques, the operator can plan for successful management of these problems.
Environmental Aspects of Produced Water Disposal
Authors: Allen R. M. , Robinson Keith
Published: December 2007

Within the oil and gas production industry there is an increased focus on the discharge of produced waters to the environment. That there is no universally agreed standard for oil-in-water discharge quality is partly an indication of the different capacities of receiving waters to absorb the pollutants. It is, however, compounded by a lack of any universally agreed methods even on how to measure oil-in-water, with, in extreme cases, results varying by orders of magnitude according to the actual methods used. In the future, it will be increasingly necessary to demonstrate that not only is the oil-in-water content acceptable but also that the water is non toxic. This toxicity can arise from dissolved hydrocarbons, such as benzene, heavy metals and perhaps even radioactive elements.
Performance of Horizontal Wells, Safah Field, Oman
Authors: Chen Hsiu-Kuo
Published: December 2007

This paper reviews the performance of seven horizontal wells completed between October 1990 and February 1992 in the Safah field, the Sultanate of Oman. The horizontal well sections range from 1985 to 4718 ft. The well performance indicates that there is no direct correlation between initial well productivity index (PI) and length of the horizontal section. The long-term PI of the horizontal wells depends on the GOR of the well. The average PI of the horizontal wells is about 10 times that of the average vertical wells. It takes about one fifth of the time to produce a given production with a horizontal well. The excellent performance of the horizontal wells has increased oil production. The use of horizontal wells is expected to increase the overall recovery for the Safah field.
Stress Around A Wellbore
Authors: Deily F.H. , Owens T.C.
Published: December 2007

A study was made of the stress state in a porous elastic body, with particular emphasis on variations in selected failure criteria. The objective was to relate predicted changes in stress and failure criteria with fracture initiation experienced in certain forms of lost circulation, as opposed to hydraulic fracture extension. The three principal stresses at the wellbore were expressed as functions of wellbore pressure; in addition, values of eight additional parameters were varied over realistically expected ranges to determine their possible importance on the principal stresses. These eight parameters were the three tectonic stresses, formation fluid pressure, pore pressure at the wall, Poisson's pressure, pore pressure at the wall, Poisson's ratio, the ratio of unjacketed to jacketed rock compressibilities, and position around the wellbore. Two failure criteria, the maximum principal stress and Von Mises number, were determined for the well stress condition chosen. Calculated results show that small changes (5%) in tectonic stresses can cause larger changes in wellbore stress (and potential failure) than very large (100%) changes potential failure) than very large (100%) changes in Poisson's or compressibility ratios.

Introduction

A theoretical investigation of the state of stress around a wellbore was made to study the problem of fracture initiation in a porous elastic body. This work was undertaken to determine the effects of rock properties, tectonic stresses, wellbore pressure, formation pressure, and mud filter cake on lost pressure, and mud filter cake on lost circulation in a drilling well.

The mathematical model chosen for this investigation is a large porous body containing fluid at a particular pressure, P. The body has a cylindrical hole which contains fluid at a pressure, Pw. In addition, the porous body is acted upon by external stresses, Sx, Sy, and Sz (see Fig. 1). The quantities Sx, Sy and Sz are the tectonic stresses and are considered positive when tensile. In reality, these positive when tensile. In reality, these stresses are compressive (negative). The vertical tectonic stress, Sz, is due to the weight of all of the overburden. It is generally accepted that the principal horizontal tectonic stresses are not equal because of the preferred fracture orientation that is noted preferred fracture orientation that is noted in a specific area. The wellbore pressure, Pw, is equal to the sum of the hydrostatic Pw, is equal to the sum of the hydrostatic pressure of the column of drilling fluid and pressure of the column of drilling fluid and the annular pressure drop due to the circulating fluid.
An Alternative Method of Installing ESP's
Authors: Robison C. E. , Cox D. C.
Published: December 2007

Electric Submersible pumps (ESP's) traditionally have been installed on threaded pipe using workover rigs. More recently, however, three alternative methods for deploying ESP's have been presented. Two of these utilize a cable system and have been successfully demonstrated in the field. The third, overlooked until now, uses coiled tubing. Coiled tubing technology has continued to provide state-of-the art diversification in many areas of well-servicing technology, and the use of coiled tubing for ESP installations is a logical extension of these enhancements.

