bluuebunny/crossref_metadata_2025_split huggingface dataset:
Production Optimisation with Hydraulic Fracturing: Application of Fluid Technology to Control Fracture Height Growth in Deep Hard Rock Formation
Authors: Al-Dhamen Mohammad , Makmun Areiyando , Hilal Ahmed 
Published: May 2016

Abstract
Hydraulic fracturing is frequently used to create the reservoir-wellbore connectivity required to produce the hydrocarbon from tight formations. Many factors can be considered as risks to the success of operations. One arises in reservoirs with a water-bearing zone in close proximity to the net pay. Many times, the risk of fracture growth into the water zone limits the stimulation options and eliminates the option of a hydraulic fracturing treatment, thereby constraining the well's future production. The challenges increase when the reservoirs are deep, hot, and exhibit a high Young's modulus. Under these conditions, it greatly increases the risk of an early screenout, and the introduction of fracturing fluid into the formation before a high-conductivity proppant pack is fully placed will damage the formation and hinder production.
In Saudi Arabia, a well in a relatively new field encompassed all three challenging characteristics. The target reservoir section was between two water-bearing zones, had high bottomhole temperature, and high Young's modulus. Traditional polymer-based crosslinked fluids would address the challenges from the perspective of proppant placement. However, these thick crosslinked fluids would also risk in uncontrolled fracture growth into the water zones. A polymer-free, high-temperature visco elastic surfactant (VES) fracturing fluid was used to balance the risks of incomplete proppant placement, formation damage, and fracture growth that would result in water production.
The VES fluid selected for treatment of Well SH-3 has a low viscosity compared to that of a traditional crosslinked fluid; it therefore generates less net pressure and thus lowers the risk of the fracture growing into the water zones. It also has excellent capacity to carry and suspend proppant. To increase its efficiency, the VES fluid was further enhanced by using a degradable fluid-loss additive.
Pumped on a conservative schedule, the hydraulic fracturing treatment placed 61,500 lbm of proppant into the thin reservoir section between two water-bearing zones without any operational issues. The Minifrac analysis, stress profile calculation, and fracture geometry characterization, as well as no water production, has confirmed the controlled fracture height growth. Furthermore, pre- and post-stimulation analyses validated the improved productivity, giving a successful stimulation option for the development of this field.
Mitigating Challenges in Resolving 7" Liner Leak-Case Study
Authors: Al-Muailu Husain Al , Zorbalas Konstantinos , Al Yateem Karam , Garcia Javier 
Published: May 2016

Abstract
An evaluation process was conducted in assessing various solutions towards remedial action to a 7" liner with an identified leak in a water injector well. The leak to the 7" liner was identified through pressure testing of the well. A comprehensive investigation and analysis was performed to identify the liner condition, exact leak location and the extent of the leak. It was accomplished by analyzing all previous activities performed during the life of the well and through running special pressure testing as well as logging the well with ultrasonic and physical logs.
The problem identification and proposed solutions were focused on curing the leak and bringing the well back on injection with the least operational risk and highest possibility of success. Corrosion and cement bond logs were ran and showed a better picture in regards to the extent of the corroded section and the quality of cement behind it. A caliber log was also run in the open hole which showed a washed out area near the 7" liner shoe.
Several solutions that could repair the 7" liner leak were assessed including: i) cement squeeze in the leak zone, ii) setting an off bottom 4.5" liner and iii) using a 5.5" expandable liner. The evaluation process included eachsolution's impact on the future injectivity of the well, the effectiveness of each option, operational challenges and associated risks. Moreover, nodal analysis was performed to evaluate possible reduction of the injection rate associated with each solution.
The final decision to repair the leak was to run an expandable liner and it was based on its advantages and deployment challenges. Lessons learned from this operation included the methods used to identify and assess the damage of the casing leak. Proper preparation and cleanout of the corroded section and the operation procedures performed to expand the liner are summarized in this paper.
CSEM Inversions Using the Gauss Newton Method and a Model Compression Scheme
Authors: Abubakar Aria , Lin Yun , Li Maokun , Habashy Tarek M. 
Published: May 2016

