bluuebunny/crossref_metadata_2025 huggingface dataset:
Fault Detection and Characterization Using a 3D Multidirectional Sobel Filter
Authors: Al-Dossary Saleh , Al-Garni Khalid
Published: September 2013

The Sobel filter is a discrete differentiation operator widely used in seismic image processing algorithms for automatic fault detection and extraction. The filter approximates the local gradient by combining derivatives of the amplitude between neighbouring traces along the x, y, and z directions. However, the approximation is not accurate in noisy seismic data. Also, in areas of steeply dipping geological faults the approximation can lead to misidentification of the faults.

To overcome these problems while also improving automatic fault detection, we propose herein a novel 3D Multidirectional Sobel Filter in which derivatives along nine non-orthogonal directions are computed, and then the direction with the largest derivative is chosen as the local gradient. This new 3D Multidirectional Sobel Filter is computationally intensive; therefore we leveraged a multi-core parallel computing design to reduce total execution time in our tests. We produced a speedup of 4x on an 8-core CPU using a 400 GB poststack seismic volume.

Tests performed on synthetic and Saudi Arabian field data demonstrate that our 3D Multidirectional Sobel Filter delineates fault and fracture distributions more effectively than the conventional Sobel filter. Moreover, our multidirectional filter is shown to be less susceptible to acquisition and processing artefacts than the conventional Sobel filter.
A Simple Method for Predicting Gas/Oil Ratio GOR of Electric Submersible Pumping ESPx Oil Wells
Authors: Salem Said K. , Osman Osman F.
Published: September 2013

Analyzing well performance is an important step toward increasing profits by improving production techniques. Among artificial lift the main factors controlling the oil producing wells are gas/oil ratio (GOR), the bottom-hole pressure (BHP) and the pump intake pressure (PIP) of the electric submersible pump (ESP). These factors are used to calculate the possible well production when choosing the appropriate pumping equipment and optimizing well performance.

There are different methods which can be used for determining (BHP) and (PIP) of electric submersible pumping (ESP) wells such as conventional pressure bomb, pressure sensors and acoustic well sounding technique. In addition, the GOR is determined only from production test by a separator. All the previous methods require a device. This requires additional money.

A new method for calculating the pump intake pressure (PIP) and the bottom hole pressure (BHP) for ESP wells has been developed using production and completion data only. Based on this method, a new procedure was established for calculating the gas/oil ratio (GOR) for electric– submersible pumping oil wells.

In this study, the value of pump intake pressure (PIP) is measured using acoustic method (measure the fluid level in the annulus) then the (PIP) is calculated by our developed method using production and completion data assuming a value of GOR, conducting many trials with different assumed GOR until matching the calculated and measured data of PIP. At this point, the calculated GOR is close to the actual GOR. The data used in this study were collected from 27 wells; these wells were selected from Western Desert of Egypt covering a wide range of variations in their reservoirs, fluid properties, and ESP assembly.

The comparison of the calculated and measured gas-oil ratio (GOR) proves good accuracy of this technique. It allows drawing a conclusion for an opportunity to use this method in oil field.
Monitoring of Downhole Corrosion: An Overview
Authors: Al-Janabi Yahya T.
Published: September 2013

Wet sour crude oil wells usually require minor attention to minimize or prevent corrosion damage of the production tubulars and well casings. These wells contain, in addition to crude oil, water, salt, and variable quantities of hydrogen sulfide (H2S) and carbon dioxide (CO2). In this paper, an overview of downhole corrosion is presented. This includes corrosion mechanisms, corrosion monitoring techniques, corrosion inhibition, and field applications along with examples. The main mechanisms contributing to downhole corrosion are classified into electrochemical, chemical and mechanical. Chemical corrosion attack is one of the major players in the case of maturing wells. Relevant corrosion monitoring techniques are then discussed. These techniques provide either direct or indirect measurements of corrosion rates (CRs). In case of existing wells, a basic downhole corrosion monitoring program should include the following techniques as a minimum: (a) wet chemical analysis, e.g., iron counts, (b) metal loss corrosion coupons, and (c) electronic corrosion probes, e.g., electrical resistance (ER) probes. The three common corrosion control strategies are briefly discussed, namely: materials selection, coatings, and chemical inhibition. Finally, three examples of field applications are presented. In these examples, different corrosion monitoring techniques were employed depending on the type of corrosion mechanism and the selected corrosion control strategy.
Systematic Approach Significantly Reduced Wet Gas Venturi Metering Inaccuracies in Saudi Arabian Gas Producers
Authors: Al-Dhamen Mohammad , Leal Jairo , Villegas Ruben , Bolarinwa Simeon , Awadh Aqeel
Published: September 2013

