bluuebunny/crossref_metadata_2025_split huggingface dataset:
Prevention of Dissolution and Re-Precipitation of Calcium Sulfate While Acidizing
Authors: Quintero Harvey , Maley Darren Michael , Zafar Farah 
Published: March 2015

Abstract
Calcium sulfate in the form of gypsum (CaSO4.2H2O) and anhydrite (CaSO4) is one of the most prevalent evaporite minerals typically found in the prolific middle Devonian carbonate rocks of the Western Canadian Sedimentary Basin (WCSB). Strong mineral acids, in particular hydrochloric acid (HCl), are employed to enhance permeability in the near wellbore area of the oil wells in these carbonate-bearing formations during matrix stimulation and hydraulic fracturing treatments. When calcium sulfate (CaSO4) comes in contact with the live acid, partial dissolution can occur. As the acid solution is progressively spent inside the carbonate rock, the concentration of unassociated calcium ions will increase. These ions will become readily available to react with the sulfate ions in the neutralized solution and cause, the unavoidable re-precipitation of CaSO4 crystals in the pore throat, therefore severely plugging the newly created flow channels.
Based on Le Chatelier's principle and the common ion effect, the addition of a soluble calcium salt to the treating acid package has been an economical oil field practice established to suppress the initial dissolution of CaSO4. However, a secondary protection mechanism is still required because sulfate-rich connate water could commingle with the spent acid solution during swabbing and/or flowback operations, reaching the ideal conditions for CaSO4 precipitation.
To date, most of the CaSO4 scale inhibitors that have been applied for acid treatments relied on either the retardation of CaSO4 crystal growth, or the creation of soluble complex salts with the calcium ions. This paper intends to detail the development and laboratory testing of a broad spectrum scale inhibitor specially formulated for high salinity and acid solutions that not only prevents the precipitation of CaSO4, but also helps to inhibit the initial dissolution of CaSO4.

Introduction
Covering a vast extension of 1.4 million square kilometers (Bowers 1997), The WCSB defines its coordinates between the southwestern border of the Canadian shield in Manitoba and the eastern flank of the Canadian Rocky Mountain system in British Columbia. Within the WCSB, approximately half is composed of carbonate reservoirs of the Devonian age. These Carbonate formations combine for a project reserve of 15 billion barrels of oil and 35 trillion cubic feet of natural gas (Li 2002). These important reserves of hydrocarbons have been successfully exploited since the late 1940's (Milligan 1998).
Investigation of Asphaltene-Asphaltene Association and Aggregation for Compositional Reservoir Simulators By Quantitative Molecular Representations
Authors: Hibi Ryutaro , Tagami Kanako , Kobayashi Kazuya , Liang Yunfeng , Honda Hiromi , Murata Sumihiko , Matsuoka Toshifumi , Morimoto Masato , Uetani Takaaki , Boek Edo Sicco 
Published: March 2015

The objective of this research is to properly calculate the association energy with molecular models of asphaltenes using Molecular Dynamics (MD) simulations. Asphaltene precipitation clogs pore throats of reservoir rocks, and significantly reduces the production rate. To better understand the asphaltene precipitation, a process-modeling methodology has been developed. The cubic-plus association equation of state (CPA) (Li & Firoozabadi, 2010) is effective in the modeling, and contains only one adjustable parameter, that is, association energy of asphaltene, however, we were not able to correctly evaluate the association energy by the currently available methods. Quantitative Molecular Representations (QMR) method provides systematic structural representations of asphaltenes based on analytical data of a crude oil, from which molecular models of asphaltene can be obtained. These models will be employed in this study for calculation of the association energy.
Two different asphaltene models were generated for two different crude oils (Oil 'A' and Oil 'M'). The potential of mean force (PMF) is calculated with two models of asphaltene molecules in liquid benzene for two kinds of asphaltenes using umbrella sampling method. The association energy is calculated by the difference between values at the lowest bottom of a trough and at infinity of the PMF curve. As the calculation conditions, temperature and pressure are 300 K and 100 bar, respectively.
The PMF profiles for asphaltenes from Oil 'A' and Oil 'M' were obtained, and the values of association energy were estimated as -8.39 kJ/mol and -8.91 kJ/mol, respectively. Two aromatic planes of asphaltene molecules are stacked with each other at the minimum energy point. This π-π stacking is one of the main interactions to form asphaltene nano-aggregation. The results of asphaltenes from Oil 'A' and Oil 'M' have a similar tendency; for example, the distance between the centers of mass of two asphaltenes at the minimum energy points factually equal.
The data obtained in this work should be used in the thermodynamic model of phase behavior of asphaltene dealing with asphaltene association and precipitation. It will improve the prediction ability of reservoir simulators with cubic-plus association equation of state.
Developing Strategies and Guidelines of Reservoir Data Acquisition Campaigns in One of the Major Operators in the North Field - Qatar
Authors: Al-Sharawy Mahmoud , Haidar Faesal Abdulla , Al-Medaihki Ali A , Al Meer Haytham Abdulaziz , Kandil Ahmed 
Published: March 2015