This paper contrasts coiled tubing ESP installation methods with cable-deployed methods.
Remarks on Exploration Tools: Integrated Exploration Strategy Being Applied to Carbonate Environments
Authors: Fischer Klaus , Holling Meinhard , Marschall Roland
Published: December 2007

Applying an integrated exploration strategy requires two basic steps: -Establishment of database, containing the given observations-Development of model data base

The model here is defined as a tool to aid in organizing the given observations, and contains interrelated subgroups of detailed submodels. These submodels may be facies trends, velocity models, maps resulting from global log-correlations etc. Therefore the development of the submodels comprises the following steps: -Global basin analysis (uplift/subsidence, basin history, hydrocarbon potential, migration paths, data and the resulting 3D stratigraphic model, which forms the basis tor a reservoir model.trapping etc.)-Structural interpretation/sequence analysis of the given seismic data (2D or 3D), integration of non seismicdata like gravity, magnetics-Classification of intervals, facies trends for selected intervals, mapping of additional tops etc (ABIC-code), application of geostatistics.-Refinementlextension of mapped interfaces-Final depthing using improved velocity functions-Application of modeling tools / special processing techniques to improve resolution/ verify interpretation

In this article we discuss some aspects of carbonate settings being evaluated along above guidelines, where the following items are investigated: -identification of build ups-mapping of shelf trends-application of special processing tools such as L1- decon, AVO-analysis etc.-verification of shelf trends in terms of lithofacies units, i.e., their individual impedance values, by fifinite-difference forward modeling (e.g., zero-offset application).-Derivation of final velocity model for time-depth conversion.

The final result of the seismostratigraphic work allows an evident increase of effectiveness in hydrocarbon evaluation and production due to the detailed knowledge of lithofacies trends, lateral and vertical as well as estimates of the permeability distribution, possible local permeability barriers and sealing potential. The chronostratigraphic information content of seismic sequence analysis allows in addition for an improved wellto-well correlation. This remark is especially valid for 3D data and the resulting 3D stratigraphic model, which forms the basis for a reservoir model.
Geologic Modelling for Reservoir Simulation: Hanifa Reservoir, Berri Field, Saudi Arabia
Authors: Kompanik G. S. , Heil R. J. , Al-Shammari Z. A. , Al-Shammery M. J.
Published: December 2007

A 3-D geologic model of the Hanifa reservoir was constructed using sequence stratigraphic principles and facies to control the distribution of porosity and permeability. The reservoir had been previously interpreted as having "layer cake" stratigraphy based on correlation of similar lithologies and similar appearing porosity inflections. The new geologic model incorporates a field-wide gamma ray correlation over 55 km from the non-reservoir rocks to the main producing area of the field. The gamma ray correlation produced a previously unrecognized reservoir geometry consisting of a high stand systems tract, a shelf (ramp) margin wedge, and a transgressive systems tract. This model represents our first 3-D geologic model based on sequence stratigraphy. This geologic model has been used successfully in reservoir simulation and field operations.

The reservoir consists of skeletal sands and stromatoporoid boundstone complexes to the north that grade to non-reservoir mudstones to the south. The reservoir was divided into 45 geologic layers. Core descriptions led to mapping facies distribution within each geologic layer. A 3-D lithofacies model was constructed and used as a template to calculate and assemble porosity and permeability models. A water-saturation model was also constructed based on facies specific J-functions. The geologic horizons were then grouped into 20 flow layers as the geologic front end into reservoir simulation.

The resulting geologic model has improved the Hanifa reservoir simulation by defining previously unrecognized reservoir geometries and providing the detailed resolution that enabled engineers and geologists to identify and understand the geologic attributes controlling fluid movement. The flood front has moved preferentially through grainstones in the highstand systems tract by crossing layer boundaries. Fluid flow has been impeded within layers that are dominated by bounds tones, wackestones or mudstones.
Upper Jurassic and Basal Cretaceous Outcrop Sequence Stratigraphy of Wadi Hagil, Ras Al Khaimah
Authors: Toland Christopher , Peebles R. G. , Walkden G. M.
Published: December 2007

The Wadi Hagil succession represents a well exposed, easily accessible reference section for the Upper Jurassic and basal Cretaceous of eastern Arabia. Due to its ’offlap break’ (platform margin) position, this locality provides a detailed record of relative sea level change and yields vital clues to understanding the sequence stratigraphy of the adjacent platform.

The measured section in Wadi Hagil comprises three disconformity-bounded depositional sequences.

