bluuebunny/crossref_metadata_2025 huggingface dataset:
Eliminate Formation Damage Caused By High Density Completion Fluid - Crude Oil Emulsion
Authors: Foxenberg William E , Ali Syed A. , Ke Minglie , Shelby David C. , Burman J. W. (Jack)
Published: December 2007

Recent research into clear brine completion fluid induced formation damage, focused on the compatibility of completion brines with formation crude oils(1). Foxenberg, et al., demonstrated that when added to completion fluids, surfactants can provide benefits such as emulsion prevention, surface tension reduction, and aiding flow back of fluid that has leaked off into the formation. They reported on the emulsification tendencies of certain Gulf of Mexico crude oils and high density completion fluids, including calcium chloride, calcium bromide and zinc bromide based brines. Although their work demonstrated a method to eliminate formation damage caused by emulsion, it necessitated disposal of the treated completion fluid. Disposal of the a 12.5 ppg CaCl2-CaBr2 brine was necessary because the fluid supplier was unable to remove the high concentration of solvent/surfactant required to provide crude oil-completion fluid compatibility. This ability to reclaim and recycle a ‘used’ fluid is an essential requirement if these relatively high dollar completion fluids are to be economically utilized.

This paper focuses on the development and application of surfactant based systems that eliminate formation damage caused by emulsification of crude oil and high density completion fluids. Laboratory procedures that ensure efficacy and penetration of the surfactant into the formation matrix are presented. A compatibility matrix of GOM crude oils and completion fluids is included. Field case histories are discussed, illustrating the benefits of specifically designed surfactant systems such as enhanced crude oil-completion fluid compatibility, ability to reclaim heavy brine by reducing the effective concentration of surfactant and diminished risk of environmental exposure by curtailing the amount of mutual solvent required to obtain fluid-fluid compatibility.
Removal of Asphalt Deposits by Cosolvent Squeeze: Mechanisms and Screening
Authors: Minssieux L.
Published: December 2007

The performance improvement of usual solvents for asphalt deposits was looked for in an effort to optimize the squeeze treatments of the formations damaged with asphaltenes. The approach adopted for increasing the solvent power for asphaltenes of solvents as xylene was to develop solvent mixtures with a polarity adjusted to the type of asphaltenes contained in the crude oil considered. For that purpose, the Hansen's theory was used as a guide in defining the composition of cosolvents suitable for asphaltenes. Besides, in order to increase solvency and to disperse asphaltenes, dope addition was used as a means to create hydrogen bonding with the heteroatoms present in the asphaltene chemical structure or to modify the intermolecular interactions involved in asphaltene aggregation. Four types of tests were associated in the screening of cosolvents. They were based on the physical chemical mechanisms deemed predominant in a squeeze operation, i.e. the solvency of asphaltenes, the ability to desorb the asphaltenes adsorbed onto minerals making up the reservoir-rock as well as the capacity to maintain them dispersed within the organic phase. Several cosolvents with a few percents current chemicals owning an alcohol or amine functional group in their molecule, are shown to exhibit the required properties versus either solid extracted asphaltenes or well deposits.

The final cosolvent efficiency was checked at reservoir temperature in squeeze experiments carried out in core samples. After a permeability damage occurred during asphaltenic crude oil flow, the remedial effects of squeezes of different cosolvents were evaluated. Several examples illustrate the improvement gained with the designed cosolvents and dopes in restoring part of the oil permeability and in reducing the in situ asphaltenes deposition accompanying oil flow through core samples.

P. 289
Scale Dissolver Application: Production Enhancement and Formation Damage Potential
Authors: Jordan M.M. , Graham G.M. , Sorbie K.S. , Matharu A. , Tomlins R. , Bunney J.
Published: December 2007

The application of sulphate scale dissolvers in the production tubing in North Sea fields has been carried out, with reported success, for many years in order to remove barium and mixed sulphate scale deposits from both the wellbore and from the near-wellbore formation. As well as having the capacity to dissolve mineral scales, these corrosive materials also have the potential to cause some degree of formation damage by the dissolution of reservoir minerals. In this study, three commercial scale dissolver formulations were tested using a range of laboratory procedures to assess (a) their comparative ability to dissolve barium sulphate; and (b) of more importance in the current study, their potential to cause formation damage in the near-wellbore formation. In addition to the commercial formulations, laboratory prepared amino carboxylic acid scale dissolvers (EDTA and DTPA) were also examined. The potential formation damage capacity of the various scale dissolvers has been assessed by measuring the levels of cation release in static tests on mineral separates and also by studying the various effluent profiles from dissolver core flooding studies on reservoir sand. The potential damage mechanisms include silicate dissolution, fines generation/migration, emulsion formation/stabilization and mechanical strength reduction. We conclude that, when testing sulphate scale dissolvers for field application, their formation damage potential should be assessed as well as their barite dissolution performance.

