bluuebunny/crossref_metadata_2025_split huggingface dataset:
Removal of Asphalt Deposits by Cosolvent Squeeze: Mechanisms and Screening
Authors: Minssieux L. 
Published: December 2007

Abstract
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

Abstract
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

Abstract
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

Abstract
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

ABSTRACT
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

Abstract
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

Abstract
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

Abstract
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 (&gt; 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 (&gt; 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.
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