The need to accurately meter gas and liquid rates from gas producers in a cost-effective way is of high importance to be able to properly manage Reservoir development and maintain optimum well performance. Inaccurately metered data can lead to poor field development decisions, wrong gas allocation and gas reserves estimation, unnecessary surveillance, and high operating expenses.

As part of a strategy designed to provide maximum operational flexibility while containing capital expenses, Saudi Aramco installed Venturi meters in the majority of its gas producers following a comprehensive review which indicated that the technology was suitable for the operating conditions of the wells. However, as the gas development program has consistently expanded, and the range of the operating condition of the wells broadened, it has been observed that the accuracy of the measurements collected from the venturi meters has continued to decline.

This paper details a systematic approach implemented in the northern sector of the Ghawar gas field to first ascertain the causes of the problem and then find an adequate solution. Details about a completed and comprehensive study involving gas producers with a wide range of condensate ratio, the main problem causes that were identified, the actions taken to reduce the inaccuracy of the gas readings close to the current 10% level, and detailed recommendations are included in this paper.
Core Acquisition from a New Sidewall Rotary Coring Tool: Overview and Experience from Saudi Arabia
Authors: Siddiqui Aamir , Al-Algam Wafi , Nuic Ivo
Published: September 2013

Detailed reservoir characterization is the main objective of all petrophysical measurements. The information obtained from petrophysical logs and well testing measurements is integrated with core-based sedimentological studies and core analysis measurements. Core-based information is crucial in the exploration phase of a field because it enables an extensive understanding of the reservoir rock potential. To reduce the operational time and cost, conventional full-core acquisition programs are often curtailed and operators rely on sidewall coring. Rotary sidewall cores provide accurate depth-controlled core plugs in various lithologies in a quicker and cost-effective way.

A new rotary sidewall coring tool has been utilized in Saudi Arabia that enables recovery of high-quality core plugs even from small-sized boreholes. The acquired core plugs have sufficient size for use in conventional and special core analysis, and petrographic studies. The capability to recover up to 60 samples in a single trip enables good coverage of the different lithologies during one acquisition. The core acquisition time per sample is significantly improved over previous generation tools, thus enabling a significant reduction in coring operation time. In addition, the ability to obtain 60 samples in one run enables operators to modify their core-acquisition programs, as sidewall cores provide a good alternative if conventional core programs are not properly executed.

This paper reviews experience and examples where rotary sidewall cores were obtained from several clastic and carbonate formations from different fields in various locations within Saudi Arabia. The operational environments and borehole conditions in which sidewall cores were obtained were exceedingly heterogeneous. These cases include very hard sandstones, mixed sand and shale layers, and limestone to dolomitic carbonates.
Study of Polyacrylamide/Cr III Hydrogels for Conformance Control in Injection Wells to Enhance Chemical Flooding Process
Authors: Hassan Saleh F. , Han Ming , Zhou Xianmin , Krinis Dimitrios , Zahrani Badr
Published: September 2013

This study is to increase the efficiency of chemical injection by reducing the injectivity in high permeability zone, especially fractures or super-K zones, which are inevitably encountered in carbonate reservoirs. A chemical gelant system in liquid composed of polymer and crosslinker will be introduced in injection wells and form semi-solid gels in the formation. This technique will divert the successively injected fluids (chemical solution) into unswept formation and ensure the success of a chemical EOR process. A polyacrylamide/Cr (III) gel system was studied in terms of sol/gel diagram, kinetics of the gelation, viscoelastic properties of gels with the help of oscillatory shear rheometer, and long-term stabilities with a measure of syneresis. The lab results present excellent performance at the conditions of a carbonate reservoir. A core flooding test was conducted to identify plugging capacity with disproportionate permeability reduction to brine and to oil. Results confirmed a successful application of gelant system as conformance control agent for a carbonate reservoir.
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

