bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field-Testing a Compact Multiphase Flow Meter - Offshore Saudi Arabia
Authors: Warren P. B. , Al-Dusari K. H. , Zabihi M. , Al-Abduljabbar J. M. 
Published: December 2007

Abstract
An automated and compact multiphase flow meter (MPFM) tested offshore Saudi Arabia has accurately measured three-phase flow rates under existing field operating flow conditions. A three-month field test was conducted utilizing over 160 well tests under varying operating conditions. A meter was installed on an offshore test barge, so that individual wells could be tested in series with traditional test separator methods. For these trial tests, the total liquid rate ranged from about 335 to 12, 333 barrels per day, the GOR ranged from about 67-185 SCF/STB and the water cut ranged from 0 to 70%. The results show that over 93% of the well tests were within +/- 10% of test barge results for all liquid, oil and water cut measurements. While gas measurements were determined to be within +/- 15% in 63% of the wells tests. Also, the results for the gas measurement comparison are discussed although the gas measurements were evaluated against historical field PVT data, due to the unavailability of a valid test barge gas rate comparison meter.
The project platforms currently identified for multiphase metering differ in physical size and vary from single well to 8 well configurations. For accurate reservoir management, each well is individually rate tested to monitor well performance and to provide data for field allocation and planning purposes. The wells are presently being evaluated by test barges, which are equipped with testing facilities. A multi-phase flow meter was successfully field-tested as an alternative to the use of the test barges. Permanent multiphase flow meter installations will provide more frequent tests and considerable economical savings in the long run.
Computer Simulation of Air Pollution in Dalan Refinery
Authors: Feridun Esmaeilzadeh , Jadidi Ali Reza 
Published: December 2007

Abstract
Dalan Refinery is located in Farashband area at 200 km far from southwest of Shiraz city. Pollutant components from the dehydration units in Dalan refinery cause to pollute the surrounding environment. The main pollutant components are aromatic hydrocarbons such as benzene, toluene, ethyl benzene, propyl benzene, TEG and hydrogen sulfide. In this project firstly the refinery is simulated by PROII software. Then Gaussian Plume model has been used with plan data for obtaining the concentration gradient of pollutant components. The effects of different variables upon the performance of pollution have also been studied. These variables include wind velocity, dispersion coefficient, cloud cover, radiation, stack height and exit temperature of pollutant-component stream.
In this study using stack in comparison to cooling or burning of the pollutant components is economically cheaper and for health safety is also suitable.
Asphaltene Precipitation in High Gas-Oil Ratio Wells
Authors: Kokal Sunil , Al-Ghamdi Abdullah , Krinis Dimitrios 
Published: December 2007

Abstract
Asphaltene deposits have been observed in a number of high gas-oil ratio (GOR) wells in north Ghawar. Even though the oil reservoir is undersaturated two small gas-caps are present as a result of gas injection during the 1960s and 1970s. New development wells drilled recently to produce oil and gas from the gas-cap areas have experienced asphaltene deposition. The cause of precipitation is the stripping of the asphaltenes from the crude by the gas.
This paper describes the results of an investigative study that was initiated to determine the precipitation mechanism and ways to alleviate the deposition problem. Asphaltene precipitation experiments were conducted at reservoir conditions in a special PVT apparatus. The effect of gas-oil ratio on asphaltene precipitation was determined by titrating the reservoir oil with gas-cap gas. Bulk deposition tests were also performed at different GORs with reservoir fluids. The results demonstrate that the onset of asphaltene precipitation occurs at relatively low GOR values. However, the amount of asphaltene precipitated at the onset is negligible. Asphaltene precipitation and deposition increase with increasing GORs. Asphaltene deposition envelopes are provided for the reservoir oil as a function of pressure and temperature. Guidelines are provided to alleviate the problem by controlling the GORs. Recipes for solvent treatment including asphaltene dispersants are also described in the paper.
Production Improvement by Downhole Demulsification - A Simple and Cost Effective Approach
Authors: Dutta Bapan K. , Ahmed Hani H. 
Published: December 2007

