bluuebunny/crossref_metadata_2025_split huggingface dataset:
Applying a New Systematic and Dynamic UBD Procedure Prevented Formation Damage, Wellbore Collapse and Improved Oil Production in Hassi Massoud Field
Authors: Berkat Ali , Kartobi Khelil , Mazouzi Amine , Dhina Okba , Qutob Hani , Barakat Naiem , Grayson Fudge , Marei Ayman 
Published: March 2009

Abstract
The Hassi Massoud oil field is the largest of its kind in Algeria. The reservoir was discovered in 1956 and produces from a Cambrian-age at approximately 3400 meters depth. It produces 45°API oil from a thick Cambro-Ordovician sandstone formation.
This sandstone is extremely hard, abrasive and slow to drill. The reservoir is naturally fractured in some parts. Fractures are either open or plugged with materials such as shale, silica, anhydrite, pyrite and bitumen. Porosity is ranging from 6 to 12%. Generally, the permeability is low with a range of less than 1 to more than 100 md in open-fractures layers
Sonatrach introduced Underbalanced Drilling (UBD) primarily in an effort to improve penetration rates. However, all additional benefits obtained from UBD, such as production improvement and reservoir characterization while drilling, will be of an added value.
Well OMPZ553 is the 37th well drilled underbalanced in the Hassi Massoud field. In this well, the focus was on production improvement with minimum formation damage while the increased rate of penetration (ROP) was a secondary benefit. Another objective was the evaluation of production while the well is being drilled. This eliminates the need for expensive post drilling production testing, and also to minimize borehole instability specially when drilling in the R2 section of the drain.
In order to increase the success rate of drilling and completing this well underbalanced, Sonatrach introduced a new systematic and dynamic procedure. The new procedure consists of: Proper UBD candidate screeningCalculating the actual reservoir pressure before UB mode startsCompleting the well in UB mode
This well proved to be the best UB drilled well in Hassi Massoud field in terms of reservoir benefits and characterization. The pre-job UBD candidate screening, feasibility studies and applying the new procedures proved effective in the success of this well.
This paper describes in detail the above procedure and presents the successful application of such procedure to optimize production and enhance the ultimate recovery in the Hassi Massoud field. Lessons learnt and challenges encountered will also be discussed in this paper
Chemistry Applied to Fracture Stimulation of Petroleum Wells
Authors: Harris Phillip C. , Sabhapondit Anupom 
Published: March 2009

Abstract
Hydraulic fracturing is a stimulation procedure that is applied to petroleum wells that will not otherwise produce at commercial rates. Hydraulic fracturing employs fluids that are pumped with very low tubular frictional pressure, yet have sufficient viscous properties to generate fracture geometry in subterranean rock and transport solid propping agents to hold the fracture open.
Fluids for commercial fracturing applications contain polymers, crosslinking agents, surfactants, clay-protective agents, and viscosity breakers. All of these must be balanced to result in the physical properties required at elevated temperatures and pressures without damaging the proppant pack or rock formation. Complex chemistry is carefully controlled on a large scale and in a hostile environment for the fracturing process to be successful.
Most fracturing fluids are mixed in aqueous media. One of the polymers used in fracturing is water-soluble polysaccharides derived from natural guar. Crosslinking agents include borate, titanium, and zirconium complex ions. Formation compatibility is enhanced by clay-protective materials, such as potassium chloride and organic salts, with surfactants to lower interfacial tension. Fluids heat up as they travel down the wellbore and into a subterranean fracture. Timing of the crosslink initiation is vital to balance fluid friction in the wellbore and yet obtain proper penetration into the fracture and transport of propping agents. Finally, the viscosity developed by the crosslinked gel is broken with chemical agents to allow the injected liquid to be produced back to the surface.
This paper discusses the development of fracturing fluids and shows how the kinetic reaction of polymers, crosslinking agents, and other chemical components work together to produce the favorable result of stimulating petroleum wells to produce at higher rates.
With the focus of today's oil production moving from the western hemisphere to the eastern hemisphere, new research facilities have been established to apply technology-specific adaptations to the demands of eastern hemisphere reservoirs. These adaptations will improve the efficiency of oil and gas production for the future.
On the Relationship between Electrokinetics and Reservoir Rock Physical Properties
Authors: Alkafeef Saad F. , Zaid Alforgi M. , Alajmi Abdullah F. 
Published: March 2009