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

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

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

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

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

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

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

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

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

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

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

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.
Hydraulic Fracture Geometry Evaluation Using Proppant Detection: Experiences in Saudi Arabia
Authors: Bartko Kirk , Salim Ahmed , Saldungaray Pablo , Kalinin Daniel , Han Xiaogang , Saldungaray Pedro
Published: September 2013

Accurate determination of the propped fracture geometry compared to the stimulation design can help fine-tune geomechanical models and to optimize future hydraulic fracture treatments. Conventional methods to evaluate fracture height with logs use radioactive tracers pumped downhole together with the proppant. Subsequently, natural gamma ray spectroscopy logs are run to detect the tracers; however, safety and environmental concerns, together with regulations regarding transportation, storage and use of radioactive materials, can limit the use of these tracers.

Newly developed proppant techniques allow detection without the need of using radioactive elements. Special compounds coat the substrate or are mixed with the proppant material. These interact with neutron logs, making it possible to evaluate the propped fracture height, and in certain cases, have a qualitative idea of the fracture width. Two approaches used by major proppant manufacturers consist of: (a) compounds that are activated by a neutron source, and (b) compounds that absorb neutrons (high capture cross section) and can be detected using conventional compensated neutron logs (CNL) or pulsed neutron capture (PNC) tools. Both PNC and CNL have a shallow depth of investigation, only a few inches away from the borehole, and therefore they indicate the propped fracture height in the near-wellbore region providing a first estimate where the proppant is placed.

This paper will present the results of the neutron absorbing approach under challenging conditions in dual casing strings in wells located in the northern area of Saudi Arabia. The methodology applied uses a comparison of pre-fracture log count rates and post-fracture count rates, with reduced post-fracture count rates observed in zones containing proppant, using both CNLs and PNC tools. The experience has provided information about the sensitivity of each logging device and allowed the comparison to other methodologies (temperature logs) and the formulation of recommendations.
First Application of Limited Entry Multistage Matrix Acidizing in Saudi Arabia’s Deep Gas Development Program – A Case Study for Improved Acid Stimulation and Placement Techniques
Authors: Ahmed Mahbub , Habbtar Ali , Al-Malki Bandar , Rahim Zillur , Al-Anazi Hamoud , Al-Kanaan Adnan , El-Mofty Wael , Bukovac Tomislav
Published: September 2013

Among the various design and operating parameters, efficient acid stimulation in deep carbonate reservoirs depends on the placement technique, injection profile and treatment composition. Unlike acid fracturing, matrix acidizing creates several conductive flow channels with substantially higher conductivity compared to the reservoir rock. These conductive channels transport reservoir fluids from the formation matrix directly into the wellbore overcoming both low permeability and near wellbore damage. The treatment composition, and more importantly, the injection technique to maximize the number and depth of penetration of these conductive channels, are among the most predominant design criteria of successful carbonate matrix acidizing especially in a high-pressure and high temperature environment.

The Permian Khuff carbonate reservoir in the Ghawar structure of Saudi Arabia produces nonassociated gas and condensate. The reservoir is characterized by heterogeneous porosity and permeability distribution extending in both areal and vertical directions with varying in-situ stress contrast along the structure extension. Due to the reservoir complexity, each well requires individual assessment to determine the optimum completion design necessary to achieve efficient matrix or fracture acidizing treatment. Some wells may need simple matrix acid treatment, while other wells may need open hole multistage (OHMS) fracture stimulation. Results demonstrate that OHMS completion was required to successfully stimulate all net pay intervals.