Abstract
Downhole demulsification of crude oil increases well production and profitability by reducing vertical flow pressure loss. This paper presents a practical, field-tested method to accomplish downhole demulsification without the mechanical complexities of the conventional downhole injection system. Chemical is injected at surface with a pneumatic dosing pump into the gas lift stream. Lift gas entering into the tubing-casing annulus carries the chemical downhole to the injection point deep into the tubing and blends it with the well fluid to prevent emulsification. Production improves after a few days of chemical injection as the downhole demulsification process stabilizes. Successive trials have proved the effectiveness of the approach in terms of improved production. In view of the simplicity and cost effectiveness of the method, it has also been applied in naturally flowing wells that produce below their potential because of emulsion. Case study and result of such trial have been discussed in the paper that shows promising success. It has broadened the application scope of the system to emulsion-infested natural flow wells.
Characterization of Asphaltene Precipitation Effect on Reducing Carbonate Rock Permeability
Authors: Kocabas I. 
Published: December 2007

Abstract
Asphaltene precipitation is a nearby wellbore phenomenon with strong adverse effects in rock permeability affecting the production operations. However, a complete characterization of the asphaltene precipitation effect, namely quantifying the degree, scale and mechanisms of permeability reduction still remains to be resolved. In this paper we report the results of a series experiments on characterizing the asphaltene precipitation effect on permeability reduction. The experiments are also unique in providing the precipitation effects on the end point relative permeability at Siw.
For quantifying the degree and scale of asphaltene precipitation a set of experiments are designed to induce permeability reduction along the flow direction. Then the plugged and unplugged pore ratios were quantified using SEM images taken at five different points from the core inlet. In all experiments, total plugging has occurred between 40 to 60-pore volume injection. It has also been found that within a distance of 0.3 total core length, approximately 80 % of the plugging has occurred indicating the ‘snowballing’ nature of mechanical entrapment.
Then the two major mechanisms of asphaltene deposition namely dynamic asphaltene adsorption and mechanical entrapment were quantified by reversing the flow direction. The reversal of the flow have initially resulted in approximately 80 percent permeability recovery, indicating that 80 percent of the permeability reduction is caused by mechanical entrapment. Then a period of simultaneously acting recovery and impairment mechanisms has been observed finally followed by impairment mechanism only. After the initial recovery period, a consequent flooding of one the cores with toluene were able to establish the original permeability. This additional recovery is attributed to removal of the adsorbed asphaltenes.
Control of Scaling Tendencies in an Effluent Water Injection Plant in West Kuwait Oil Fields: Laboratory Study
Authors: Salman M. , Al-Hashem A. , Carew J. 
Published: December 2007

Abstract
Scale inhibitors screening and evaluation study was conducted to minimize the possibility of scaling tendencies when effluent water is injected into the reservoir of West Kuwait oil fields. Static autoclave jar test and dynamic scaling rig were used to screen and evaluate six commercially available scale inhibitors. Five different effluent and formation waters were tested using the static jar test and dynamic scaling test rig under reservoir and surface conditions. The results of this scale inhibitor screening and evaluation study were judged upon efficiency to inhibit calcium carbonate (CaCO3) and barium sulphate (BaSO4) scales. The two most effective scale inhibitors to reduce both CaCO3 and BaSO4 scales were selected with optimum dosages. The first effective inhibitor was an aqueous solution of organic phosphate with an optimum dose of 15 ppm to control CaCO3 and 20 ppm to control BaSO4. The second effective inhibitor was a combination of organic amine and organic phosphates with an optimum dose of 20 ppm to control both CaCO3 and BaSO4.
Gas Process Displacement Efficiency Comparisons on a Carbonate Reservoir
Authors: Egermann P. , Robin M. , Lombard J-M. , Modavi A. , Kalam M. Z. 
Published: December 2007