P. 303
A Stimulation Treatment and Evaluation of a Gravel Packed Well; A Case Study From the Statfjord Field
Authors: Boreng Raymond , Vikane Olav , Hagen Thomas , Sorhaug Eyvind
Published: December 2007

A STIMULATION TREATMENT AND EVALUATION OF A GRAVEL PACKED WELL; A CASE STUDY FROM THE STATFORD FIELD

Several wells in the Statfjord field are restricted from producing at their maximum potential due to sand production. To optimize production different sand control techniques have been implemented.

Gravel packed wells have contributed significantly to maintain production capacity. Typical production increase after gravel-packing has been 2 – 4000 Sm3/d. However, rapid plugging problems have been experienced after water breakthrough. Extensive scale dissolver and scale inhibitor treatments have been performed with varying success.

Plugging problems experienced in the gravel packed wells are difficult to predict and overcome, In order to improve the productivity of the well and to establish a better understanding of the damage mechanisms, it was decided to perform a scale dissolver treatment and evaluate the stimulation effect by the use of a production logging tool (PLT).

Well C-32, having a 55.5 m cased hole gravel packed interval was selected. The well was stimulated by a 2% KCl treatment prior to water breakthrough and treated by a scale dissolver and inhibitor shortly after water breakthrough. Production logging performed after installation of the gravel pack in November 1991 gave a basis for comparison,

The evaluation of the data has shown that the plugging process is complex and difficult to interpret. We can conclude, however, that injection of fluids has improved the gravel pack productivity. The erosion potential has also been minimized due to reduced draw down across the gravel pack.

The plugging mechanism is most likely a combination of scale and fines plugging the wire wrapped screens and the poorly filled perforation tunnels.

The first stimulation operation had a payback time of 3 days and the second operation including production logging had a pay back time of 17 days.

P. 313
Performance Evaluation of Extreme Overbalanced Perforating
Authors: Ghalambor A. , Asadi M. , Azari M.
Published: December 2007

A numerical technique based on the finite element method is developed to simulate the process and the ensuing effect of an e:ctreme overbalanced perforating technique. The model first considers a point pressure effect as a result of the conventional jet perforating on a selected formation, and second, a time step pressure effect on the inner surface area of the perforation, as a result of the extreme overbalanced process. The extreme overbalanced perforating technique in addition to the perforation tunnel creates micro-fractures normal to the perforation tunnels. Although these micro- fractures are not uniform in length and size, they are uniform in orientation and are extended radially and away from the shot center. Most of these microfractures, to a profound extend, exceed the crushed zone thickness formed during the jet perforating process. The conductivity of these micro- fractures, however, overcomes the effect of crushed zone in reducing the porosity of the formation and hence productivity of wellbore. Through this simulation, flow rates are calculated to compare the net production rate of this process to that of a conventional completion perforating at various formation permeability. The contribution of micro-fractures to flow by the model is presented. According to the result extreme overbalanced perforating increases the productivity of low permeability formation more than a high permeability formation.

P. 393
Guidelines for Selection of Fluid Loss Control Methods Before and After Sand Control Treatments to Maximize Well Productivity and Cost-Effectiveness
Authors: Parlar M. , Ali S. A. , Price-Smith C. , Palthe P. , Chang F. F. , Ladva H. , Patel D.
Published: December 2007

The loss of completion and workover fluids into productive zones is a major concern particularly in high-permeability, unconsolidated sandstone formations where sand control is most typically required. Selection of the fluid density to balance the formation pressure is often based on an educated guess through previous experience in nearby or offset wells. Where overpressured formations are expected, balancing the formation pressure requires heavy brines, the loss of which into the formation can be quite costly when reservoir pressure is grossly overestimated. In underpressured formations, overbalance can be as high as several thousand psi even with very low-salinity brines, and maintaining a fluid level in the wellbore becomes extremely problematic. Long horizontal open holes present a formidable challenge for fluid loss control since cleanup of filter cake throughout the hole length using external breakers can be very difficult.

In this paper, we review the currently available mechanical and chemical options for fluid loss control, and discuss the limitations of each method. Based on laboratory data and considering practicality in field applications, we offer guidelines for selection of fluid loss control method and/or material in order to maximize productivity. The guidelines are given for two general categories: Before Sand Control (e.g., after perforating with two-trip methods in cased-holes) and After Sand Control (either two-trip or single-trip). The mechanical options discussed include isolation and flapper valves, as well as a single-trip perforating and gravel packing method that eliminates the use of fluid loss control (FLC) pills and multi-functioning isolation systems. Chemical options include crosslinked HEC systems without particulates, and soluble particles in various carrier fluids. The particles may be soluble in water (sized salt), in acid (CaCO3), or in oil (oil-soluble resins).
Polymer Loss in Filter Cakes
Authors: Przepasniak A.M. , Clark P.E.
Published: December 2007

A.M. Przepasniak, Department of Chemical Engineering, The University of Alabama, and P.E. Clark, Department of Chemical Engineering, The University of Alabama

Formation damage by polymers used in drilling, workover, and completion fluids can be a significant problem. In many of the processes that occur in the oilfield, fluid-loss agents are added to the fluids to minimize the loss of polymer containing fluid to the formation. It is well known that certain polymers will filter out on the formation face while other polymers freely enter the matrix. Some polymers will filter in low permeability rock while flowing freely in high permeability rock. This leads to the question of polymer filtration in fluid-loss agent and drilled solids filter cakes.