Abstract
We present a model compression scheme for improving the efficiency of the regularized Gauss-Newton inversion algorithm for marine controlled-source electromagnetic applications. In this scheme the unknown model parameters (the resistivity distribution) are represented in terms of a basis such as Fourier, cosine, or wavelet. By applying a proper truncation criterion, the model may then be approximated by a reduced number of basis functions, which is usually much less than the number of the model parameters. Furthermore, since the controlled-source electromagnetic measurements have low-resolution, we will show that for inversion it is sufficient to only keep the low-spatial frequency part of the image. This model compression scheme accelerates the computational time as well as reduces the memory usage of the Gauss-Newton method. For demonstration purposes, we show both synthetic and field data inversions. The results show that we are able to significantly reduce the algorithm computational complexity without compromising the quality of the inverted models.
Optimising Offshore Gas Field Development with Large Well Bore Completion
Authors: Al-Baqawi Ahmed , Ashri Amjad , Al-Utaibi Abdullah , Al-Kanan Adnan 
Published: May 2016

Abstract
During 2008–2009, Saudi Aramco recorded two major nonassociated gas field discoveries in the Arabian Gulf. The initial plan was to develop both fields with deviated extended reach 7" completion wells, which will be drilled from multi-well platforms. Based on the challenging subsurface conditions of the problematic highly fractured shallow horizons, in addition to the thick, highly fractured, and excellent carbonate Khuff reservoir quality, the decision was carefully made to develop both fields with vertical large bore wells completed as monobore with 9?" pre-perforated uncemented liner across the pay zone and9?" production tubing to the surface. The large bore wells are planned to be drilled from single-well platforms that can be strategically located around the two fields to allow efficient spacing and depletion to produce initial gas rates up to 300 MMscfd per well.
The large bore well design has a potential for maximizing the gas production from each well and reducing the overall field development costs down by 45% by minimizing the number of wells and facilities required without jeopardizing the production, safety or integrity of the development projects.
The shallow horizons in the newly discovered fields, along with the targeted Khuff reservoir, are considered to be highly faulted structures with many associated fractures that can continuously cause drilling problems with lost circulation and differential sticking. The newly planned vertical large borewells tend to reduce drilling problems. Nevertheless, those planned vertical large bore wells are still capable of producing the required high gas rates.
The intent of this paper is to highlight the multiple challenges faced during the early exploration and delineation phase of the fields and to share the experience of planning new offshore field development strategies for large bore wells with high reservoir temperature and pressure (T&P). Transforming from the original development plan to the optimized large wellbore completion plan, takes advantage of the excellent reservoir quality and high flow capacity, allowed for many optimization efforts. Such optimizations have changed the entire project strategy to accelerate the official on stream start update without any compromises.
SPME Method Development for the Determination of Aliphatic Amines in Industrial Waste Water
Authors: Alghamdi Talal M. 
Published: May 2016

Abstract
In the presence of dissolved oxygen in the water inside a pipeline, the oxygen attacks the steel to form iron oxides. To prevent this, corrosion inhibitors are added to the crude oil streams. These chemicals are amines-based that form a film to coat the steel and prevent it from contacting the oxygen. Amines residuals should be monitored in the system and this is classically done by liquid-liquid extraction (LLE) of amines followed by colorimetric determination using spectrophotometry.
In this work, solid phase microextraction (SPME), a novel extraction technique that uses no solvent, was used as a sample preparation technique to isolate the amines from the complex sample matrix and then the gas chromatography (GC) system was used for separation and quantification of amines. A flow-through system was used to simulate the process of flowing streams in pipelines during oil production.
A method was developed to determine amines residuals at the lowest detection limit possible at the optimized conditions such as solution pH, ionic strength, and sand contents. It was found that residuals can be determined as low as 1ng/mL using the GC system equipped with a flame ionization detector (FID). This method was developed in the lab using a model to simulate the flowing streams and containing synthesized waste water.
This method is an environmental friendly technique that will minimize the use of hazardous solvents and therfore the need for the proper disposal of them. Also it does not require pretreatment steps of samples or many reagents to be used in the extraction process of amines residuals. Finally, it will provide more precise results in a timely manner for better and quicker actions.
Drilling with Casing Technique Successfully Overcome Massive Thief Zone
Authors: Agustina Diah , Tanjung Erwindo , Taufiqurrachman Hafidh , Won Keith , Zega Delfin 
Published: May 2016