Abstract
Secondary and tertiary recovery processes based on gas injection can represent a very interesting solution to extend the life of waterflooded reservoirs and maximize the oil recovery. However, the injection strategy needs to be carefully studied in order to optimize the overall sweeping efficiency. In particular, the impact of a possible water blocking on the recovery has to be addressed. For that purpose, a series of experiments was performed under reservoir conditions on a carbonate rock type, to compare the displacement efficiencies of a secondary gas injection, a tertiary gas injection and a SWAG (Simultaneous Water Alternated Gas) injection.
The experiments were carried out on composite cores, consisting of several carefully selected reservoir core plugs of the chosen rock type. The operating pressure was lower than the minimum miscible pressure (MMP) and reflected the current reservoir pressure. Phase exchanges were continually monitored during the hydrocarbon recovery, including the chromatographic analysis of the produced gas.
The final oil recovery resulting from the three types of experiments were very good (about 90% OOIP at surface conditions, after 6 PV injection) and quite similar within the experimental conditions, regardless of the sequence of gas injection. The low residual oil saturation (Sorg) values observed were consistent with competing processes of both viscous displacement of oil by gas and phase exchanges occurring between oil and gas. Due to the nature of the injected gas (rich gas from the first separation stage), a condensing/vaporizing process had to be considered. The SWAG injection speeds up the oil recovery by a mobility control of the water phase. This enhances the sweep efficiency by viscous drive. Water blocking effect was found to be negligible as it could be anticipated due to wettability consideration.
The influence of the fluid description (EOS) and the threephase relative permeability model on the simulation results was studied. An excellent agreement between simulation and production data was obtained using both gas/oil relative permeability data measured at ambient conditions on a restored composite core and an appropriate EOS (with 7 pseudos). The condensing/vaporizing process that strips the intermediate compounds from the oil phase to the gas phase was properly taken into account with this appropriate EOS. The influence of the three-phase permeability model ("geometrical construction" or Stone1) on the results was found to be small.
Integrated Workflow Applied to the Characterization of a Carbonate Fractured Reservoir: Qarn Alam Field
Authors: Zellou A. M. , Hartley L. J. , Hoogerduijn-Strating E. H. , Al Dhahab S. H. H. , Boom W. , Hadrami F. 
Published: December 2007

AbstractThis paper presents an innovative integrated workflow applied to the characterization of a carbonate fractured reservoir in order to generate an effective 3D Matrix Block Size (MBS) distribution based on all available data: geological, geophysical and dynamic production data. The MBS is a key factor determining heating and thereby recovery efficiency during steam flooding in a fractured reservoir. The MBS model allows simulating the complex flow and establishing reservoir management strategies that will optimize oil recovery and facility sizing.The major difficulty in developing a 3D MBS model is the ability to account for the all the information pertinent to natural fractures in the field and develop an understanding of what geological characteristics are linked to the occurrence of fractures. Until recently most fractured reservoir modeling tools were limited to simple discrete statistical models. A new approach in fractured reservoir characterization, using primarily artificial intelligence tools, is presented in this paper. The methodology is based on the assumption that there is a complex relationship between a large number of potential geologic drivers (structure, faults, matrix characteristics etc.) and fractures. The combination of both the continuum fracture modeling (CFM) and discrete fracture network (DFN) modeling provides a quantitative framework for MBS distribution estimation, geological concepts and data integration. The application of this integrated workflow to the Qarn Alam field is presented in this paper.
An Overview of the Development of the Scarab/Saffron Project
Authors: Dick Will , Sharshar Abd El Raouf 
Published: December 2007

Abstract
The Scarab/Saffron Development was initiated by the signing of the West Delta Deep Concession Agreement between the Government of the Arab Republic of Egypt(A.R.E.), The Egyptian General Petroleum Corporation(EGPC), BG Exploration and Production Ltd(now BG Group) and Edison Gas International. Following the signature of the Gas Sales Agreement and Project Sanction, a Joint Venture Company called Burullus Gas Co comprising EGPC(50%), BG Egypt (25%) and Edison Gas International (25%) was formed.
Performance Enhancement by Applying RDBMS Tool as A Small-Enterprise Solution to Integrated Data Management - A Case from Kalol Field, India
Authors: Ghosh U. K. , Patra T. C. , Raghuvir Singh 
Published: December 2007