This paper presents an overview of Saudi Aramco’s efforts to evaluate various stimulation methods used in the Khuff reservoir and highlights an optimal carbonate stimulation technique for certain reservoir conditions via the first trial test application of a limited entry OHMS completion for effective stimulation. The technique uses a system that is designed to run as part of the production liner and provides mechanical diversion at specified intervals, thereby allowing multiple matrix acidizing treatments to be effectively placed in the target zones. The technique was applied recently for the first time in Saudi Aramco’s gas program and the details are discussed in this paper.
Design and Evaluation of Hydraulic Fracturing in Tight Gas Reservoirs
Authors: Murtaza Mobeen , Al Naeim Sami , Waleed Asmar
Published: September 2013

As the increasing demand of gas to support the industrial boom grows in the entire world, the unconventional, in particular, extremely tight gas reservoirs are playing significant role. However, the exploitation of these tight resources is still an economical and technical challenge, which can be dealt with the incisive use of current resources. Effective hydraulic fracturing techniques are the only solutions that make the development of these resources economical. This paper is concerned about the method of fracturing treatment design, economical evaluation, candidate selection, and fracture economic optimization. Finally, the detailed financial analysis of fracture job with net production increase is used to select the best stimulation solution for tight gas reservoirs. Moreover, the paper will serve as a good source of information to gain better understanding of hydraulic fracturing design to maximize the economics of tight gas reservoirs.
Mechanical, Rheological and Microstructural Properties of Saudi Type G Cement Slurry with Silica Flour Used in Saudi Oil Field under HTHP Conditions
Authors: Murtaza M. , Rahman M. K. , Al-Majed A. A. , Samad A.
Published: September 2013

With the continued growth of petroleum demand, the oil and gas companies are searching in new or unexplored areas. The search is getting extreme in terms of depth, temperature and pressure. In deeper wells, high temperature and pressure and post cementing operations put extreme stresses on the cement sheath and affect the integrity of the cement. In such conditions, the design of cement slurry is very critical and it must possess properties which ensure the durability and long term integrity of cement sheath.

The purpose of this study is to evaluate the physical properties of Saudi cement class G with silica flour and admixed with different additives such as fluid loss agent, retarder, expanding agent and friction reducing agent under high temperature and pressure conditions. In this paper, we present the results of experimental investigations conducted on class G cement slurry without additives, as a basis, and cement slurry with additives and silica flour. Free water separation, rheological properties, compressive strength, density, scanning electron microscope (SEM), X-Ray diffraction (XRD), porosity and permeability tests were conducted with and without additives at both room and HTHP conditions.
Emerging Technology Transformed the Development of Thin/Tight Layers in a Giant Middle Eastern Field
Authors: AlGhamdi H. M. , ElHayek S. O. , AlHutheli A. H.
Published: September 2013

This paper discusses the successful development of thin/tight layers in a Middle Eastern field with a production history of more than 50 years supported by peripheral water injection. The reservoir is characterized as a carbonate formation and consists of four major layers, namely 1, 2, 3 and 4. Layers-2 and 3 constitute the main reservoir body and are the most prolific layers.

Layer-1, which is the focus of this paper, exposed to production using vertical wells, was not contributing due to its limited thickness and low reservoir quality compared to the other layers.

With the advancement in drilling and geosteering accurate well placement became a reality. Therefore, a multidisciplinary team proposed a pilot well targeting Layer-1 alone to exploit its potential. This pilot was an existing producer in an area where layers-2, 3 and 4 were swept and Layer-1 remaining oil saturation showed the most developed porosity thickness in the field. A geological model was built to evaluate various scenarios to ensure good planning and successful well placement. A proactive geosteering tool was exploited to confront well placement challenges. As a result, the well was drilled with 100% reservoir contact. Post-sidetracking performance was encouraging and opened new opportunities to develop this layer.

This achievement sets the beginning of a new milestone to improve recovery in this field. This paper discusses three major aspects related to this achievement. First, it highlights the pre-assessment of the target location. Also, it discusses the geosteering technology that was utilized to maintain the entire horizontal section across the target layer. Finally, it presents the production performance after the well re-completion.
Advanced Visualization for Reservoir Simulation
Authors: Al-Harbi Badr , Al-Darrab Abdulaziz , Al-Zawawi Ahmed S. , Al-Zamil Khalid
Published: September 2013

This paper provides an overview of an advanced visualization system for visualizing giga-cell simulation models to assist Reservoir Engineers in managing and developing Saudi Arabia’s giant fields. The challenges in the hydrocarbon industry require the use of the latest technology to maximize recovery in a cost-effective manner. Over the last few years, reservoir simulation activities have undergone major transformation toward the use of giga-cell simulation models [1]. This transformation stems from the use of advanced data acquisition solutions and advanced modeling packages to capture and model physically large fields. Fine scale-grid blocks capture detailed description of geologic heterogeneity that is necessary to model the complexity of fluid flow in the subsurface. Giga-cell simulation models are currently generated using Saudi Aramco’s GigaPOWERS parallel reservoir simulator [2]. The size of reservoir simulation models continues to grow to exceed the billion-cell barrier.