Abstract
Numerous investigations have been made of the relationship between formation resistivity factor and porosity of reservoir rocks. One of the most widely used expressions is the familiar Archie equation. This paper presents an investigation of the relationship between electrokinetics and reservoir rock formation conductivity factor and porosity. Electrokinetics is the general term associated with the relative motion between charged solid/liquid interfaces, and has proven to provide direct information on oil reservoir characterizations. The movement of liquid through the capillaries carries a net charge (mobile part of the Electrical Double Layer) and it gives rise to streaming current, consequently, a potential difference (streaming potential). This investigation leads to the determination of formation conductivity factor from the total electric conductivity of reservoir rocks. This was achieved from the estimation of the ratio of the pores' area cross section 'A′ to its length 'L′ by coupling streaming current and streaming potential measurements. The validity of calculated formation conductivity factor from this analysis is established by the use of sandstone data with various porosities. The results are in good agreement with the Humble expression for porosity-formation resistivity factor relationship. These results could prove to be valuable in determining formation conductivity factor from simple and quick measurements of streaming current and streaming potential. The factor can then be used to estimate water saturation in the normal manner.
Controlled Pressure Drilling (CPD) Candidate Screening Methodology
Authors: Villatoro Jaime , Boutalbi Said , Schmigel Kevin , Qutob Hani , van Galen Martijn , Lakshminarayanan Sunil 
Published: March 2009

Abstract
Controlled pressure drilling (CPD) has become the most effective drilling method to improve technical limit drilling time and reduce previously recorded lost time on offset conventionally drilled wells—when it is applied to correctly selected candidates. In addition, specific drilling techniques offered within CPD technology not only improve the time it takes to reach total depth (TD), but also have been proven to optimize reservoir section productivity and maximize economically recoverable reserves. CPD comprises three main techniques: air drilling, underbalanced drilling, and managed pressure drilling. This paper discusses the latest CPD techniques and the non-productive time that it can address.
A methodology to properly screen all CPD techniques to reduce failure/misapplication and align objectives with expectations had been absent. This paper addresses the latest enhancements in an expert system developed to better understand and screen options for CPD operations. The Internet-based selection tool provides guidance by using key indicator questions, beginning with the primary objective(s) for the given wellbore section. If the specific CPD technique is known, the user can activate the online screening tool. The online screening tool considers a range of economic and technical parameters, as applied to algorithms and logic rules, to provide a relative ranking for each candidate of the CPD technique. Sensitivity analysis can also be performed to determine the impact of key uncertain parameters. Additional expert screening and selection methods are available upon the completion of the online CPD candidate selection process. The paper provides an overview of the Internet-based tool and methodology, in addition to supporting case histories.
Review and Outlook of Subsurface Acid Gas Disposal
Authors: Carroll John J. , Griffin Peter J. , Alkafeef Saad F. 
Published: March 2009

