bluuebunny/crossref_metadata_2025_split huggingface dataset:
Frequency Dependent Magnetic Resonance Response of Heavy Crude Oils: Methods and Applications
Authors: Kurup Arjun , Valori Andrea , Bachman H. Nate , Korb Jean-Pierre , Hürlimann Martin , Zielinski Lukasz 
Published: September 2013

Abstract
Oilfield nuclear magnetic resonance (NMR) applications are widely accepted for characterizing reservoir rocks and fluids. All of the downhole applications, and most oilfield NMR lab work, are carried out assuming that the results are independent of the operating frequency. The assumption is generally warranted, since most NMR logging tools and lab devices operate in the 0.5 to 2 MHz range. However, two strong motivations exist for investigating the frequency dependence (that is, dispersion) of NMR of crude oil samples: 1) introduction and acceptance of lower frequency logging while drilling (LWD) and multi- frequency wireline NMR tools, and 2) sensitivity of NMR dispersion to the interaction and dynamics of molecules of varying size in complex fluids.
We report here on a versatile frequency-dependent lab NMR measurement known as fast field cycling (FFC) NMR. The results clearly demonstrate a frequency dependence of the longitudinal relaxation time, T1, for crude oils between 10 kHz and 40 MHz. The study investigates the full T1 distributions for crude oils containing significant amounts of all the SARA (saturates, aromatics, resins, asphaltene) fractions, including a broad range of concentrations for the heavier fractions. For crude oils containing minimal asphaltene and resin fractions, the dispersion is minimal. In contrast, crude oils containing larger concentrations of asphaltene and resins show a clear shift of the T1 distribution to longer times at higher frequencies.
We will discuss the implications and benefits of NMR dispersion for oilfield application. We suggest how the dispersion can be understood in terms of the molecular dynamics of asphaltenes with the rest the oil. Finally, we will provide an overview of the experimental challenges in making these measurements, including the hardware design and the specialized pulse sequences required for acquiring multi-frequency data.
Fit for Purpose Underbalanced Coil Tubing Surface Equipment Permits Safe Drilling of High H2S Horizontal Gas Wells in Saudi Arabia with Higher Productivity Results
Authors: Khamees Shaker , Ali Mohammed , Marey Ayman , Valecillos Juan C. 
Published: September 2013

Abstract
This paper describes the underbalanced drilling (UBD) surface package used in the Saudi Aramco underbalanced coiled tubing drilling (UBCTD) project. A brief description on each item of this equipment is presented, as well as a description of the overall process flow. Moreover, the evolution and modification of the package throughout the period of the project and the optimization of the equipment to meet new challenges and to overcome some drilling hazards, such as erosion and high H2S levels, is discussed.
The objective of the project is to drill reentry horizontal lateral sections in a hole size of 3⅝" with coil tubing (CT) using the UBD technique specifically the "Flow drilling" technique to increase the hydrocarbon’s productivity without damaging the formation, increasing the rate of penetration (ROP) and eliminating risk of losses or wellbore instability.
The UBD surface equipment used for the UBCTD project was designed to handle maximum allowable rates to drill the well within safe limits. The equipment were selected and designed on the basis of historical data gathered from offset wells in the same specific field.
The main focus in this paper will be on the lessons learned throughout the period of the project regarding the UBD surface equipment, which was specially built for this project.
Pressure Drop Reduction of Stable Emulsions: Role of Aqueous Phase Salinity
Authors: Al-Yaari M. , Hussein I. A. , Al-Sarkhi A. , Abbad M. , Chang F. 
Published: September 2013