Abstract
Kalol field is a major oil-producing field of Ahmedabad Asset, ONGC. The field has 40 years of history with over 500 wells drilled and 11 potential hydrocarbon-bearing layers exploited. Over the years data has gathered differently into substantial dimension. A field-level integrated database system has been developed in-house using &lt;i&gt;Microsoft Office&#39;s Access &lt;/i&gt;module. Apart from regular data management tasks, the package is designed to generate streaming input data files for two popular software. As the package is equipped with strong relational back-bone, data updating is instantaneous and it remains integrated sans any duplication or redundancy. The package is in use for Kalol field most effectively and indeed a suitable quick-run data management tool for any oil-field, small or large.
Comparison of Wellbore Hydraulics Models to Maximize Control of BHP and Minimize Risk of Formation Damage
Authors: Gil Isabel C. , Shayegi Sara 
Published: December 2007

Abstract
Underbalanced drilling is considered a technique for improving productivity, since the target zone in the well is drilled with bottom-hole drilling pressure lower than pore pressure in the target zone. These differences in pressure may minimize the risk of formation damage if the bottom hole circulating pressure is maintained lower than reservoir pressure at all times. For this reason, it is very important to have good knowledge of pore pressures and bottom hole circulating pressures and their variations while drilling.
The ability to accurately predict bottom hole pressure is critical for both designing an underbalanced drilling operation as well as for predicting the effect of variations during the actual drilling operation. Commercial models are available to calculate wellbore hydraulics for fluids used in underbalanced operations. Modeling is employed for designing and monitoring underbalanced drilling operations and for modifying operational parameters in response to changing conditions. It is also very important to realize that, in case the bottom hole pressure signal from the downhole tool is lost, it is necessary to rely on the model being used. If calibration has already been made and predictions agree with actual measurements there is more confidence in the model and the prediction that the system is underbalanced. Otherwise underbalanced conditions may not be guaranteed, and formation damage could occur.
Field data from oil and gas wells are used in this paper for comparing the prediction of bottom hole pressure using different wellbore hydraulic simulators against the actual pressure while drilling underbalanced. Results show which simulator and correlations give better predictions based upon characteristics of the wells and fluids type. The source of differences in results is examined and recommendations are made.
The Challenge Of Well Control In Under Balance Drilling And The Role Of Training In Meeting It
Authors: Malkowski Richard 
Published: December 2007

Abstract
In overbalanced drilling conventional well control is affected by using a hydrostatic pressure greater than the pore pressure. In under balanced drilling this differential is removed and bottom hole pressure is maintained at a value less than the pore pressure. Therefore there is a continuous "well control situation" during the under balance section.
To do this requires some form of rotating control device, drilling chokes, specialised fluids and different operating techniques.
A Closed Form Hydraulics Equation for Predicting Bottom-Hole Pressure in UBD with Foam
Authors: Guo Boyun , Sun Kai , Ghalambor Ali 
Published: December 2007

Abstract
A closed form and easy-to-use analytical model has been developed in this study for foam hydraulics. The analytical model fully couples the frictional and hydrostatic pressure components in vertical and inclined boreholes. The newly developed model together with screened rheological model was validated using bottom pressure data measured from two wells drilled with stable foams. The maximum difference between the model-predicted and measured bottom hole pressures is 9.2%. Theoretical analyses with the model indicate that injection GLR is a dominating factor affecting depth limit and ECD in stable foam drilling. In the practical range of GLR (1 to 20) and a gas injection rate limit of 2000 scfm, the maximum borehole depth is about 5000 ft where the lower limit of stable foam quality of 0.55 is reached. The new model was used in this study to generate depth limit and ECD curves that can be used for multi-gradient drilling on-shore and in deepwater development.
Re-Completion Techniques on Shallow Gas Wells Using Coiled Tubing Conveyed Fracturing
Authors: Thatcher Darren , Glanville Stephen , Zander Dennis , Jirges Harlan , Weishoff Jon 
Published: December 2007