Hydroxyethyl cellulose (HEC) and xanthan gum were the two polymers used in this study. Both of these fluids find wide application in drilling, completion, and workover fluids. Initial studies were carried out with polymer concentrations of one and two pound per barrel (0.29 and 0.57% by weight respectively). Bentonite, rev dust, and calcium carbonate were used in the concentration range of one to twenty pounds per barrel (0.29 to 5.8% by weight) for the filter cake material. Two different experimental protocols were used in the study. The first experimental protocol consisted of slurrying the solid material in brine, filtering a known amount of the slurry, flowing a clear brine through to establish the permeability, and then flowing a known amount of polymer solution through. The polymer solution effluent from the cell was collected in three different segments. The rheology of each segment was then compared to the rheology of the initial polymer solution. The second protocol consisted of slurrying the solid material directly into the polymer solution and filtering the slurry in the filter press cell. Again, samples were taken and the rheology compared with the rheology of the initial polymer solution.

P. 401
Distribution of Mud Induced Damage Around Horizontal Wellbores
Authors: Thomas Bimal , Sharma Mukul M.
Published: December 2007

This paper presents the results of an experimental study on the extent, depth, and distribution of mud induced formation damage around a horizontal wellbore. This investigation aims at addressing the question of how much damage is caused in the bottom, middle, and upper portions of the heel and toe when a horizontal well is drilled.

Our simulated borehole consists of a 5" diameter pipe rotating inside a 7" diameter pipe. Three core holders are placed at the top, middle and bottom of the simulated borehole. The fluid loss rate and the permeability of 4 different sections of the core are measured as mud is circulated in the annulus and the inside pipe is rotated. The formation damage and the fluid loss data for the top, middle and bottom of the wellbore are measured for different drill-in fluids, axial velocities and pipe rotation rates.

It is found that when the drill pipe is concentric the fluid loss rate is symmetrical and independent of axial fluid velocity and rotational speed of drill pipe, over the range of rpms and velocities studied. For eccentric annuli (as might be expected in horizontal wellbores) the extent of damage and fluid loss vary azimuthally with the most damage occurring in the bottom portion of the hole. The extent and depth of damage are related to the speed of drill pipe rotation and the time of exposure to the mud. Erosion of the mud cake at the bottom of the hole plays an important role in the distribution of formation damage around the hole. Both the drill-in fluids tested, sized calcium carbonate and sized salt, were found to be relatively non-damaging. However, the presence of drill solids in the mud induces significant damage.

P. 441
Conventional High Rate Well Completions: Limitations of Frac&Pack, High Rate Water Pack and Open Hole Gravel Pack Completions
Authors: Welling Rudy W. F.
Published: December 2007

New Deep Water completions in the Gulf of Mexico (GOM) are expected to produce over 20,000 bpd or more than 100 MMscf/d from reservoirs less than 200 ft thick. At these high flow rates (100 bpd/ft, 500 Mscf/d/ft) turbulence in the gravel filled perforations starts to play a significant role. This study attempts to assess which type of completion is most suited for these high rate wells. Frac&Pack (F&P) completions are compared with High Rate Water Packs (HRWP) and Open Hole Gravel Packs (OHGP). Both Oil wells and Gas wells are analyzed.

The concept that, in cased hole gravel packed completions, the main source of damage is in the perforation tunnels (casing and cement sheath) has been used to build inflow models for each completion type. These models use standard inflow equations for radial flow in the reservoir and linear flow in the perforation tunnel. This inflow model was matched to field data for HRWP and F&P completions by changing the effective number of perforations flowing as well as the average gravel permeability in these perforations. For OHGP completions no detailed field data was available and general completion assumptions were used as inputs to estimate the inflow performance.

Results generated from these field calibrated models, in the predictive mode, show that for high rate gas wells (> 500 Mscf/d per ft of perforations), where the high pressure drops in the perforation tunnel dominates the inflow, the benefits of fracturing the formation diminishes for reservoirs with permeabilities greater than 150 mD. Above 150 mD. a HRWP become more efficient than a F&P. At reservoir permeabilities above 600 mD OHGP's however may become more efficient.

In high rate oil wells (> 100 bpd/ft perfs) the total pressure drop is not so much dominated by the perforation tunnel. Hence the benefits of fracturing the formation continue to a permeability of 900 mD before OHGP becomes more efficient.

The field matches suggest that F&P completions in general only have 0.7 to 2.3 shots per foot (spf) flowing with an average gravel permeability of no more than 17 Darcy. For HRWP it is found that more perforations are flowing (5 spf) and that the average gravel permeability is still high (13.6 Darcy).
Water Quality Requirements and Restoring the Injectivity of Waste Water Disposal Wells
Authors: Nasr-El-Din H.A. , Al-Taq A.A.
Published: December 2007

Water Quality Requirements and Restoring Wells the Injectivity of Waste Water Disposal

Water separated in desalters and other separation units in a gas-oil separation plant contained variable amounts of oil contaminant, suspended solids and chemicals. Two nearby wells are used to dispose the produced water from the plant. Due to the poor quality of the waste water and long shut-in period, one of the two wells encountered a significant drop in well injectivity.

