bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evolution of Limited Entry Multi Stage Stimulation Completion Technology for Improved Acid Stimulation in Tight Carbonate Reservoirs
Authors: Rodoplu Rasim Serdar , Abdulaziz Ahmad Azly , Malik Ataur R. , Gardiner Colin 
Published: October 2018

Abstract
Acid stimulation is an excellent method to increase hydrocarbon production and long-term formation drainage from carbonate formations. However, the stimulation effectiveness largely depends on pertinent placement method. Besides the necessity for optimized treatment design and fluid recipe, homogenous acid distribution is one of the most critical aspects for treatment success. For this purpose, a novel completion method has been deployed that allows for effective acid stimulation by maximizing formation contact in the openhole horizontal wellbore.
An improved Multistage Stimulation System (MSS) that has been developed to distribute acid homogenously across the lateral is utilized, where multiple sleeves are deployed in clusters as part of a single stage, and opened with a single size ball without being limited to pump rate. It was considered imperative to have positive indications of the balls landing on the seats and the sleeves being shifted open within the zone of interest. The previous MSS system was based on severing part of the nozzles for fluid access which needed to be upgraded for better operational efficiency and production enhancement.
The new completion technology is suitable for carbonate formations which are tight, heterogeneous and require stimulation to improve gas production and recovery. Wells drilled in the maximum horizontal stress direction to mitigate hole stability risks and geosteered to maximize the formation contact makes it difficult to stimulate effectively. Therefore, an improved MSS system is required to homogenously distribute the acid across the lateral during the stimulation. This novel MSS completion design was undertaken standardized, well established trial test procedure and was applied in a candidate well and included three stages where two of the stages utilized four sliding sleeves while the remaining stage was integrated with five sliding sleeves. Each stage was isolated by hydro-mechanical packers in the 5.875 in openhole.
Each stage was then monitored using a new surface mounted real-time downhole monitoring system, an electronic device that enables live verification of completion operation events while being independent of pressure. The data gathered from different sources indicated that the sleeves functioned as per design. The production results exceeded the expectations.
This paper describes a novel approach that enhances acid stimulation effectiveness and fulfills stimulation objectives using advanced openhole MSS completion technology. Evolution of the technology and comparison with its predecessor is discussed. It also demonstrates the use of a new surface monitoring system that supplies real time data during sleeve activations enabling clear and accurate detection of downhole events.
Development of low density rigid gels/composites for ESP packer penetrator protection
Authors: Zhao Weishu , Huang Jin , Zoraia Ghanem H. , Xiao Jinjiang 
Published: October 2018

Abstract
Electric Submersible Pumps (ESP) are commonly used artificial lift equipment in production wells. The ESP packer penetrator system is designed to carry the electric power cable that connects the electric motor in ESP to the surface control panel. Various chemicals downhole make up highly corrosive and hostile environments to the metal wires and their insulation materials for electric connectors. Many ESP failures could be attributed to packer penetrator failure due to corrosion of the electric connector beneath the ESP packer.
A method is developed to generate a low density gel system that isolates the electric connector from downhole chemicals in order to provide prolonged protections of electric connectors against corrosive atmospheres and chemical attacks. Mixture of low-density materials/composites are prepared on the surface and then pumped into targeted place through the bypass tubing. The mixture has low density so that it travels upwards in the wellbore and floats on the top of downhole fluids. Under a given well temperature, a rigid gel/composite system forms between the electric connector and the downhole fluids, isolating the electric connector from the hostile chemicals thus providing a better protection. We have developed the low density settable material and demonstrated its performance in the lab scale. It is also scaled up to a mocked up physical simulator to observe the flow dynamics and chemical reaction in realistic geometry.
Reduce the Rate of Abandoning Radioactive Sources in Oil and Gas Wells
Authors: Shhub Abdu Naser , Amer Mustafa 
Published: October 2018