Abstract
Emulsified acids are a common matrix treatment method for carbonate plays. High frictional pressure losses limit the rates at which these fluids can be pumped especially in small diameter or coiled tubing. A method to effectively reduce friction factor will positively impact pump horsepower needed to place the treatment. This experimental study investigates the role aqueous phase salinity has on frictional drag of emulsions at different pipe diameters.
Flow loop experiments were conducted to study the effect of aqueous phase salinity on the flow characteristics of surfactant stabilized emulsions with volumetric oil to water ratio of 30/70. The emulsions' stability, type, droplet size distribution, shear dependent viscosity and interfacial rheology measurements were correlated to pressure drop measurements in a flow loop consisting of 1-in and 0.5-in horizontal pipe diameters at constant (ambient) temperature.
At low aqueous phase salinity (≤ 10 kppm), oil-in-water emulsions were created and emulsion stability decreased with increasing salinity. Conversely, water-in-oil emulsions were produced and emulsion stability increased as the salinity increased at high aqueous phase salinity (≥ 20 kppm). In addition, the results showed a significant reduction in emulsion viscosity as well as pressure drop, in both pipe diameters, with decreasing water salinity, especially for water-in-oil emulsions (salinity ≥ 20 kppm). These results were explained in terms of droplet size distribution as well as interfacial rheology.
Characterization of Shale Gas Rocks Using Dielectric Dispersion and Nuclear Magnetic Resonance
Authors: Almarzooq Anas , AlGhamdi Tariq , Sassi Khaled H. , Badri Mohammed 
Published: September 2013

Abstract
Shale gas has become a significant resource play in the USA over the past few years, and oil companies are now evaluating the shale gas potential of many sedimentary basins. The successful development of these shale gas systems has led to a strong exploration campaign in Saudi Arabia to investigate its several onshore basins. These "shales" have complex and varying mineralogies and require intensive petrophysical analysis to determine even basic characteristics. The renewed focus on rock sequences has necessitated the development of workflows and methods for characterizing these shale rocks. With the deployment of new methods comes the need for interpretation frameworks to understand properties from diverse measurements. We investigated the use of two techniques, the dielectric dispersion technique and nuclear magnetic resonance (NMR), as potential tools for systematic shale characterization and examined their applicability to reservoir evaluation in shale plays.
Dielectric properties were measured on a suite of shale gas rock samples selected from several wells across the Silurian source rock formation. The frequency range of 10 MHz to 1 GHz covers the different polarization types of the electric field within the rock samples. The dependence of minerals in the shale-gas rocks on the interpretation of the dielectric response was studied. The dual-range Fourier transform infrared (FTIR) technique was used to accurately quantify the mineralogical composition of the studied samples, including pyrite. Pyrite has an obvious effect on the dielectric responses, and an accurate estimation of its volume is crucial for an enhanced interpretation of the dielectric response. The dependence of the effective matrix permittivity to the shale-gas minerals was well investigated in this work. A workflow was developed to accurately estimate the effective permittivity of the rock matrix to enhance the estimate of water volume from the dielectric response. The high-resolution retort was also used for the quantification of water content, and the results were compared to the water saturations from dielectric dispersion. NMR T2 was also measured on the selected shale gas rock samples using very short echo spacing to capture all the inorganic and organic porosity at the nanometer scale. An accurate estimation of total porosity from NMR and total water content from dielectric dispersion enhances the estimation of the total gas in place of the shale-gas rocks.
Integrating PLT Data with Well Centric Modeling to Detect Packer Leakage and ICD Plugging – A Case Study
Authors: Al-Rabeh Majed , Lee Byung 
Published: September 2013