Abstract
Hundreds of depleted shallow gas wells in the Saco, Montana area of the Northwestern United States have been found to have bypassed pay that until recently was believed uneconomical to recover. Wells in the area were traditionally completed with one production zone and were fractured by conventional means down the casing. The pay zones were then efficiently depleted through the use of siphon strings and flow line compression. Upon review of the well logs, it was determined there may be enough bypassed pay within the existing wellbore to continue producing the well as a multi-zone completion.
This paper outlines the logistics, execution, and evaluation of coiled tubing conveyed fracturing for depleted gas wells. Formations that were stimulated in this study appear to have similar characteristics to the thin producing lenses typically treated in Southeastern Alberta, Canada. The majority of the wells treated received up to six fractures and averaged 100,000 lbs of sand placed into each wellbore. The challenges and results from an initial pilot project are reviewed along with the subsequent multi-well project that followed.
New Boundaries for Cementing with Coiled Tubing
Authors: Wilson K. J. , Morrison D. , Sackash M. J. , Poole D. 
Published: December 2007

Abstract
Recently a contaminated cement squeeze was performed in the Gulf of Mexico using coiled tubing. The work was performed at 18,600 ft, 326°F bottom hole temperature, 12,000 psi pumping pressure and 9,000 psi chokeback pressure in a H2S, CO2 environment. Operationally this squeeze was a tremendous success and set several new benchmarks with regards to high-pressure coiled tubing operations.
This paper describes the reasons for using a contaminated cement squeeze under these harsh conditions, the standard procedure for this work, and the deviations from standard procedure made specifically for this well. The paper also discusses the importance of hydraulic modeling, fluid selection, the benefits of doing yard tests, and analyzing previous jobs to verify the models.
A Multi-Well Review of Coiled Tubing Force Matching
Authors: Craig S. H. 
Published: December 2007

Abstract
To increase the predictability of successful coiled tubing operations, a review of recorded versus predicted weights was undertaken for several Statoil operated Norwegian platforms. Results from thirty-three wells were analysed and showed that a coefficient of friction of 0.24 was applicable in most wells. Additionally, it was confirmed that deviation complexity, production rates and direction of travel had no effect on the friction coefficient.
Selective Tubing Access into Multilateral Wells in Upper Zakum Field: A Two-Well Case Study From Abu Dhabi
Authors: Dahroug Ahmed , Al-Marzooqi Ali , Al-Ansara Faisal , Chareuf Ali , Hassan Mahmoud 
Published: December 2007

Abstract
Branches in Level 1 and 2 lateral extensions traditionally have offered limited access. Coiled tubing (CT) intervention was limited to the main hole only, and thus stimulation of main reservoir targets was not possible.
A new system designed with a 2 1/8-in. outside diameter (OD) enables rigless intervention through the completion restriction. The system includes a reentry bottomhole assembly (BHA), which consists of a surface-controlled orienting tool and a controllable bent sub (CBS). The Discovery MLT* multilateral tool identifies the window of the selected lateral before attempting reentry, and confirms successful identification. The entry is visible at the surface through a software-displayed pressure log. The technique does not require a wired coiled tubing string; the corrosion-resistant reentry tool is operated solely by flow and is conveyed with standard CT equipment.
As proved by the success of the new reentry tool in Upper Zakum field selective matrix stimulation and nitrogen kickoff operations detailed in this paper, the need to bullhead huge acid treatments that result in major openhole washouts has been eliminated. These washouts can cause both poor acid distribution and prevention of future access to the lateral for CT logging operations.
This paper discusses the successful deployment of a selective multilateral entry tool that was utilized to access multilateral wells in Upper Zakum field, two case histories, and the method™s potential in Upper Zakum field.
The two case studies presented demonstrate the success of this system in reentering a desired lateral on the first attempt for matrix stimulation operations. Current developments that enlarge the scope of application to wellbore logging are under study.