Abstract
Developing efficient strategies for reservoir data acquisition is a key aspect of reservoir surveillance that is highly valued by oil and gas operating companies. The purpose of reservoir data acquisition is to monitor well and reservoir properties such as flow capacity, skin damage around the wells as well as average reservoir pressure and production profiles in order to optimize and maintain well production.
Before 2009, Qatargas' reservoir data acquisition strategy was mainly based on applying Modified Isochronal Test (MIT), Production Logging Tool (PLT) and Bottom Hole Static Pressure (BHSP) surveys separately.
In this paper, we developed new data acquisition strategies and guidelines and compared with the old strategy. The major difference between the two is that the PLT, PBU (Pressure Build Up), multirate Flow-After-Flow (FAF) and static pressure gradient surveys are conducted in one well intervention operation in the new strategy compared with three interventions operations including PLT/PBU/static gradient, MIT and BHSP surveys in the old one. In addition, Reservoir Saturation Tool (RST), Electromagnetic Inspection Tool (EMIT) and Platform Multifinger Imaging Tool (PMIT) surveys are included in the new strategy to collect more information about the reservoir and well integrity. This is highly advantageous in terms of reducing the time and cost required for test performance. Unlike the old strategy, which requires extended shut in periods, the new strategy requires short shut in periods which result in reduced production loss. Furthermore, combining the various well tests in one operation give more practical workflow with minimized risks of repeated well intervention and maximized quantity of data gathering.
Based on our data acquisition experience at Qatargas, we belive that applying the new data acquisition strategy would add more value to the oil & gas industry in terms of reducing the operation risks, saving costs and collecting more data at the same time.

Introduction
The function of reservoir surveillance is to provide facts, information, knowledge and intelligence necessary1 to:Chronicle reservoir performance.Provide information on performance parameters to improve ability for prediction.Identify or anticipate barriers to meet or exceed forecast performance and provide methodologies to mitigate the impact.
Qatar's North field (NF) is one of the largest known non-associated gas fields in the world. It covers an area of approximately 6,000 square kilometers. The field was discovered in 1971. The first development drilling project was initiated in 1987 with the first production occurring in 1991.
Integration of the PLT and PBU Data in Permeability Modeling Workflow
Authors: Benlacheheb Mohamed , Al Meer Haytham Abdulaziz , Kandil Ahmed , Ross Fraser , Rimach Millagritos 
Published: March 2015

Abstract
Permeability prediction always constitutes a challenging step in the modeling process. Reservoir heterogeneity such as diagenesis, fracturing and effective connected geobodies are the main factors complicating the prediction. Hence, limiting permeability model to core data only could lead to unsatisfactory results while history matching. As consequence, poor reservoir performance prediction will be obtained. In such circumstance, further permeability enhancement using PBU and PLT data are usually needed.
The Core or log derived Permeability captures the heterogeneity around the wellbore whereas well test data describes the reservoir in accordance with the radius of investigation. In addition to that, the measured core permeability is absolute while the fluid flow in the reservoir is governed by the effective permeability which is captured by well test data.
Having the advantage of continuous monitoring program including PLT and PBU constitute a precious and considerable piece of data. These amounts of PLTs allow capturing the vertical heterogeneity in the reservoir while the PBU tests give better areal distribution of the KH test.
A ratio of KH test over KH core can be calculated and usually assumed as a good indicator of presence of fractures. In this case, an appropriate Discrete Fracture Network (DFN) model is required to build the permeability model. However, if the ratio is indicating matrix contribution a more simplistic approach can be applied and gives reasonable results.
By identifying the contributing intervals from PLT results coupled with the KH test over KH core ratio, the core permeability is then elevated to the test permeability.
The objective of this work is to present the application of this approach in different blocks in one giant gas field which shows improvement in the permeability prediction; results are supported by dynamic analytical model performance.