Abstract
A well completion diagnostics methodology was developed in order to detect downhole packer leakage and plugged Inflow Control Devices. This methodology was based on integrating production logging tool (PLT) data with computerized ICD well centric modeling to identify packer leakage and plugged ICD’s in compartmentalized completions. This approach was implemented on several oil wells with the objective of trial testing new zonal isolation technology and to optimize oil flow from the different ICD modules. Optimization is achieved by identifying and solving problems such as packer leakage which negatively affects the performance of oil wells by preventing the isolation of water downhole increasing the water cut of the produced oil. It also identifies ICD plugging which introduces mechanical skin that reduces or completely prevents oil production in the corresponding plugged ICD modules.
The diagnostics method described in this paper utilizes direct comparisons of ICD well centric modeling with actual production logging data and openhole formation logs to identify abnormalities within the ICD completions. The resulting information obtained is valuable and can be used in trial testing new packers to gauge their sealing ability in downhole conditions and is also useful in identifying areas of potential improvements within the completion.
The implementation of this approach on several Saudi Aramco oil wells resulted in confirming the sealing ability of various mechanical and swell packers in addition to downhole constrictors. Furthermore, a potentially plugged ICD was identified for possible future remedial treatments to restore production.
The significance of the subject matter is that it offers the petroleum industry a systematic approach to identify packer leakage or potential ICD plugging. Such an approach is needed to ensure that equipment being run downhole is functioning as per the design. Otherwise, ICD plugging or packer leakage can be identified for possible work over operations.
Integrated Technologies Yield Five Years of Excellent Performance: A Unique Field Case Study
Authors: Ukaegbu Orji O. , Alyan Essam M. 
Published: September 2013

Abstract
The paper covers a story of field that was brought on production using a combination of industry leading edge technologies; maximum reservoir contact (MRC) multi-lateral wells; advanced well completions and intelligent field infrastructure. Though individual components of the technologies had been tested and proven but the combination of these technologies in one development made this field to stand out as among the firsts in the industry. This feat came with peculiar challenges and rewarding opportunities.
This article undertakes an assessment of the field, the wells and the technologies; following five years of production. The article discusses a unique case study detailing real time field and wells performance monitoring, management and production optimization. The experience from this field has provided unique knowledge and insight to better understand how the advantage of these technologies were nurtured and leveraged to take performance to the next level. During the five years of production, this field has been meeting or exceeding the fundamental field Key Performance Indices (KPIs) such as production targets, sweep efficiency and well potential. Moreover, the intelligent field infrastructural environment has made possible proactive real-time reservoir management leading to more efficient operations and result-oriented business work flows.
A Successful Field Application of a New Chemical Treatment in a Fluid Blocked Well in Saudi Arabia
Authors: Al-Yami A. M. , Gomez F. A. , AlHamed K. I. , Al-Buali M. H. 
Published: September 2013

ABSTRACT
A successful trial of the Gas Well Stimulant WS-1200 was recently completed on a gas well with high Condensate-Gas Ratio (CGR) and producing below the dew point to treat fluid blockage in Saudi Arabia. The treatment consisted of pumping from a surface 2 wt% active solution in common organic solvents that solubilizes and/or displaces the brine and condensate that are present in the near wellbore region of a fluid blocked well. After bullheading the treatment into the well, it was chased with two equivalents of nitrogen gas. The well was shut-in over night for the treatment to react and then the well was opened to flow and clean out. A test separator was connected to measure the flow at surface and compare the flow after the treatment. Several days were required after opening the well to back-produce the solvents and evaluate the well through the test separator until stabilization was acquired. The well was put back online and continued monitoring production for several months. Just prior to injection of the chemical treatment, the well was producing ~1.5 MMSCFD and ~275 BOD. Within five days of concluding the injection, the well was producing ~2.7 MMSCFD and ~1,000 BOD and in an increasing trend. The well was left in production with only the wellhead temperature (WHT) and wellhead pressure (WHP) being monitored on an ongoing basis. After three months of production, the well rate was again measured through a separator at similar conditions and found to be ~2.85 MMSCFD and ~1,152 BOD, a sustained improvement of 83% in gas production and a 313% improvement in oil production. In light of initial encouraging results, similar chemical treatments are planned in other sandstone reservoirs with similar problems.
Synthesis and Performance Evaluation of Date Pit Based Surfactant-Polymer Formulation for Enhanced Chemical Flooding
Authors: Adewole Jimoh K. , Sultan Abdullah S. 
Published: September 2013