A thorough investigation was conducted to identify the damaging mechanism, design a treatment program to restore the well injectivity, and recommend guidelines for water quality needed to minimize formation damage. The study included characterization of the waste water, and conducting coreflood experiments to determine the effects of total suspended solids, oil content, particle size, H2S and iron content on the permeability of reservoir cores (sandstone formation). Finally, coreflood experiments were performed to determine an acid formulation which can be used to remove formation damage while maintaining the integrity of the formation (sandstone).

Experimental results indicated that the waste water contained significant amounts of suspended solids (mainly iron sulfide) and oil (up to 250 mg/l). Coarse particles of more than 500 microns were present in the waste water. Coreflood results indicated that the waste water severely damaged reservoir cores. Formation of an external filter cake was the damaging mechanism observed in all coreflood experiments. Iron sulfide played an important role in the damage observed in the lab and field studies. The following water quality requirements were recommended to minimize loss of injectivity total suspended material (solids and oil) should not exceed 50 ppm, mean particle size should not exceed 4 microns, hydrogen sulfide concentration should not exceed 10 ppm, and total iron concentration should not exceed 2 ppm. Also, to prevent formation damage due to particle settling, it was recommended to continuously inject the waste water into the two disposal wells. Shutting in disposal wells for a long period of time will allow most of the particulate material to settle in the pore spaces, which will cause formation damage and loss of injectivity.

To restore the injectivity of the damaged well, an acid formulation was designed which took into account formation mineralogy, presence of trapped oil, precipitation of iron, and elemental sulfur. The treatment was applied in the field where the acid was injected using a 1.5" coiled tubing. Ball sealers were added to the acid to ensure better diversion. The treatment was successful, and the well injectivity increased by more than 400%.

P. 565
The Application of Pre-Stack Depth Migration using Topographic Analysis to Aid in the
Authors: Oates N.K. , Harinder P. , Willacy C.
Published: December 2007

The PY3 oil field lies in the Cauvery Basin situated some 10km off the east coast of India in the region of Pondicherry. Historically it has been difficult to define an accurate depth model, which has lead to problems with well prognoses and reserve estimations. The difficulties in depth conversion are the result of rapidly varying overburden stratigraphy due to the field being located beneath a series of stacked shelf edge sequences. This phenomenon causes rapid and unpredictable lateral velocity changes and leads to the situation where time lows convert to depth highs. Numerous depth conversion techniques have been applied ranging from traditional V0, k layer cake interval methods to stacking velocity based procedures. These methods can generate significant depth differences particularly those incorporating stacking velocity information.

As a consequence Pre-Stack Depth Migration was carried out on a number of trial lines in order to derive accurate modeled velocities which were then compared with the original stacking velocity field.

The methodology applied consists of generating initial velocity models using travel time tomography. Travel times are picked pre-stack and are compared with modeled travel times. A least squares inversion technique is used to minimize the error between the picked and modeled travel times by adjusting velocities and depths. This technique is especially suitable for detecting velocity variations that have higher spatial frequencies than the cable length.

After the initial interval velocity depth model is generated using tomography the data is depth migrated. The depth gathers are further analyzed for model completeness and accuracy.

This type of depth model yields a better seismic image but is still prone to depth errors caused by velocity anisotropy. The improved seismic profiles enabled greater definition of the key Tertiary section which gives rise to the rapid lateral velocity variations and also of the reservoir interval itself. The application of the velocity data derived from this process has resulted in a significant reduction in the error margin relating to both the depth model and reserve estimation for the field. The results of this study will also have a considerable influence on the siting of future producer and injector wells.

P. 49
Spectral Enhancement of Seismic Data Using Modified Nelson-Mitchell Algorithm
Authors: Hebbare Suryaprakash Rao , Vaddadi Subba Rao
Published: December 2007

Frequency spectrum of the recorded seismic trace (2 ms S.I.) has a band width of 4–250 Hz. However, the restriction of the recording devices and the received seismic signal impose a limitation of effective band width to 10-(0) Hz only.

A method for spectral enhancement of seismic data (from 10–60Hz to 10–125Hz) around a wellbore close to seismic line is proposed based on sonic and density logs by employing Modified NM- Algorithm and Matching Filter. It is applied to windows of size about 400 ms by 200 CDPs along two seismic lines situated in different geological setups.

Spectrally enhanced seismic data shows finer events in comparison to normal seismic data and has thin bed resolution capability However, geological validity of events is yet to be understood.