Introduction
Estimating effective permeability at reservoir scale is a challenging task especialy in carbonates due to the fact that their depositional process and the diagenetic history can be very complex, resulting in heterogeneity of the pore system. In addition to that, fractutres can occure in the reservoir leading to additional difficulties to characterize the permeability. As consequence of that, high permeability intervals can be developed at different scale, those streaks might not be captured by core and log data.
Extending the life of Brown Field Developments by Acoustic Impedance-Conditioned 3D Reservoir Modelling: An Example from a Mature Gulf of Suez Carbonate Producing Asset (Ras Fanar Field), Egypt
Authors: Vaughan Richard David 
Published: March 2015

Abstract
Discovered in April 1978, Ras Fanar Field in the Gulf of Suez of Egypt has delivered a total cumulative production of 114 MMSTB oil (Jan 2013) from Middle Miocene coralline algal buildups and laterally intercalated dolomitic layers within sabkhas deposits. OOIP was estimated to be 90 MMSTB in 1984.
This paper presents a simple but apparently effective 3D reservoir modelling workflow which used acoustic impedance (AI) data and its relationship to effective porosity as a deterministic 3D modelling parameter ("porosity-facies"). In 2002 an AI-conditioned model for the Ras Fanar Field was completed and a number of infill wells were successfully drilled within the main field which mediated the production decline of the field. Based on the model a number of higher risked drilling targets were subsequently identified to the west of the main field. The westward extension of the Ras Fanar field was confirmed by well RF-B10 in 2004. This well encountered the original field oil-water contact at 2450' TVDss despite 20 years production in the main field. The oil-water contact is thought to be in part influenced by secondary gas cap expansion which has "pushed" the oil column back to the original spill point.
Ras Fanar West development drilling has subsequently targeted lagoonal patch reef bodies landward of the main Ras Fanar Field "reef "trend. Each development well has been carefully positioned within the highest quality "porosity facies". The target locations have been optimised so that the reservoir is penetrated with the standoff from the gas-oil and oil-water contacts. Two phases of development have been successfully implemented, primarily based on the AI-conditioned reservoir model. Incremental production of 10 MMSTB has been achieved from the Ras Fanar West development area since 2004 and significant upside is still recognised.

Introduction
The Ras Fanar Field lies some 2 Km offshore east of from the town of Ras Gharib (Figure 1). The field comprises NW-SE trending structural trap bounded by a major fault system to the SW and tilted to the NE. The depositional setting of the reservoir comprises a 10–12 Km wide carbonate ramp which extends eastwards from Ras Gharib Field to Ras Fanar Field. The proposed sequence stratigraphic geological model allows for both lateral and vertical facies transitions between the Nullipore carbonates and South Gharib evaporitic-carbonate units. Several phases of upward-shoaling deposition are noted and main reef trend and patch reefs were periodically exposed as islands or raised beaches. Periods of subaerial exposure created high porosity layers (Super Permeability layers) within the reservoir resulting from karstification, solution collapse brecciation and possible mixing-zone dolomitisation. Diagenetic overprinting of the original facies was intense therefore a petrophysical-based modelling procedure was adopted (Figure 2).
Stable Fracturing Fluids From Waste Water
Authors: Kakadjian Sarkis , Thompson Joseph Earl , Torres Jose Roberto , Quintero H. 
Published: March 2015