Abstract
Abstract
Chemical flooding is one of the enhanced oil recovery (EOR) techniques that is used to prolong the lives of oil reservoirs. In this paper, the synthesis of date pit based polymers solution and its adaptability in surfactant – polymer flooding technique were investigated. Date seed from the eastern province of Saudi Arabia were washed by sonication and sun dried. The dried seeds were ground and de-oiled using hexane in a Soxhlet apparatus. The de-oiled powder was dissolved with aqueous sodium hydroxide solution to form date pit polymer (DPP) solution. The properties of the solutions were investigated by evaluating change in their rheological properties with temperature (40 – 110 °C) and aging period. Also, the viscosity enhancement capability of DPP in the surfactant – polymer formulation was evaluated.
The results obtained showed a saturated solubility range of 0.5 to 3.7 wt % of the solution, a yield between 23 and 69%, and viscosity range of 2.5 to 22cp at about 33°C. The optimum viscosity is about 22 times higher than the viscosity of the blank NaOH solution which is about 1.08cp at the same temperature. The viscosity modification property of the polymer was maintained up to a temperature of 80 °C. At 100 °C, the viscosity of the samples with 3.29wt% DPP dropped from 2.8 to 1.07cp which is about the same viscosity of that of the blank alkaline (NaOH) solution that was used as solvent. Thus, DPP can be utilized as viscosity modifier to alter the mobility ratio in enhanced oil recovery processes. However, more studies need to be done to find a better chemical modification route that can be used to improve the yield. Higher yield is expected to give polymer with higher viscosity. DPP application may be limited to light crude oil recovery and it can be used as blend with other high viscosity polymer to improve their performance. Accordingly, future work will be focused on detailed investigation of better chemical modification method. It is expected that this research will benefit the industry by serving as an eye opener into the possible exploration of the use of local raw materials for upstream operations in the oil and gas industries.
Integrated Reservoir Management Approach to Improve Injection Efficiency in a Low Transmissibility Sector of a Giant Carbonate Reservoir
Authors: Benedek Lajos , Almajid Muhammad , Alhuthali Ahmed H. 
Published: September 2013

Abstract
This paper provides a critical review of the integrated reservoir management process implemented to maximize ultimate recovery by maintaining an optimum reservoir pressure distribution in a low transmissibility sector of a giant carbonate reservoir. The peripheral water injection is the main driving mechanism in this reservoir due to the excellent areal transmissibility from the flanks towards the center of the reservoir. However, the study area is limited and characterized by a various degree of low transmissibility due to the degradation in reservoir quality and the presence of a tar mat at the flanks. The main challenge is to provide an adequate pressure support far away from the peripheral injection line and to sustain the required production capacity from the study area. Conventional peripheral water-flooding is insufficient to meet the ever increasing production capacity without an optimized injection set-up consisting of up-dip and down-dip peripheral injectors.
The study demonstrates that cohesive understanding of the flow mechanism, which entails integration of various sources of information, is crucial to achieve successful pressure maintenance and voidage replacement schemes. Consequently, detailed characterization of the tar region was constructed through multiple realizations covering the entire spectrum of uncertainties and impacts on reservoir performance. The injection efficiency over various production scenarios was also carried out using finite-difference and streamline tracing to capture the interaction between producers and injectors. In addition, a coupled subsurface-surface integrated modeling was utilized to identify bottle-necks and evaluate development options.
Production performance and acquired reservoir surveillance data vindicated the implemented practices. Optimum reservoir pressure distribution was observed over the entire study area. Conventional and advanced open-hole log results from strategically placed evaluation wells and time lapses of saturation logs from key monitoring wells over a 5 years period indicated favorable areal and vertical sweep efficiency.
Energy Savings From the Stabilizer Bottom Pump — A Success Story From Khurais Central Processing Facility
Authors: Khan Ashiff , Saif Ahmad M. 
Published: September 2013