Abstract
Data collected over 12 years indicated an average of 19 radiation incidents per year, related to stuck radioactive sources in well logging. On average 61 % of these stuck radioactive sources have been retrieved, and the remainder sealed in as per protocol.
The goal of this Lean Six Sigma project is to reduce the percentage of abandoned stuck radioactive sources from 39% to 30%.
Analysis of past data shows five parameters with the greatest effect on the percentage of abandonment.
These parameters are: location, onshore/offshore, LWD/wireline, company and fishing duration.
Lean Six Sigma Methodology (5 DMAIC phases) is used to manage this project and two workshops have been conducted to determine root causes and recommendations.
We are currently in the process of implementing 13 recommendations for 13 root causes. Corrective actions have been assigned to stakeholders with an estimate date for completion.
Use of Polymer Resins for Surface Annulus Isolation Enhancement
Authors: Elyas Odai , Alyami Abdullah , Wagle Vikrant , Alhareth Nasser 
Published: October 2018

Abstract
Cementing is an extremely important task in oil/gas well drilling operations to ensure integrity of the well, and to prevent gas and oil migration through the cement matrix for an extended period. This could lead to sustained pressure in the casing annulus (CCA). Sometimes, cements or chemicals are injected from the surface to improve wellbore isolation. Two parameters control this surface operation success; injectivity and pressure.
The objective of this paper is to demonstrate the ability of different types of resins in shallow remedial operations at different parameters of injectivity and pressures to improve wellbore isolation. Examples of these resins are epoxy resin system and polyester resins. Epoxy based resin is prepared by mixing an epoxy resin with an aromatic amine-curing agent. A polyester resin system is made by mixing polyester resin, norpol peroxide curing agent, filler, and silicon dioxide.
Intensive lab testing and pilot testing were performed at shallow conditions to assess the limitation of each type of resin and to optimize on operational procedures. For such surface operations at low injectivity profile, it is expected to have solids free resin for deeper penetration. Short setting resins are desired over extended ones to allow for proper isolation and quick sealing.
The paper will discuss best practices to perform the surface operations and will highlight limitations and benefits of both resins supported by intensive lab testing and field applications.
Semi-Analytical Three-Phase Relative Permeability Model for Gas-Condensate
Authors: Abdul-Latif Benson Lamidi , Abdul-Rashid Bawah 
Published: October 2018

Abstract
Modeling three-phase flow in gas-condensate systems requires the relative permeability of each fluid as a function of the fluid saturation. The Coreflood laboratory and experimental measurement of three-phase relative permeability (3-PRP) data is much complicated, more time consuming and relatively expensive when compared to forecasting two-phase relative permeability data.
Owing to this, many three-phase relative permeability correlations have been proposed in the petroleum industry for estimating three-phase relative permeability using geometric or arithmetic summation and interpolation of two-phase relative permeability data. After comparing results of most of the existing three-phase models to Oaks experiment, we realized that most of the existing three-phase models fail to incorporate the physical mechanisms underlying multiphase flow in gas-condensate systems.
This paper aims to fill this knowledge gap by proposing a novel 3-PRP model to forecast three-phase relative permeability in gas-condensate systems. Three-phase interactions between fluids and fluid saturations are fully incorporated in this model by introducing three-phase characteristic coefficients. Using these coefficients, the total two-phase oil saturation relative to water is not only a function of the three-phase oil saturation relative to water but it is expressed as a function of the three-phase oil saturation with respect to both water and gas.
The proposed 3-PRP model is successfully validated against experimentally measured three-phase relative permeability data.
Success Stories of a Green Chemistry Based Stuck Pipe Solution in Saudi Arabia's Challenging Top Holes Facing Total Losses to Production Holes with High Overbalance
Authors: Hegazy Mohamed , Sharma Sunil , Fares Khaled , ElBatran Ahmed 
Published: October 2018