The design of a high performance computational platform for simulation of giant reservoir models has been discussed in other literature [3]. In this paper, we focus on the simulation post-processing visualization system developed, which consists of advanced technologies for handling and visualizing massive amounts of data. Implemented techniques include: Remote visualization utilizing graphics processing clusters, parallel data loading, level of detail graphics rendering and hierarchal multi-resolution data structure. In addition, a number of advanced visualization features that have been implemented are highlighted in this paper, such as the ability to display fluid patterns in the field by utilizing streamlines and vector fields, advanced volume visualization techniques based on streamlines and wells filtering to help engineers better understand the fluid flow in subsurface reservoirs. Furthermore, the performance considerations, challenges and impact on reservoir simulation studies are also discussed.
Phase Behavior and Interfacial Tension Properties of an Amphoteric Surfactant for EOR Application
Authors: Fuseni Alhasan , Han Ming , Al-Mobith Adel
Published: September 2013

Amphoteric surfactants are known for their tolerance to salinity and temperature and are considered as likely candidates for enhanced oil recovery (EOR) application in harsh reservoir environments. This study looked into the phase behavior properties of an amphoteric surfactant, OCT-1 and its interfacial lowering capability over weeks. The surfactant concentrations used ranged from 0.05 to 0.5% active and phase behavior studies were conducted with seawater of salinity 57,000 ppm and crude oil at a reservoir temperature 90°C.

Interfacial tension measurements showed that this surfactant is capable of lowering oil-water interfacial tension (IFT) considerably at low surfactant concentrations. Surfactant concentrations of 0.05% and 0.1 % were able to achieve lowest IFTs till a week into the study. Thereafter, only the 0.2 % concentration was able maintain a low IFT till three weeks. A measurement of surfactant concentrations showed that the aqueous phase surfactant concentration stayed much stable for all surfactant concentrations. An examination of photomicrographs revealed that a tiny amount of the oil partitioned into the aqueous phase enhancing the IFT lowering capability of the aqueous phase at these low concentrations.
A Novel and Cost-Effective Clay Control Approach in Water-Sensitive Sandstone Gas Reservoir of Saudi Arabia During Proppant Fracturing Treatment
Authors: Malik Ataur R. , Ghamdi Abdulwahab H. , Senturk Nejla H. , Leal Jairo A. , Atwi Mohammed A. , Soriano Eduardo
Published: September 2013

Clay swelling, dispersion and migration due to water-sensitive clay minerals in the producing formation can substantially reduce rock and retained proppant permeability resulting in reduced well productivity. The effects of water-based fracturing fluids in water-sensitive formations have been extensively investigated which led to development of different types of clay stabilizers based on type of clays, bottomhole temperature, and clay protection time. The use of KCl or NaCl brine up to concentration of 6% is well known clay stabilizing method for swellable and migratory clays during the stimulation treatment.

However, using high salt content brines have some limitations and constrains. The performance of crosslinkers (Borate or Zirconium) and breakers are often affected when using high salt concentration in the base fracturing fluids. The sandstone formations of Saudi Arabia have been reported to be "water-sensitive" and can be easily damaged by fresh water. A novel clay stabilization liquid additive has been successfully introduced as a substitute to inorganic salts in fracturing fluids for sandstone formation in Saudi Arabia. This new permanent clay control additive is cationic polymer with ultra-low molecular weight (PC-4) and compatible with borate and zirconium crosslinkers. It also reduces safety concerns and operational time by eliminating handling and mixing of huge amount of salts on location.

This paper provides details on lab testing, and field implementation of the novel cost effective clay control additive in HTHP sandstone gas well during proppant fracture treatment.