Abstract
Environmental concerns and public opinion have elevated the visibility of hydraulic fracturing. Currently oil companies and operators acquire fresh water for fracturing treatments on the front end and pay to dispose or transport the flowback or produced water on the back end, increasing dramatically the cost of the hydraulic fracturing job. We report a newly developed fracturing fluid system utilizing 100% untreated produced water which eliminates the upfront costs of purchasing fresh water. In addition, the back end costs are significantly reduced by transporting produced and/or flowback water to locations for re-use rather than to disposal well(s) located miles away or even in other states.
This new system uses conventional gelling agents and crosslinkers used in active US shale plays, addressing the fracturing focus initiative.
This new fluid system was developed for temperature ranges between 120–300+ °F. Field tests prove shear stability and good proppant transport at 20 BPM through a 1.25 in sliding sleeve baffle. The fracturing fluid system can be designed for instant or delayed crosslinking in recycle water with total dissolved solids exceeding 300,000 mg/L with hardness exceeding 30,000 mg/L. Another concern in the past was the presence of boron in produced water. This system can be used in water containing boron levels exceeding 500 mg/L.
The code for recycle water has been broken utilizing this unique fracturing fluid system designed to conserve fresh water aquifers and recycle produced and flowback waters, reducing significantly disposal costs.
This paper reports laboratory testing of the fluid characteristics in untreated produced water from the Bakkenas well as the outcome of hybrid fluids in field applications, recommendations for field applications and economic impacts on fracturing fluid systems.
Challenge and Successful Application for Scale Removal in Oil Field, Egypt: Field Study
Authors: Hamdy Emad , Abu Bakr Mohamed , Abd El-Hay Ahmed , Sisostris Samir , Anwar Mohamed , El Farouk Omar 
Published: March 2015

Abstract
Water flooding is the hinge pin for Petrobel Oil Field. Water injection is supplied from shallow water supply wells. Compatibility tests, Petrographic Techniques and quantitative calculations of scale tendency using specific software had indicated probable deposition of calcium sulphate scale in the near-wellbore (Critical Matrix). Calcium sulphate scale, paraffin & was have been recognized to be a major operational problem. The bad consequences of scale formation& organic deposits comprised the contribution to flow restriction thus resulting in oil and gas production decrease. The nature of calcium sulphate scale is very hard and can't be dissolved with known dissolver. Sister companies that has similar problem were always going to the mechanical remover options which usually lead to further formation damage when invasion of formation rock by small particle sizes of the scale components.
Extensive lab and field work was conducted to determine the suitable chemicals to dissolve calcium sulphate scale.
The Production of Sidri formation which is currently contained 23 % of belayim land field OOIP (original oil in place) and currently contributes 27 % to the total oil production has been stopped dramatically in some wells.
Sidri formation exhibits a high degree of permeability, heterogeneity and increase water injection was done in some areas that lead to increase the possibility of forming scale, most of scale in Belayim onshore is calcium sulphate.
Precipitation of mixed organic/inorganic deposits (Calcium Sulfate Scale) resulted in decreasing the permeability in the critical matrix and perforation tunnels. Scale formed in the near-wellbore reduces oil production by blocking the narrow pore throats of the matrix itself
This paper highlights Petrobel first application by using the new innovation product SCSR in Belayim land field (Sidri formation), its success and results based on extensive lab studies, SCSR was tested and applied through an effective treatment strategy proposed to remove the scale efficiently; the program was designed taking into consideration the nature of the scale. Furthermore the proposed treatments were conducted and placed using coiled tubing (CT).
The Importance of Critical Flow Considerations in Understanding Jet Pump Performance: The Mangala Field
Authors: Verma Sumil Kumar , Ojha Shiv Prakash , Jha Mihir , Singh Aditya Kumar , Kefford Paul , Kumar Piyush , Tandon Rohit , Kumar Sunil , Prasad Dhruva , Singh Manjit Kumar 
Published: March 2015