Abstract
Acid gas primarily is a mixture of carbon dioxide and hydrogen sulfide and is a byproduct of the sweetening of natural gas. Acid gas injection (AGI), an environmentally friendly method of dealing with the acid gas, is basically the compression of a low-pressure stream to sufficient pressure to achieve injection. The fluid is transported via pipeline to an injection well where it travels downward into a selected injection reservoir. AGI is a mature technology on a small scale (less than 283×103 SmVd [10 MMSCFD] of injected fluid). In addition there are a few injection schemes on a medium scale (less than 2125×103 SmVd [75 MMSCFD]). Some producers are now considering injection on a larger scale (greater than 2125×103 Sm3/d [75 MMSCFD]). Many of the principles used to design the small and medium sized injection schemes can be transferred to the larger schemes. However the larger injection schemes pose new challenges. In this paper the state of the art for AGI is reviewed. The main difference between the current injection schemes and some of those proposed is the volume of fluid to be injected. Some of the newer projects are suggesting the injection of significantly larger volumes than are currently being injected. Some of the differences between the small and large-scale injection schemes are discussed. The main focus of this paper is on the surface facilities, but wells and the injection reservoir are also discussed.
The Oil Compressibility Below Bubble Point Pressure Revisited–Formulations and Estimations
Authors: Al-Marhoun Muhammad Ali 
Published: March 2009

Abstract
Oil compressibility plays an important role in reservoir simulation, material balance calculations, design of high-pressure surface-equipment and the interpretation of well test analysis, specifically for systems below the bubble point pressure. Accurate information on the oil fluid compressibility above and below bubble point pressure is very important for reservoir evaluation.
The conventional definition of the isothermal oil compressibility below bubble point pressure is being questioned on its scientific merit and challenged against the basic compressibility definition and the general trend of physical behavior of compressibility. This paper presents a new derivation based on the basic compressibility definition to calculate the oil compressibility below bubble point pressure. The experimental data obtained from flash and differential liberation tests is utilized to determine the isothermal oil compressibility values.
It is found that the oil and gas compressibilities below original oil bubble point pressure computed in the conventional method may lead to errors in reserve estimation for saturated reservoirs and skin factor in well test analysis.
Geomechanical Characterization of a Sandstone Reservoir in Middle East—Analysis of Sanding Prediction and Completion Strategy
Authors: Mohiuddin M. A. , Najem M. M. , Al-Dhaferi Y. R. , Bajunaid H. A. , Tan C. P. 
Published: March 2009

Abstract
Sanding problems are often observed in fields after a period of relatively smooth operation. These occurrences usually coincide with an increase in depletion, water cut, or changes in the artificial lift mechanism used to produce the hydrocarbon. Sanding is detrimental to optimum field development and therefore, information about the possible advent and extent of sanding will be helpful in planning for completions and facilities.
The study presented in this paper characterizes the geomechanic behavior of a field in which sanding problems are expected after depletion, increase in water cut, and installation of ESPs to optimize production. To accomplish this task, a 3D full field model was created. First, several 1D Mechanical Earth Models (MEMs) were developed. These 1D MEMs were calibrated using drilling data, laboratory measurements, well tests and other field measurements. The calibrated rock mechanical properties from the 1D MEMs were distributed in the 3D model using Gaussian sequential simulation technique. The populated 3D model was then used to perform a coupled geomechanical simulation to evaluate the changes in stress with time and production.
The rock mechanical properties and stresses needed to perform sanding analysis were sampled along the well trajectories from the 3D model. Sand production prediction analysis was subsequently undertaken using a field proven sanding prediction model that accounts for scale effects associated with different perforation size and sand grain diameter, and plasticity effects that modify the strength behavior of sands surrounding open holes and perforations during drawdown and production. The sanding tendency predicted from sanding analysis was corroborated with field observations. This was also used to calibrate the 3D model and formulate a completion strategy to minimize sand production for the life of the field. The completion strategy optimizes the production using ESPs while minimizing sand production.
Development of a Full-Field Parallel Model to Design Pressure Maintenance Project in the Wara Reservoir, Greater Burgan Field, Kuwait
Authors: Ma Eddie , Williams Lee , Ambastha Anil , Al-Naqi Meqdad 
Published: March 2009