Abstract
The Lima field, located offshore in North West Java Indonesia, encountered major challenges to both drilling and cased off problematic zone during running casing operation due to severe lost circulation conditions. Specifically, severe mud losses in the major loss zone were recorded in Pre-Parigi formation. The operator has experienced massive loss problems while drilling the 8-1/2inch section. Unsuccessful sidetracking operations with conventional drilling technique has urged operator to look for alternative drilling methods to caseoff the massive thief zone.
The drilling with casing system has been identified as one drilling technique that may repair the troublesome thief zone. This non-retrievable system, which utilizes casing as drill string, allows the string to immediately be cemented in place once targeted depth is achieved, hence eliminating the risk of casing tripping failure through massive lose zone with conventional drilling method. The special designed aluminum crown casing bit is drillable by subsequent section conventional bit without additional clean out trip.
This paper will discuss the planning, implementation and finally the results of 7 inch drilling with casing technique through the problematic Pre-Parigilost circulation zone.
Lessons Learnt from Water Shutoff of Horizontal Wells Using Inflatable Packers and Chemicals in Ghawar Field of Saudi Arabia
Authors: Sharma Hemant , Duarte Jorge , Mufeed Eid , Turki Saadoun , Vielma Jose R. 
Published: May 2016

Abstract
Due to the advancement of technology and improved capabilities of drilling horizontal wells, producers and injectors are now commonly completed with long horizontals to expose large reservoir areas. For the reservoir pressure maintenance, the most prevalent means is by using water injection. This injected water, while helping in pressurizing the reservoir, becomes a curse when it starts to produce with the oil. In addition, as the transmissibility of the water is higher than the oil, water breakthrough is a major challenge facing the oil industry. Various techniques are available and being used worldwide to control/reduce this produced water; however, controlling water production by performing water shut-off (WSO) in horizontal wells is more complicated and challenging than in vertical wells.
To control water production in horizontal wells, isolation of the wellbore using inflatable packers in open/cased hole completion and capping with cement has shown little success in the past.
Therefore, another technique was attempted to control water production in horizontal oil producers by using mechanical means to isolate the wellbore and chemical means to isolate the matrix/fissure, which forms a permanent barrier and reduces water production. The selection criterion for mechanical isolation and type of chemical suitable for the formation is a tedious task for the petroleum engineer. Most of the time, the vendor's data that is available is being used and applied for the field application, which shows a low success ratio.
In this paper a brief overview has been presented, taking into account two wells from Ghawar field in Saudi Arabia, where a combination of wellbore isolation using inflatable packers and matrix/fissure isolation using an organically cross-linked polymer (OCP) system were performed. The candidate selection criteria, job criteria, planning, execution, and post-job evaluation will be discussed.
Physical Modelling of In-Depth Fluid Diversion by "Gel Dam" Placed with Vertical Well
Authors: Li Junjian , Liu Yuzhang , Li Yikun , Wei Falin , Lv Jing 
Published: May 2016