P. 689
Sedimentation, Diagenesis of the Bank and Their Control to Gas Pools in 2-Section of Jialingjiang Group in Eastern Sichuan
Authors: Wei Zeng , Ping Qiang , Xu Jianbin
Published: December 2007

The formation of gas pools in 2-section of Jialingijang group in EasternSichuan is not controlled by tectonic traps, but controlled by sedimentation and diagenesis of the bank. Bank-microfacies is the base of gas pools and favorable diagenesis is the necessary condition for the formation of reservoir. Combination of sedimentation and diagenesis can form favorablesource-reservoir-seal assemblage, high porous section and valuablesedimentary-diagenetic traps. The composition model, facies sequence model and diagenetic sequence model of the bank are put forward. The distributing rule of the bank has been analyzed. The shallowing exposed bank with diagenetic sequence B is the full and necessary condition for the formation of gas pools. Accordingly, this theory is important to the exploration of gas pools inEastern Sichuan.

p. 69
Choosing the Right Synthetic-Based Drilling Fluids: Drilling Performance Versus
Authors: Patel Arvind D.
Published: December 2007

Environmental issues have created ever-moving targets for drilling fluids, or muds. Environmental regulations are diverse, complex, and have a tremendous impact on drilling operations, economically as well as logistically. In order to successfslly meet these regulatory constraints, synthetic-based muds are beconiing increasingly popular as substitutes for conventional oil- based muds. Continual evolution of synthetic-based muds (SBM's) and the increasing diversity of synthetic base fluids (SBF's) have made the selection of environmentally acceptable synthetic fluids increasingly complex requiring knowledge of chemical composition and structure effects on toxicity, biodegradability, and performance.

Examination of the SBF's, the synthetic base fluids, provides insight into the environmental and performance issues that affect the selection and drilling performance of the SBM's, the mud. The toxicity, biodegradability, and bioaccumulation of SBM's depend on the molecular composition and structure of the base fluid. In general, the degree of branching affects the biodegradability and the molecular weight affects the toxicity of synthetics derived from similar chemistry. The thermal stability and performance characteristics of the SBM's depend on the chemical composition of the base fluid and emulsifiers used in the SBM's. The final choice of the SBF (and thereby the SBM) depends on the application and environmental requirements for a particular area; however, synthetic hydrocarbon-based fluids have shown to be overall best in cost vs performance.

P. 95
Multilaterals: An Overview and Issues Involved in Adopting This Technology
Authors: Vij S.K. , Narasaiah S.L. , Walia Anup , Singh Gyan
Published: December 2007

Multilaterals, an upcoming technology, offers the potential for substantial improvement in well economics. Integrated efforts of service companies and operators have made this upcoming technology a viable completion technique. The issues like maturing reservoirs, many of the existing wells with uneconomical- to-recover results in place and increasingly expensive offshore structure and drilling operations, are addressed in a very positive way by recent advances in the ML Technology. This technology allows to have same magnitude of reservoir exposure with lesser number of wells on surface platform. Also, there is a potential for reducing water-gas Coning and improved recovery of oil.

Overview of multilateral technology, its applications and limitations have been covered in the paper. Being comparatively a new technology, higher costs and risks involved during drilling/ completion/servicing would need to be kept in view while deciding to go in for multilaterals.

Modelling of multilaterals may be complex for particular configurations, because of likely interplay between reservoir performance and friction losses and pressure continuity in the well bore. Special simulation packages (coupling fluid flow in the reservoir and laterals) may be required for the purpose. Studies so far undertaken in the industry on this issue have been discussed.

Multilateral system offered by various service companies, from existing and new wells, have been discussed, covering issues like isolation between laterals, flow control, re-entry access/interventions, dual string completions. Worldwide experience on economics of multilaterals has also been covered.

Reservoir screening criteria provided in the paper may be used as guidelines for selecting reservoirs for possible applications of multilateral technology. Multi-disciplinary approach would be required for effective implementation of this technology.

P. 109
Use, Quantification and Learnings From a Vertical Pulse Test Conducted for Barrier
Authors: Kikani Jitendra , Jasek D.E. , Mathis L.S.
Published: December 2007

A vertical pulse test was conducted in a water injector in the Goldsmith San Andres Unit (GSAU) in West Texas for determining the integrity of a low permeability barrier separating two carbonate facies. This test was conducted as part of a CO2 pilot project. The effective vertical sweep efficiency is controlled by the barrier and is important to quantify.

The pulse test design was tempered by tailing it with a standard interference sequence to mitigate unforeseen situations. This proved useful as the reservoir pressure was lower than anticipated and the well went on vacuum. The data was interpreted using conventional techniques and numerical modeling. The numerical model was tuned to provide transient quality results by comparing against standard analytical solutions before using it to interpret the pulse test.

This paper presents the conduct, analysis and interpretation of the vertical pulse test and discusses some of the learnings. Sensitivity analysis was performed on slab, layercake and geostatistical models for the flooding pattern, to understand the influence of small scale heterogeneity on short tests. The results indicate that one can distinguish between a casing leak and reservoir vertical communication from a pulse test. The vertical permeability governs the peak arrival and magnitude of the pulses whereas the horizontal permeability controls the magnitude and shape of the fall off portions of the test.