Abstract
Historically, stuck pipe has been one of the biggest causes of non-productive time (NPT) in Saudi Arabia, resulting in loss of tools, reduced hole footage, and potentially endangering well objectives. Stuck pipe still tops the list of costly non-productive time events worldwide, ahead of items such as well control incidents, waiting on weather, lost circulation, equipment failures, and rig associated problems (Hunter et al., 2014).
In Saudi Arabia, stuck pipe incidents occur in all drilling sections. While drilling top hole sections, they are generally coupled with partial to total losses; in deeper sections, they are induced due to high overbalance. Stuck pipe in top hole sections requires a solution that is environmental friendly, as many aquifers used by local communities are also present in these sections. Since the presence of aquifers limits the use of conventional hydrocarbon-based solutions, a novel non-hydrocarbon-based pipe freeing agent was developed. This new technology eliminates the need to isolate the stuck pipe pills at surface after circulating them out; they can be incorporated into the circulating system because of their excellent environmental footprint. When added in the drilling fluid, these pills improve system lubricity.
This paper presents an overview of successful applications of this novel chemistry in both the top-hole section with total losses and in the production section with overbalances up to 4,400 psi. Performance-based results and advantages of using this solution to improve overall drilling performance will also be discussed in detail. Best practices and lesson learnt for mixing, pumping, displacement, and soaking will also be covered in detail to provide a guideline for operators in similar conditions across the Middle East.
High-Fluid-Loss, High-Strength Lost Circulation Solution for Total Losses Zones in Saudi Arabia
Authors: Hegazy Mohamed , Sharma Sunil , Fares Khaled , ElBatran Ahmed , Dave Alok , Megally Fady 
Published: October 2018

Abstract
Lost circulation is a prominent problem in almost all fields of Saudi Arabia. Losses can vary from partial to total and sometimes also initiate other drilling related issues, such as stuck pipe, kick, and wellbore instability. These complexities make it paramount to cure losses as fast as possible to minimize non-productive time.
Conventionally, discrete pills formulated using a material blend with broad particle size distribution (PSD) are employed first as one of the more popular approaches for curing severe lost circulation. The lost circulation material concentration and PSD are increased in the pills based on loss rates, thus under severe and total loss conditions the pills require use of specialized pumping equipment, by-pass tools, and even the removal of the BHA. Unfortunately, dealing with severe losses in the Kingdom, success rates with these pills are very low. A solution for severe to total losses pumpable through a BHA was the operator's wish.
In this paper, successful field applications proving the advantages of a new high-fluid-loss, high-strength (HFHS) lost circulation solution in different fields, formations, and sections will be covered in detail. The paper will also include operational best practices for mixing, pumping, spotting, and squeezing HFHS pills, lesson learnt, and recommendations for future applications.
Prediction of Inflow Performance Relationship of a Gas Field Using Artificial Intelligence Techniques
Authors: AL-Dogail Ala S. , Baarimah Salem O. , Basfar Salem A. 
Published: October 2018

Abstract
The Inflow Performance relationship is considered one of the diagnostic tools used by Petroleum engineers to evaluate the performance of a flowing well. An accurate prediction of well IPR is very important to determine the optimum production scheme, design production equipment, and artificial lift systems. For these reasons, there is a need for a quick and reliable method for predicting the well IPR in gas reservoirs.
This study presents back propagation network (BPN) and fuzzy logic (FL) techniques for predicting IPR for a gas reservoir. These models involved 489 data points from published literature papers and conventional PVT reports.
Statistical analysis was performed to see which of these methods are more reliable and accurate method for predicting the inflow performance relationship for the gas reservoir. The FL model outperformed the artificial neural network (ANN) model with least average absolute error, least standard deviation and highest correlation coefficient. The proposed fuzzy logic well inflow performance relationship model achieved an average absolute error of 4.303%%, standard deviation of 18.891% and the correlation coefficient of 0.995.
The developed technique will help the production and reservoir engineers to better manage the production operation without the need for any additional equipment. This technique will reduce the overall cost of the operation and increase the revenue.
Evaluating the Effects of Surface Tension and Viscosity on Two-Phase Flow in Horizontal Pipes
Authors: AL-Dogail Ala S. , Gajbhiye Rahul N. , Mahmoud Mohamed , ElKatatny Salaheldin 
Published: October 2018