Abstract
In view of the ineffective cycling issue of injected water through the high permeability zones during water flooding process in positive rhythm reservoirs, the gel dam in-depth fluid diversion technique is proposed. The technique first promoted the injection of gel by horizontal or sidetracking wells drilled in the more permeable and strongly swept zones of thick positive rhythm reservoirs. The injected water then will bypass the "gel dams" and be diverted into the upper unswept or poorly swept low permeability zones. As a result, the swept efficiency and oil recovery of the upper low permeability zones can be both increased.
Gel dam placement method can be enhanced the oil recovery both in the laboratory experiments and numerical simulation technology, but the use of new drilling horizontal wells for gel dam placement accompany with certain technical and economic risks; In order to reduce risk, to explore the law of horizontal well gel dam placement, we proposed the use of the crossing straight well set to place the gel dam for Daqing Oilfield, which is consistent with the current research status. Straight and horizontal wells gel dam placement have the similar principles, but there are some differences, how to use a crossing well to place the gel dam should be further study to improve the development effectiveness.
The physical modeling experiments of gel dams in a positive rhythm formation and in a point bar sand body are conducted in the 3D physical model. The results of the experiments indicated that, with one or two gel dams, the sweep volume and ultimate oil recovery were both increased greatly, and the water cut ascending velocity was decreased. Compared with the physical model with horizontal gel dam, the ultimate oil recoveries of those with gel dams decrease by 8.1,but the oil recvoery is still 7.6% higher than waterflood. By vertical well "gel dam" in-depth fluid diversion technique, the difficulties in the in-depth placement of plugging agents will be solved, risk has been reduced and the swept efficiency of positive rhythm reservoir can be increased significantly.
A Successful Application of 3D Seismic Attributes in Exploration for Eolian Stratigraphic Traps in Central Saudi Arabia
Authors: Hu Herbert , Al-Zahrani Mohammed Saeed , Al-Mahmoud Khalid 
Published: May 2016

Abstract
The purpose of this presentation is to demonstrate the successful application of 3D seismic attributes in exploration for Permo-Carboniferouseolian stratigraphic traps in central Saudi Arabia. To explore for these traps, we have integrated regional geological studies and rock property analysis, and tied these to the seismic attribute response.
Permo-Carboniferous eolian reservoirs are the primary objective for oil and gas exploration in central Saudi Arabia. Due to the nature of the mixed fluvio-eolian setting, this is a very challenging target, especially for stratigraphic traps. The eolian setting comprises a complex mix of depositional systems including eolian ergs, ephemeral streams, and ephemeral (playa) lakes. Eolian sand dunes and sand sheet deposits are the two main reservoir facies, while lateral facies changes result in the primary up-dip seals.
We carried out detailed well-to-seismic correlations at the reservoir level and found that the following seismic attributes were useful in exploring for these stratigraphically trapped eolian reservoirs:Reservoir thickness and quality:sum of positive amplitude over the target interval,isochron from Early Triassic to Early Permian,isochron from top to base of the target,frequency decomposition,acoustic impedance inversion, anddeformation of seismic wavelet.Up-dip seal: Sum of the negative amplitude over the target interval.Hydrocarbon potential: AVO/AVA inversion.
Exploration results in the study area indicate that the above mentioned seismic attributes correlate very well to changes in geologic environment, and to log and reservoir properties. The integration of 3D seismic attributes with regional geologic studies and existing well control has been very successful in exploring for eolian stratigraphic traps in central Saudi Arabia.
Multiple History Matching and Well Placement Optimisation in a Mature Field Using a Streamline Approach
Authors: Raniolo S. , Bilancio D. , Dovera L. , Mezzapesa D. , Galibert S. 
Published: May 2016