Abstract
The Wara reservoir is one of the four main reservoirs in the Greater Burgan field, the world's largest sandstone oil field. It has experienced significant pressure decline after 60 years of primary production. In 2005, design for a pressure maintenance project (PMP) via a peripheral waterflood was initiated to arrest pressure decline and improve oil recovery.
A key building block of the Wara PMP is a stand-alone, full-field Wara simulation model. The 23-million cells geological model was scaled-up to 4 million cells for flow simulation. Four pseudo layers were added to the simulation model to allow fluid migration via faults from the lower reservoirs. The new model has 100 m x 100 m areal cells and individual layers with an average thickness of 6 ft. Overall, this new model has 18 times refinement compared to the previous model for the Wara reservoir. Thus, this model is suitable for evaluating PMP, infill drilling and pattern waterflood. This paper, however, focuses on PMP evaluation only carried out over the last four years.
The final history-match has been carried out at three levels: Field, Gathering Centers (GC) and Key Wells. Detailed study of interactions among field permeability distribution, edge aquifer representation, and fault transmissibility specifications on simulation results was key in developing a meaningful history-match. PNC data for many wells around the periphery of the field provided useful insights for edge aquifer representation. Water cut match was less than satisfactory for wells located in the center due to modeling deficiency of pseudo layers as discussed in the body of the paper.
Prediction runs have been set up to investigate various PMP designs. These runs include sensitivity with respect to number of injectors, number of producers, target injection rate per well, maximum bottom-hole injection pressure, voidage replacement ratio, injector-producer distances, and injector-producer rows along with various scenarios for dealing with production from existing Wara producers throughout the field. This flow simulation model will be used as an operating model to optimize process design and well location.
Opportunistic Fluid Sampling and Analysis to Track Reservoir Souring in Water Flooded Operations in North Kuwait Reservoirs – Implications for the Future
Authors: Al-Marri Salem , Alkafeef Saad , Chetri Hom , Al-ghabdan Asma'a 
Published: March 2009

Abstract
Reservoir souring while water flooding North Kuwait reservoirs has been predicted by modeling studies in the past. One of Sabiriyah Mauddud wells showed up H2S as first indication of reservoir souring, which was an alarm bell for production facilities designed for only sweet crude. Surface/ Bottomhole fluid samples were required to confirm whether it is localized or reservoir-wide. In order to track reservoir souring and monitor on continuous basis, a process for tracking of reservoir souring annually was developed and initiated for the first time in 2006. Subsequently, this has been made part & parcel of fluid study requirements each year.
As sea water is being injected into traditionally sweet reservoir like Sabiriyah Mauddud, some degree of reservoir souring is expected due to Sulfate reducing bacterial (SRB) activity, as was projected happen sometime in 2005 in wells, needing monitoring/ mitigation actions. Expected H2S levels being very low (50–200 ppm), risk of loosing and not capturing these concentrations using conventional samplers/ bottles due to absorption/ reaction with the metallurgy of the samplers was felt, thus posing a challenge for obtaining a representative bottomhole sample for the analysis of H2S.
A comprehensive sampling program was made jointly by KOC & KISR, using the non-reactive internally coated samplers for capturing bottom hole samples; performing the onsite analysis, followed by immediate shipment to the local fluid analysis laboratory and conduct all necessary analysis with expert supervision & care.
Value was added to North Kuwait Water flood management by timely knowing the onset of reservoir souring. The analysis also led the way forward for the review of chemicals dosages; interventions needed in case of H2S occurrence; inputs to the future facilities and the requirements of further modeling studies.
Increased Certainty in the Determination of Zonal Isolation through the Integration of Annulus Geometry Imaging and Improved Solid-Fluid Discrimination
Authors: Al-Suwaidi A. S. , Al-Marri Faisal M , Sultan Emad , Ibrahim Moh'd El-Sayed , Jammeli Kamal , Al-Kindi Zaid , Elkadi Antoine 
Published: March 2009