ABSTRACT

Khurais Central Processing Facility Overview
The geographical location of the Khurais Central Processing Facility (KhCPF) is around 250 km southwest of Dhahran, where Saudi Aramco’s headquarters are located. KhCPF were commissioned and started in May 2009.
The gas-oil separation plants (GOSPs) of KhCPF consist of four parallel 25% capacity processing trains. The GOSPs in the KhCPF are designed to produce 1,263 MBOD of stabilized dry Arab Light (AL) crude oil, which is routed to the crude export pipeline during normal operation.
Practical Well Testing Analysis Considerations in Heterogeneous Sandstone
Authors: Al-Zayer Ahmed , Mesdour Rabah , Al-Faleh Khaled , Basri Mustafa , Utaibi Abdullah 
Published: September 2013

Abstract
Declining reserves in conventional gas reservoirs, high energy demand and the evolution of technology are all encouraging oil and gas companies to consider the feasibility of exploiting large reserves trapped in heterogeneous and tight gas reservoirs. In general, successful results in tight gas depend on identifying the sweet spots as well as an efficient hydraulic fracturing treatment for it to be commercially viable. Nevertheless, in order to evaluate the success of the stimulation job, the reservoir and hydraulic fractures properties need to be quantified. The pressure build-up analysis is a classical tool that is widely used in the petroleum industry to gain more insight into the reservoir by studying the pressure variation before and after stimulation. In order to be able to determine skin and reservoir flow capacity, the reservoir must reach infinite acting radial flow, which is characterized by a flat stabilization on the pressure derivative.
This paper highlights some of the extensive pre and post stimulation pressure build-up results on heterogeneous and tight gas Sarah sandstone found in the northwest of Saudi Arabia. The analysis shows different behaviors in terms of reservoir response between a series of build-up in different conditions including openhole, cased hole and post-stimulation test analysis on the same well. A systematic approach was used to connect between these responses using integrated reservoir data.
Utilizing Chelating Agent System Fluid to Remove Scale Buildup from Stuck ESP Shaft in Offshore Saudi Arabia
Authors: Al Zahrani Ahmed R. , Al Shinaiber Fahad A. , Al Omairen Khalid I. , Nuriakhmetov Ruslan , Gurmen M. Nihat 
Published: September 2013

Abstract
Saudi Aramco’s first offshore field produced by electrical submersible pumps (ESPs) has completed a nine year operating cycle, sustaining the field production rate with an acceptable ESP run life in most cases. Recently, a well in this field has experienced a stuck pump shaft shortly after installation. In the past, similar failures in the same well had led to ESP replacement through workover operations. To avoid the same outcome, an effort was initiated to regain operation of the ESP stuck shaft, and realize the production target without a workover.
After the first failure, a scaling tendency analysis exhibited this well to have tendency for carbonate scaling. The Dismantle Inspection and Failure Analysis (DIFA) and laboratory testing of samples taken from the pump stages confirmed the presence of predominantly calcium carbonate scale. The impellers and diffusers of the ESP pump were discovered to be totally blocked with solid precipitation, which had been the cause of frequent pump trips and decreasing production rate. Using parts from the third failed ESP, a chelating-agent-based treatment fluid was designed to dissolve the scale buildup in the stuck ESP shaft without adversely affecting the tubular and downhole equipment. After the treatment, to avoid the reoccurrence of pump failure, scaling indices and thermodynamics of the scale precipitation tendency of the formation water associated with its crude stream were studied. Results indicated that scale inhibitors, such as polyacrylic acid (PAA) or polyphosphinocarboxylic acid (PPCA), bullheaded into the formation may be used to control scale in this well in the future.
With a stuck pump shaft, this well would normally have been worked over to replace the ESP, thereby consuming 10 days of rig time and sustaining potentially avoidable production losses. The goal of the project was to remove the scale accumulation, regain operation of the stuck ESP shaft, and reestablish the production of 5 MBOD. Consequently, a costly workover was avoided and the life of the ESP was increased without compromising the completion. The successful treatment for this stuck ESP shaft, which was carried out by bullheading the treatment fluid is a reference treatment design for similar cases. The history of the well, laboratory studies, and recommendations to avoid scale precipitation in the future are detailed.