P. 155
A Comprehensive Reservoir/Wellbore Model for Horizontal Wells
Authors: Penmatcha V.R. , Aziz K.
Published: December 2007

Comprehensive, three-dimensional, anisotropic and transient, reservoir/wellbore coupling models are developed for infinite-conductivity and infinite-conductivity wellbores to calculate the productivity of a horizontal well placed in a box-shaped drainage volume. The finite-conductivity well model considers frictional and accelerational pressure drops in the wellbore. It also takes into account the effects of fluid inflow into the well. These models are semianalytical in nature and can be used under transient or pseudosteady state flow conditions. The infinite-conductivity well model is compared with the uniform flux model to show the differences in well productivity calculations. The effects of wellbore pressure drop on well productivity are shown using the finite-conductivity well model. These models can provide reference solutions to calculate well indices or to check the accuracy of a numerical simulator. Because of their analytical nature they are easier and faster to use than numerical simulators. Using superposition in space and time, these models can be run under a variety of constraints. We believe that our finite-conductivity well model is more general than any published previously.

P. 191
Interval Pressure Transient Testing with MDT Packer-Probe Module in Horizontal
Authors: Kuchuk Fikri J.
Published: December 2007

In this paper, the use of various pressure measurements is investigated for determining formation pressure as well as permeability distribution by using the Multiprobe Formation Tester Packer and Probe Modules in horizontal wells. It is shown that reservoir pressure measurements along the wellbore give local as well as reservoir scale information about how the reservoir is being depleted and how cleanup takes place. The estimation of horizontal and vertical permeabilities. skin, and reservoir pressure along the wellbore is also presented by using interval (local) pressure transient tests. For the Multiprobe Formation Packer and Probe Modules in horizontal wells, an interpretation methodology is presented for determining the reservoir parameters. A few interval pressure transient test examples are presented for both formation pressure and permeability distribution.

P. 205
A Study of Pressure Behavior of Dual-porosity Composite Reservoir with Non-uniform
Authors: Xiang Kaili , Guo Jianchun , Kun Wang
Published: December 2007

The theories and models of well testing analysis of dual porosity reservoirs with uniform thickness have been discussed in detail in the literature. In order to completely describe the situations of real reservoirs, this paper first studies the pressure behavior of dual-porosity composite reservoirs with non-uniform thickness and lateral heterogeneity. In this paper, the dual-porosity composite reservoir with non-uniform thickness and lateral heterogeneity is defined as the dual-porosity reservoir that consists of many zones with non-uniform thickness, different fluid and formation properties. A new effective radius mathematical model of this composite reservoir in the presence. of skin, wellbore storage and phase redistribution is presented. Laplace-space solutions for this mathematical model with outer constant pressure boundary or outer impermeable boundary are obtained by Laplace transformation and the typical curves for the modern welltesting analysis are given by numerically inverting method. The mathematical model has improved the welltesting analysis theories and the pressure behavior of this reservoir is discussed. The model and solution can be used in the fractured reservoir with variable formation properties or containing water injection wells, gas injection wells, polymer injection wells or finite damaged zone.

P. 235
Inter-relationships between Polymer/Crosslinker Chemistry and Performance in
Authors: Moorhouse Ralph , Harry David N. , Matthews Les , Merchant Uday
Published: December 2007

Fracturing fluid systems based on the natural polymer guar, or its derivatives, crosslinked with boron or certain transition metals, such as zirconium, have become the staples of the pumping services industry worldwide. It has been estimated that in North America alone, one billion gallons of fracturing fluid were pumped in 1997. These fluid systems have been designed to operate over a wide pH range and at temperatures to 400F (about 200C) by the appropriate choice of polymer crosslinker, stabilizer and buffer. Not only has it become apparent that the same fracturing fluid composition is not suitable over such a wide range of applications, but it is also becoming increasingly apparent that seemingly identical fluid compositions yield different results.

This paper is the result of a systematic effort to demonstrate some of the reasons why seemingly identical fracturing fluid compositions may produce considerably different results, and the steps that may be taken to minimize the odds of making an undesirable choice.

P. 253
Amenability of Eocene Crude to Thermal Conditioning and Chemical Treatment for
Authors: Nihalani M.C. , Sinha S. , Dubey H. , Kulkarni T.G.
Published: December 2007

Laboratory studies have been carried out to assess the comparative effectiveness of chemical treatment and thermal conditioning on the crude oil being produced from Eocene formations by Oil India Limited (OIL) in the upper Assam region of India. The studies have indicated that the present Eocene crude is amenable to both thermal conditioning and chemical treatment, and combination thereof. The study has shown that he thermal conditioning of crude has distinct advantage over chemical treatment in terms of improvement in rheological parameters, reduction in pour point and remarkable reduction in depositional characteristics. However, the thermally conditioned Eocene crude has shown some ageing effect, and has poor thermal stability.