Abstract
The paper presents an application of an innovative workflow for multiple history matching. Initially streamline-based simulations are used to rank multiple geological images and to efficiently identify representative models. Afterwards, the selected realizations are fully simulated and multiple history matching is achieved through the application of genetic algorithms.
The workflow has been implemented on a North African field whose production started in 1996. The main hydrocarbon reservoir is a Triassic sedimentary series developed in a fluvial environment characterized by high heterogeneity and uncertainty. Such uncertainty has been captured by generating more than a thousand alternative reservoir models by varying key geological parameters. For each realization, streamline simulation was performed and the heterogeneity has been measured based on flow capacity-storage capacity plot. Streamlines simulation requires only few minutes to solve the entire set of models. Cluster analysis was used to select five models with different heterogeneity. History matching calibration has been set up on the reduced number of realizations using genetic algorithm to speed up and automate the process.
The final output of the workflow is a set of alternative models properly matched that represent the ideal suite to estimate the uncertainty in forecast and to evaluate infilling opportunities.
Well placement optimization has been then implemented all over the different geological scenarios.
The application demonstrated that the innovative workflow allowed managing more than a thousand reservoirs models in a very short time, to efficiently select representative realizations and to speed up the history matching process. Moreover, dealing with multiple history matched models put the basis for a robust estimation of future production together with a more reliable evaluation of new infilling opportunities.
As a result of the study, two over three approved wells have been already drilled and put on stream with positive results, in line with the predictions.
Asset Integrity Challenges in Oil & Gas Process Facilities
Authors: Al-Sulaiman Saleh , Sardesai Vinayak , Murthy Hari Srinivasa , Reddy N. Harinadha , John Reji P. 
Published: May 2016

Abstract:
Managing asset integrity is a complex activity in surface production facilities of an oil industry. Process equipment in an oil production facility is exposed to various damage mechanisms that may be active due to the presence of contaminants in the process streams.
Proper material selection, maintenance programs, inspection monitoring and repair are the standard components of the Asset Integrity Management Process. The conventional way of approaching the problems caused by damage mechanisms such as Hydrogen Induced Cracking (HIC) and Stress Corrosion Cracking (SCC) in Pressure vessels is by way of repairs or replacements. Black powder deposits are also causing increasing concerns due to fouling and severe corrosion. One pressure vessel and one heat exchanger have been replaced in few facilities of Kuwait Oil Company during the past one year due to Hydrogen Damage and fouling. One more vessel with minor embedded defects is under inspection monitoring and engineering evaluation. Alternate remedies have been applied to minimize propagation of defects.
This paper presents field experience and application of various inspection methods in detecting embedded defects, hydrogen induced damages in the early stages, application of preventive measures to extend asset service life and asset integrity. Under this process, various advanced NDT inspection techniques were applied to detect and monitor critical internal defects on pressure vessels. Root cause analysis, fitness for service (FFS) and Risk Based Inspection (RBI) study have been conducted as a part of mitigating risks and applying remedies.
An Insightful and Robust Approach for Multi-Tool Interpretation: Moving Away from Traditional Black Box Methods
Authors: Anand Vivek , Freedman Robert , Cao Minh Chanh 
Published: May 2016

Abstract
In this paper a new approach for joint interpretation of petrophysical measurements acquired by multiple sensors or tools is demonstrated. This approach is based on a mapping function that can be expressed as a linear combination of radial basis functions (RBFs). The theoretical log response equations for the sensors or tools are used to compute a database covering all possible ranges of formation properties, i.e., the solution space. The database is used to construct the mapping function that relates log measurements to formation properties.
The solution space can be plotted in 2D or 3D depending on the number of input measurements. The plots provide the petrophysicist with a useful tool to:identify outliers that might denote a model inadequacy,select appropriate equation parameters that might not be obvious from individual logs, andcompute a solution consistent with the model equations.
The mapping function solutions are computationally fast, unique, and robust. In contrast, traditional multi-tool interpretations based on non-linear minimization techniques often face problems of non-uniqueness and lack of robustness.
We demonstrate the new approach using two classic examples. The first is the integration of resistivity and pulsed neutron capture logs to solve simultaneously for water saturations and salinities. This is a non-linear problem that has complex input parameter dependencies. The second example is analysis of thin-beds that have resistivity anisotropy. Even though analytical solutions exist, they are complex and it is difficult to see how, for example, net pay depends on the anisotropy. The choice of these classic examples allows us to show the simplicity of the proposed technique and to benchmark it against the traditional methods.