Abstract
The zonal isolation behind casing was critical during a major field development project in the Middle East. However, the assessment whether the cement bond will hold against hydraulic communication or not has not always been an easy task; slurry contamination during pumping, slurry invasion by formation hydrocarbons especially gas, channeling through the cement sheath, patchy cement, annulus shape and casing excentralization inside the outer wellbore are all factors that have traditionally made it difficult and sometimes even impossible to judge the zonal isolation behind casing between various zones of the reservoir.
A new approach was adopted for the assessment of the cement bond behind casing in this project. The technique combines the conventional "pulse – echo" ultrasonic measurement with that of a newly introduced flexural waveform. The analysis from this combination allows a better discrimination between solid, liquid and gas behind casing and it also provides, for the first time, a comprehensive assessment of the annulus shape and casing centralization inside open hole or inside the second casing string. This latter casing stand-off measurement has proven to be instrumental when deciding whether the cement sheath will hold against hydraulic communication or not.
In this paper we will discuss the data that was acquired in four wells from this project. We aim at proving the clear benefit of this new approach for the assessment of zonal isolation behind casing.
Gas Condensate Relative Permeability of Low Permeability Rocks: Coupling Versus Inertia
Authors: Jamiolahmady M. , Sohrabi M. , Ireland Shaun 
Published: March 2009

Abstract
Flow around the wellbore of gas-condensate systems, when pressure drops below dew point, is controlled by complex interaction of capillary, viscous and inertial forces. Hence, accurate determination of gas-condensate relative permeability (kr) that is affected by relative impact of these forces is challenging.
There are a number of reports demonstrating kr of high permeability rocks affected by both coupling (the increase of kr as velocity increases and/or IFT decreases) and inertia (i.e., the reduction of kr as velocity increases) for these low IFT systems. However, there is little information on this subject for low permeability rocks.
In this work, we report and analyze a series of steady state kr for a 3.9 mD reservoir rock with low porosity of 6% measured using our unique experimental facilities. These data have been measured at three IFT below one mNm−1 and five velocity levels below 200 md−1.
The results indicate that at the highest IFT, inertia is dominant at low condensate to gas flow rate ratio (CGR) whereby kr reduces with increasing velocities. At higher CGR, an increase in kr is observed due to the dominant effect of coupling. At lower IFT, the negative impact of inertia on kr as velocity increases is observed at all CGR. We have recently reported kr of highly conductive propped fractures showing a more pronounced effect of inertia at lower IFT but this is the first report of such behavior for low permeability rocks. We also compare the results with the corresponding predicted kr by the generalized kr correlation, which we reported recently and expresses the combined effect of coupling and inertia with universal parameters. The unique contribution of inertia, as observed in the experiments and predicted by the correlation, is mainly attributed to impact of the single-phase inertial factor and fluid properties.
Experimental Evaluation of Heavy Oil Recovery by Hot Water Injection in a Middle Eastern Reservoir
Authors: Alajmi Abdullah F. , Algharaib Meshal , Gharbi Ridha 
Published: March 2009

Abstract
With the increase of oil demand worldwide and current oil price, the recovery of heavy oil deposits became a major issue in the oil industry. Overcoming the challenges and complexity associated with the production of these deposits has been the target and focus in recent years. Large quantity of hydrocarbon deposits remains unrecovered due to the high viscosity of oil. Thermal recovery processes are techniques used to reduce the oil viscosity and enhance the oil recovery by introducing heat to the underlying reservoirs. Hot water injection is a thermal recovery technique in which water is injected into hydrocarbon strata. The hot water injection reduces the viscosity of the heavy oil and provides a driving mechanism to sweep the heavy oil toward production wells. In this work, the application of hot water injection in a Middle Eastern reservoir with large heavy oil deposits was investigated. The reservoir's heavy oil had a viscosity of 500 cp and an initial oil saturation of 75%. Two-phase fluid flow displacement experiments were conducted. The objective was to find the optimum design parameters in terms of injection temperature and hot water slug size that would yield to the best performance. The results obtained from several design configurations are presented. These configurations include hot water floods with different slug sizes and sequences. These results can be used as a tool for the successful design of hot water injection to recover heavy oil in these types of reservoirs. In addition, they provide the condition under which a given design may yield better recovery performance.