P. 271
Combating Hazardous Sludge Disposal Problem at Lakwa (India) Oil Field Effluent
Authors: Sengupta P. , Dutta D.K. , Goswamee R.L. , Saikia P.C. , Borthakur P.C.
Published: December 2007

The effluent treatment plant (ETP) at Lakwa oil field (India), generate huge amount of sludge containing about 7–10 % hydrocarbon. Disposal of the sludge with the high hydrocarbon content is of environmental concern. The possibility of combating the problem through total utilization of the sludge in making building brick and light weight aggregate has been investigated. This communication highlights the result of preliminary investigation. Common masonry brick and light weight aggregate with acceptable physical and chemical properties could be prepared using about 34 % as received sludge.

P. 279
Removal of Downhole Strontium Sulphate Scales By Chemical Dispersion Technique
Authors: Maithani A.P. , Sah A.K. , Rai Ramashish , Singh Gyan
Published: December 2007

Scaling is a major problem in any oil field. Calcite or Calcium Carbonate (CaCO3) and Celesite or Strontium Sulphate (SrSO4) are the common type of scales encountered in oil field operations. various fluids (e.g. Brine, liquid and gaseous hydrocarbons and other gases) mix in the reservoir and/or wellbore under varying thermodynamic, kinetic and hydrodynamic conditions resulting into scale formation. While CaCO3 scales are possible to be removed by the use of common acids, Strontium and Barium Sulphate require special formulations to remove.

Laboratory investigations for characterization of scales recovered from a well of Bombay High and their removal from down hole equipment and wellbore by chemical treatment have been carried out.

Produced water and injected water has been analyzed for ionic composition to monitor scale formation tendencies. The possibility of formation of Strontium Sulphate (SrSO4) scales in wellbore and tubing is well established from these analysis. Further, the well production decline in some of the wells were analyzed and corroborated with formation of scale which were later confirmed during workover.

The dissolution of Strontium Sulphate scales with special chemicals / formulations have been upto 75% under laboratory conditions, whereas other conventional solvents/chemicals were not effective for dissolution.

Accordingly squeeze treatment with chemicals for scale removal from formation face, perforations and down hole equipment's was recommended. These treatments has been carried out in some wells and results have been very rewarding.

This paper presents the results of these evaluations and field applications of scale treatment.

P. 285
Pipeline Transportation of Heavy/Viscous Crude Oil as Water Continuous Emulsion in
Authors: Sharma Kuldip , Saxena V. K. , Kumar Avinish , Ghildiyal H.C. , Anuradha A. , Sharma N.D. , Sharma B.K. , Dinesh R.S.
Published: December 2007

The heavy oil belt of North Cambay Basin comprising of Santhal, Lanwa and Balol oil fields poses great problems in floatation of these heavy oils due to high viscosity (10,000–16,000 cps) of the emulsion. Oil-in-water emulsions provide a cost effective alternative to the heated pipelines or diluents for their transportation. Emulsions in different phase ratios and application doses of 2000–5000 ppm of non-ionic surfactants have been found to be effective in phase reversal of emulsions with drastic reduction in viscosities which are in 100–400 cps range at pipeline operating conditions. Non-ionic surfactants have the advantage of relative insensitivity to the salt content of the aqeous phase. The non-ionic family of surfactants has been used successfully for the formation of stable emulsions that resist inversion to a wide operating temperature range. Resulting reverse emulsions are heat sensitive and resolve themselves at elevated temperatures without addition of dehydration chemicals. Suggested surfactant treatment has the potential to successfully transport heavy/viscous emulsions of Lanwa oilfield resulting in tremendous savings in transportation costs.

P. 301
A Model to Quantify Residual Saturation Distribution in Heterogeneous Reservoirs
Authors: Virnovsky G.A. , Skjaeveland S.M. , Skauge A. , Helset H.M.
Published: December 2007

To study capillary trapping phenomena in 2 and 3D a mathematical model is developed facilitating rapid fine grid computation of the saturation fields in heterogeneous reservoirs. The reduction in Computation time is achieved due to the fact that the model is much simpler than a conventional black oil simulator. Influence of wettability type, magnitude of capillary pressure, rate, and gravity forces are studied in 2D and 3D analytically (qualitatively) and by way of computations (quantitatively). It is shown that at infinite time in the strongly water wet reservoirs all the mobile oil is recovered, while in the oil-wet and mixed reservoirs a certain amount of capillary trapped oil exists. The capillary trapped oil saturation has a tendency to increase in the direction from injection to production wells, though it reveals a non-monotonous behavior locally.

The developed model is useful in calculation of recoverable reserves, and in optimization of waterflooding strategy to minimize remaining oil in heterogeneous reservoirs including the fractured ones.

P. 307
Perforation-Specific Inflow Fluid Characterization with Downhole Video
Authors: Maddox Steve
Published: December 2007

It is useful to confidently know what type of fluid is coming into the wellbore from each specific perforation and to accurately establish the depth associated with that fluid entry. The more confidence you are able to assign to your knowledge of the fluid type entering a specific perforation, the more valuable that information is to the engineer trying to maximize oil or gas production and trying to minimize water production. Knowing if the fluid entering a specific perforation is gas, oil, or water and establishing the exact depth of that perforation relative to other downhole equipment is possible using downhole video technology.