Abstract
Two-phase gas/liquid flow in pipes is a common occurrence in the petroleum, chemical, nuclear and geothermal industry. In the petroleum industry, it is encountered in the production, transportation, and processing of hydrocarbon from oil and gas field. In designing these systems, accurate prediction of pressure drop is imperative which is determined from flow regime map. Unfortunately, most of the flow regime maps were developed for the air-water system and widely used for the gas/oil system. In spite of the practical importance the general applicability of these maps is not addressed. In order to improve the generality of flow regime maps it is necessary to evaluate the effect of fluid properties such as surface tension which differ by great magnitude (air/water = 72 dyne/cm and gas/oil = 35 dyne/cm) and viscosity (viscosity of water 1 centipoise and for oil 10 centipoises at standard condition) on the flow regimes. Thus, this study aims to evaluate the effects of surface tension and viscosity on the flow regimes in horizontal pipes.
The most flow regime maps are generated using the air-water system and widely applied to the oil-gas system. In addition, the empirical equations based on flow regime maps are not accurate with relatively high error (20-30%). So that the applicability of these maps is limited due to the lacking knowledge of fluid properties effect. Evaluation of these properties will address the applicability of these maps for other systems.
The objective of this study is to evaluate the effects of surface tension and viscosity on flow regimes in horizontal pipes and investigate its effects on boundary transition. The experiments were conducted on horizontal pipe flow-loop (length 30' and diameter 1") with two-phase air/ water. The range of superficial gas velocity is 0-60ft/s and superficial liquid velocity is 0-10ft/s. The effect of surface tension has been introduced by reducing the surface tension with the aid of a surfactant, and the effect of viscosity has been introduced by increasing the viscosity with aid of glycerin. Four different surfactant concentrations (0.02, 0.05 0.1, 0.5%) and four different glycerin concentrations (5,10,20,30%) have been selected to evaluate the effects of the surface tension and viscosity.
The experimental data were utilized to generate flow pattern map and the effect of surface tension and viscosity were evaluated based on the variation in the boundaries of different flow patterns.
New Technology to Evaluate Equivalent Circulating Density While Drilling Using Artificial Intelligence
Authors: Elzenary Mahmoud , Elkatatny Salaheldin , Abdelgawad Khaled Z. , Abdulraheem Abdulazeez , Mahmoud Mohamed , Al-Shehri Dhafer 
Published: October 2018

Abstract
The equivalent circulation density (ECD) is a very important parameter in drilling high pressure high temperature (HPHT) wells and deep water wells. In formations where the margins between the formation pore pressure (PP) and the formation fracture pressure (FP) is narrow, ECD is a key parameter. In these critical operations, the ECD is used to control the formation pressure and prevent kicks. The recent approaches in oilfield depend mainly on using expensive downhole sensors for providing real time values of ECD. These tools also have operational limits which may prevent using it in all downhole conditions.
The objective of this paper is to present a new technique for predicting ECD values while drilling without the need for downhole tools. The technique uses surface drilling parameters in a model to evaluate the ECD values precisely using artificial intelligence (AI) techniques. The model was developed using two AI techniques; artificial neural network (ANN) and adaptive neuro fuzzy inference system (ANFIS). Using this technique will save cost and time by eliminating needs for using expensive, complicated downhole tools like measurement while drilling (MWDs) and pressure while drilling (PWD).
The results obtained showed that the accuracy of the developed model is very high with error factor less than 0.22 % comparing the actual to predicted ECD values. Implementing this model in well design will have great impact in accurately choosing correct mud weights to safely drill the well. It will also minimize the drilling problems related to ECD such as losses or gains especially in critical area where margins between pore and fracture pressure is very narrow.
Dynamic Fluid Pulsation: A Novel Approach to Reservoir Stimulation Improves Post-Stimulation Gains
Authors: Davidson Brett , Kolli Koti , Spanos Tim , Akar Ahmed Abu , Omari Mazen Al , Djelliout Mohamed Amine , Shanoun Djilali 
Published: October 2018