Abstract:
The Mangala field, located in Rajasthan, India, is characterized by multi-Darcy sandstones, containing waxy and viscous crude oil from which most of the production is being lifted using jet pumps. This is one of the largest applications of hot water jet pumping in the world. The earlier works presented on jet pumping by the operator highlight pump screening, design, monitoring, and operational challenges (Chavan et al-2012 and Singh et al-2013).During the jet pump design work over the years, it was observed that the field results were not matching with the design particularly for wells with relatively high free gas at the pump intake. It was realized that the physics of multiphase flow in critical flow conditions was not captured fully. This paper highlights the new approach taken to model jet pumps based on the theory presented by R.G. Cunningham (ASME, JFE 1995) which explicitly captures the effect of free gas entering the pump and the onset of critical flow. The approach taken to analyze the well and jet pump performance firstly involved evaluating each part of the well independently (sand face to pump suction, flow through the jet pump, and flow from the jet pump to surface).The availability of downhole gauges in a number of the Mangala wells allowed each component of the well performance to be analyzed and validated in isolation. A final complete mathematical model of the entire well was then developed to allow predictions of the hydraulic performance of the jet pumps to be made. This paper presents the above methodology and validation of results through field trials in the Mangala wells.

Introduction:
Jet pumps are widely used as a form of artificial lift due to numerous advantages like the absence of reciprocating parts which allows tolerance of power and a viscous production fluid can be produced. Another advantage is the compactness of working section and ability to attain variation in liquid rates with minimal variation in jet pump design. Disadvantages include the cost of infrastructure associated with requirement of high pressure power fluid which needs to be pumped downhole and increase in the liquid handling capacity required at plant level.
In the Mangala field where even the downhole flow assurance of the produced crude is a challenge due to the high wax content, jet pumps provide down-hole flow assurance by utilizing hot water as power fluid. They are also very convenient to install and retrieve with no workover cost required. These features and others as mentioned by Chavan et al. (2012) led to the field-wise use of jet pumps in Mangala.
RFEC PIG Designed for Long Distance Inspection
Authors: Mazraeh Ali Ahmadian , Alnaimi Firas B Ismail , Mohamed Sahari Khairul Salleh Bin 
Published: March 2015

Abstract
This paper presents an innovative approach for the design and development of Pipeline Inspection Gauge (PIG) which can inspect pipes from 15" up to 30" with a simple change of shirts using the latest technologies such as Electromagnetic Acoustic Transducer (EMAT) sensors as well as Remote Field Eddy Current (RFEC) sensors for oil pipes inspection, through the creation of a simulation tool capable of generating simulated images from pipeline using Inertial Navigation System (INS) for highest accuracy and precision inspection to protect the environment and equipment from any unexpected accident. There are several dynamo motors utilized to regenerate green efficient power from the flow of the medium inside the pipeline to elongate the distance of investigation by the mean of reduction of the number of individual pigging processes to save time and cost for companies. The INS uses accelerometers and gyroscopes of the type "Integrated Micro Electro-Mechanical Systems" (iMEMS), to carry out the mapping corresponding to the inspected pipes. Fluid hammer effect is another factor which has been considered during designing this pig. To avoid such case to occur the design has been revised and several arms have been devised around the robot to maintain the speed and position of pig all the way through the pipeline.

Introduction
Pipelines are considered to be the safest way for transportation of large amounts of liquid and gas over large distances. Pipelines are one of the cornerstones of modern civilization constituting an essential part of the infrastructure. More than 3 million kilometers of pipelines connect the reservoirs of oil and gas, the ports of shipment, the refineries and the storage facilities today. Non-destructive testing of the pipeline system by means of in-line inspection using intelligent pigs has become an important part of this system in ensuring its safe and economic operation. In order to prevent pipeline failure, any defect that may become critical has to be detected early enough. As most of the pipelines are buried and also covered by a protective coating, a complete inspection can only be done from the inside. This is achieved with in-line inspection using automated inspection systems called intelligent pigs (or smart pigs). The ultimate goal of this type of inspection is to detect a certain type of defect with a high Probability of Detection (POD) and to provide high resolution data that allow precise sizing of the detected defects. (WILLEMS, 2008)
Intelligent pigs are automated inspection systems which are usually designed such that one inspection tool is looking for a specific type of defect utilizing one technology. Table 1 shows an overview. The main inspection methods that are used are Magnetic Flux Leakage (MFL) and Ultrasonics (UT).