After a brief overview of the development and current state of the art of downhole video technology, this paper presents some examples of perforation-specific fluid characterization. These examples include analysis of flow patterns at specific perforations actually observed and the factors that contribute to those patterns. Examples include videos of oil, gas, and water entry at various depths, pressures, temperatures, watercut percentages, inclination angles, and tubular sizes.
Fresh Sonic Interpretation in Limestone Through Modulus Decomposition
Authors: Saxena Vimal
Published: December 2007

The conventional acoustic interpretation in porous formations often utilizes Pickett's plots for lithology calibration, variations in sonic velocities for porosity estimates and relative shifts in V,/Vs ratios for hydrocarbon evaluation. In practice, it alone does not provide satisfactory answers as true formations are composite media. In limestone, additional heterogeneities are observed in porosity type and its distribution created as diagenetic imprints on the formation. A variable degree of dolomatization is also found in carbonates. The advent of recent success in modulus decomposition of sonic velocities or hydrocarbon evaluation in silici-clastic composite porous rocks influences to implement decomposition technique in carbonates by addressing the problem as multi-constituent media. It provides a new resistivity independent exciting approach for petrophysical understanding in limestone formations, which should be reviewed in comparison with conventional results.

Modulus decomposition combines both the sonic velocities in a multi-constituent model to account for dolomite and fluid influences and provides the evaluation of an effective' dry frame bulk modulus, under known fluid conditions and vice-versa. The study of evaluated bulk and shear dry properties show the presence of an excellent inter-relationship. Extending it to unknown fluid conditions, provides a resistivity independent indication of hydrocarbon in carbonates. It also allows to compute the effective fluid modulus ill pores to estimate hydrocarbon saturation through a mixing law. The study observes the presence of a strong Semi- logarithmic relationship between shear modulus and formation porosity. The relationship is found to be limited by a terminal' porosity. The general relationship holds good in all the studied limestone.

P. 339
An Experimental Study for Oil Identification in Very Fresh Water (Salinity<10000PPM)
Authors: Sun Deming , Li Lijun
Published: December 2007

The oil identification of pay zone in very fresh waterbearing reservoir in China is hard problem to be solved by logging analyst. This is because the difference of resisitivity between oil and water zone in this kind of reservoir is relatively small. For this, logging analysts have been trying to find non-electric logging methods to solve the problem. Many methods have been found. The dynamic Poisson's ratio obtained from acoustic log is one of those. However, as we have known, the dynamic Poisson's ratio is useful for oil identification in high salinity- bearing sand. But, the mechanism of oil identification in very low salinity water- bearing sand is uncertain because interval transit time of the rock has a relation to the formation water salinity. In order to solve the above problem, an experimental study has been carried out with natural cores in Lab. under the reservoir conditions. The results of the experiment show that the Ave. values of dynamic Poisson's ratio are about 0.3 and 0.25 respectively for the cores saturated with fresh water and natural oil. Those also show that it is possible to identify the oil using dynamic Poisson's ratio even in very low salinity water- bearing sand.

P. 379
A Novel Streamtube Model For Tracer Flow In An Areally Heterogeneous Reservoir
Authors: Marathe R.V.
Published: December 2007

A new method is proposed to obtain streamline distribution in an irregularly shaped reservoir with an arbitrary placement of injection and production wells and randomly oriented sealing faults, Using streamline distribution thus obtained, it is possible to predict tracer breakthrough times.

The proposed method models flow around a permeability barrier by a distribution of vortices around the barrier plane obeying the appropriate boundary conditions of vanishing normal velocity component along the barrier plane and the overall boundary condition of no flow or uniform potential along the reservoir boundaries. In addition, the requirement that net circulation around the permeability barrier be zero is also satisfied. Flow around a vortex is modeled by the arc-tan solution to the Laplace equation, while flow towards vertical well is modeled by conventional infinite line source (log r) solution. In thin reservoirs, flow towards horizontal producers/injectors is modeled by Infinite Conductivity Vertical Fracture (ICVF) solution to the Laplace equation. Specific advantages of the model based on steady state potential flow theory over full fledged numerical simulation model are:it is free from numerical dispersion and grid orientation effectsflow geometry near wells and permeability barrier is taken care of naturally in the model andit is easy to use.

P. 423
Investigation of Hydrocarbon Miscible Gas Injection by Experimental and Modelling
Authors: Javadpour F.G. , Jamialahmadi M. , Shadizadeh S.R.
Published: December 2007

The present investigation reports the results of extensive experimental and theoretical work to determine the minimum miscibility pressure of a mixture of hydrocarbon gas and eight Iranian crude oils. The measured minimum miscibility pressure values were modeled with a fully compositional simulator. The results show that the available gases alone or with some enrichment can develop miscibility process with crude oils at reservoir condition. At the end a new empirical correlation presented which can predict the minimum miscibility pressure (MMP)with acceptable error.

P. 447