Abstract
One of the major challenges to maximizing recovery of reserves is that every oil or gas reservoir rock is more or less heterogeneous at all scales (micro, mega, and pore) which leads to disproportionate production and injection outcomes. Generally, the higher the level of reservoir heterogeneity the more difficult it becomes to achieve maximum fluid distribution or conformance. Improving conformance in a non-homogenous material such as a hydrocarbon reservoir inherently means improving flow through lower permeability regions. Ideally, during a conventional well stimulation using a treatment fluid such as acid, we wish to move the fluid through the majority of the rock volume but the physical constraints of fluid flow negatively impact that ideal outcome.
Dynamic fluid pulse technology provides for high inertial fluid momentum which improves the flow efficiency of fluids injected into the wellbore, the near wellbore region, and the reservoir. The nature of fluid displacement energy ensures that pulsed fluid will penetrate the matrix proximal to where the tool is placed thus achieving enhanced fluid distribution. Prior to a stimulation operation a dynamic mathematical model associated with fluid pulse technology is employed to generate a precise well program (pumping schedule) to maximize the contact volume of the treatment fluid along the completed interval. Compared with conventional stimulation dynamic fluid pulsation has been demonstrated to bring significant financial benefits to well stimulation without impacting results including: reduced chemical costs; improved post-stimulation sustainability; and, better overall post-stimulation well performance as a greater volume of the completed interval hence matrix is contacted by the treatment fluids.
Cost Estimation of Fire Protection Requirements During Bidding Phase Through Simplified Risk Assessment Methods For Oil & Gas Facilities
Authors: Srikanth Mellachervu , Prabhakaran Abhilash 
Published: October 2018

Abstract
Projects with accelerated engineering, procurement, and construction (EPC) schedules are becoming common in the oil and gas industry with Oil Majors keen on quick and guaranteed returns on investment. EPC contractors involved in the bidding process face the task of submitting ‘qualification free’ techno-commercial proposals within a short time frame which provides challenges to the tenderer for a package having a level of design not mature enough for the estimation purpose. The objective of this paper is to demonstrate a practical approach to the cost estimation of fire protection systems during bidding stage using Simplified Risk Assessment (SRA) methodologies.
The methodology adopted was to conduct a risk assessment for a typical bid to arrive at the sound cost estimate for the fire protection systems. Typically fire protection requirements come in form of recommendations from safety/risk studies, hence cost attached to fire protection requirements were estimated based on the results from SRA for a typical bid. The Fire Risk Assessment (FRA) was performed using DNV-GL PHAST software to carry out consequence analysis to identify the extent of fire impacts. Subsequently, frequency analysis was conducted using parts count methodology to cumulate the frequency of fire scenarios. The most prominent leak scenarios for the study were considered as a part of the simplified approach in lieu of considering exhaustive scenario combinations based on different leak sizes, weather parameters, leak directions, etc., which traditionally forms part of detailed QRA. The selection of prominent leak scenarios was based on the good practice followed in the industry supported by the requirements specified within Operator Standards as well. The Fire Risk Assessment (FRA) results for different time intervals formed the basis for fire protection requirements.
The study has helped to identify fire protection requirements for specific system/equipment/structure and further has helped in the submission of ‘qualification free’ techno-commercial proposals. The advantages of adopting this methodology based on SRA approach are deemed to be well-suited for bidding phase, where the time and cost of carrying out detailed risk analysis is not feasible.
Application of such methodology would also provide benefits to the operators in receiving quick and reliable fire protection cost estimate.