Sequence 1 (?Oxfordian) commences with an abrupt disconformable flooding surface overlain by 16m of hummocky cross-stratified cortoid packstones (transgressive systems tract) and 88m of peloidal packstones and grainstones (highstand systems tract).

The base of Sequence 2 is marked by a prominent erosional hiatus (?Kimmeridgian-earliest Berriasian) and an abrupt change in depositional environment from shoreface to platform slope (attributed to platform margin collapse during the Late Tithonian). Sequence 2 is of intra-Berriasian age and comprises a basal conglomerate (transgressive systems tract) upto 5.5m thick, overlain by 29.5m of clinostratified calpionellid lime mudstones (highstand systems tract).

The base of Sequence 3 (latest Berriasian-Early Valanginian) is marked by a spectacular ravinement surface with at least 40m of associated downcutting. This is interpreted as a Type I sequence boundary corresponding to the 128.5Ma boundary of Haq et al (1988). The sequence boundary is overlain by 46m of megabreccias representing a submarine canyon fill (lowstand systems tract) and more than 30.5m of radiolarian lime mudstones and calciturbidites (transgressive systems tract).
Innovative Approaches to Downhole Corrosion Control
Authors: Esaklul K. A.
Published: December 2007

Corrosion control in oil & gas production has traditionally been accomplished through the use of corrosion inhibitors, coatings and materials selection.

Effective corrosion control is generally implemented in the design stage through rigorous evaluation of the anticipated operating conditions, and identifying the most cost effective and practical corrosion mitigation options. The process starts with application of predictive models, correlation to existing experience, and review of available technology; followed by laboratory testing under simulated field conditions.

This paper describes corrosion control philosophy, practices and innovative approaches applied to combat corrosion problems in operating fields. The approach shows how the dominating factors in corrosion of downhole tubulars are identified, and how predictive models are developed and applied to determine the extent of corrosion and predict tubing life. Success of sound corrosion mitigation relies on reliable and cost effective monitoring of corrosion. To that extent, new technologies are being implemented for the first time to monitor downhole corrosion. These new techniques are far superior to present techniques, and offer more reliable quantitative measurements than were previously attainable without pulling the tubing string.
Horizontal Well with Two Lateral Holes in Layered Limestone Reservoir: Performance and Test Interpretation
Authors: Mackay Alexander , Bustami S. S. , Jaber A. K. , Abdou M. K.
Published: December 2007

Horizontal drilling was under consideration for the development of the poorer reservoir quality northern area of a large onshore oil field in Abu Dhabi. This paper presents the case history of two horizontal holes drilled in a pilot well to help evaluate horizontal well performance for development planning purposes.

Geological and petrophysical data are described. The reservoir consists of layered limestone with porous layers alternating with continuous, thin, dense, stylolitic intervals.

An existing vertical well, with production test history from two completion intervals, was re-entered. The short radius technique was used to drill two horizontal holes into two porous layers, separated by several intervening dense and porous intervals.

Production test results, before and after horizontal drilling, are presented. For both horizontal holes, productivity was higher than the previous vertical completions. Vertical interference testing was also carried out, by monitoring the pressure in the lower hole while producing from the upper hole. Well test interpretation is discussed. Results of analysis, assuming a single homogenous layer, are described. The layered nature of the reservoir appears to affect transient pressure behavior. Numerical simulation, with local grid refinement around the horizontal holes, was also used to match the test results, including the vertical interference test observed pressures.
Horizontal Drilling and Completion Fluids Design Criteria
Authors: Ezzat A. M.
Published: December 2007

The main objective of horizontal drilling is to place a drain-hole within the pay zone for a long distance to enhance productivity or injectivity. In Saudi Arabia, horizontal wells have been successfully drilled through reservoirs with different characteristics such as tight to highly permeable limestone, extremely porous and permeable dolomite and dolometic limestone, and highly permeable unconsolidated sandstone. Based on laboratory test data, non-damaging fresh water and salt-saturated/polymer systems were selected for drilling the carbonate pay zones and a special oil-based fluid was developed for drilling the sand reservoirs. These drilling fluids satisfied the same basic functions common to all drilling muds and provided excellent reservoir protection. Production rates of the completed wells have reached several fold higher than the vertical producing wells from these reservoirs without stimulation treatments. This paper presents the laboratory data generated and discusses the fluids formulations and design criteria.