bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of the Wettability and the Petrophysical Properties in Carbonate Reservoirs by Advanced NMR and MRI Techniques
Authors: Matenoglou G. , Kelessidis V. C. , Garcia A. P. , Heidari Z. , Fardis M. , Karayanni M. , Maris Thomas G. 
Published: November 2016

Abstract
Carbonate rocks are among the dominant oil reservoir formations. Due to their heterogeneity, their petrophysical properties are difficult to be evaluated. Magnetic Resonance, applied as low-field Nuclear Magnetic Resonance (NMR) or Magnetic Resonance Imaging (MRI), are powerful tools for reservoir characterization. Their basic advantage is the quantitative demarcation of various fluids. In this work we have used MRI methods in order to evaluate the petrophysical properties of carbonate rocks. For this purpose commercial limestone, saturated with deionized water, crude oil and model oil or mixture of water with model oil were used to acquire calculated spin-spin relaxation time (T2) and Diffusion Tensor Imaging (DTI) MRI scans. This leads to the pixel-by-pixel characterization of the rock samples and the quantitative evaluation of the saturation profiles in 3-D space. The proposed MRI techniques offer a new insight in the spatially resolved information of petophysical properties towards better understanding of the fluid-rock matrix interactions.
Cost Effective Detection of H2S Release in Oil Well Locations
Authors: Jayapalan Gopalakrishnan , Konkati Sarath , Bangari Praveen 
Published: November 2016

Abstract
Hydrogen sulphide (H2S) gas is one of most poisonous gas associated with oil and gas production. Gas release in wellhead and crude oil product transfer flow line has to be detected at the earliest to save human life and asset. When the oil wells are spread over hundreds square kilometers, it is not an easy task to monitor H2S release. H2S gas detection solution should be economical. In the desert, there will be hundreds of oil and gas wells exist; typically oil wells data is available in oil control room and gas wells data is available in gas control room. At present sharing of H2S detector status between these control rooms does not exist. All the sour gas wells are equipped with local H2S monitoring and well tripping mechanism on gas detection. Objective of this paper is to detect any H2S gas release in well heads and transfer lines in an economical way. The entire field mounted gas detectors status is collected in centralized control room and detector location mapping is done. Weather monitoring station information such as wind direction, wind speed, etc., is populated in the same page. In unrepresented vulnerable locations such as trunk roads, security check post, cattle firm, etc., standalone solar powered H2S detectors are installed and its signal is connected to RTU. RTU sends signal through GSM modem to Field Data Integration system; which facilitates centralized monitoring of available H2S detectors status. Field data integration system collects gas detectors status in oil control room and gas control room through OPC server and populates are the detectors status in single page; which facilitates emergency handling. This paper presents various types of H2S detection technology used in upstream oil industry and their response time. It also talks about recent technological advancement in H2S detection.
Implementing Fiber Optics Distributed Sensing as a Key Surveillance Tool
Authors: Al Shoaibi S. , Kechichian J. , Mjeni R. , Al Rajhi S. , Bakker G. G. , Hemink G. , Freeman F. 
Published: November 2016

Abstract
Fiber Optics Distributed sensing technologies are evolving in the petroleum industry with its potential applicability in many areas of surveillance. Petroleum Development Oman (PDO) is embarking upon the implementation of this technology in various assets including both Gas and Oil fields. The vision of the company is to have the Fiber Optics distributed sensing technology as a surveillance tool in the Well and Reservoir Management (WRFM) toolbox and to become, where appropriate, a key element of its cycle. In comparison to conventional surveillance, fiber optic distributed sensing requires no well intervention and thereby reducing HSSE exposure and production deferment. In addition, the installed fibers can be used for multiple applications, e.g. hydraulic fracture performance monitoring and inflow performance monitoring. Recently, PDO trialed Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) technologies utilizing both, dip-in surveys and permanent installation of fiber optics in the wells.
Fiber optic implementation in PDO included a polymer flooding trial in heavy oil, high permeability clastic reservoir with a strong bottom water aquifer drive. The objective was to monitor well conformance as the polymer injection progressed. The horizontal injectors were completed with pre-drilled liner and divided into four zones, each with an independent Inflow Control Valve (ICV). The well was completed with a multi-mode (MM) fiber pumped into control lines three injectors. Real time DTS data was acquired continuously in all three wells while DAS was acquired as per the injection program in one injector. DAS and DTS data were analyzed to quantify the changes in injection profile and rate in each ICV zone. This provided timely information needed for decisions related to manipulation of the ICV valves to ensure best utilization of the polymer.
Another example of fiber optics was a dip-in survey in a deep gas well with commingled production which covered stacked reservoirs. This was run in order to prove the concept of flow response on DAS/DTS signals in terms of gas flowing and liquid lifting detection. The acoustic signature observed was mainly due to gas entering the well through perforations. This was detected by DAS and DTS and allowed a qualitative inflow profile to be generated. The dip in survey proved the concept and allowed justification for the permanent installation of fiber optics behind casing. The objective of the permanent setup is to improve the sensitivity of the measurement and allow for better quantification of inflow per zone. In this paper, the approach of implementing fiber optic technologies in PDO is discussed with emphasis on value generation in the various assets. Additionally, the examples mentioned in this abstract are discussed in more details and based on the results, the way forward is described.
From Lab to Field: An Integrated Approach to Successfully Restore The Productivity of Damaged Wells with Organic Deposition
Authors: Al-Taq Ali A. , Alfakher Basil M. , Al-Muhaish Salah A. , Alrustum Abdulla A. 
Published: November 2016

Abstract
Asphaltene deposition is a major formation damage issue in production wells with asphaltene problematic oil. Asphaltene can precipitate within the reservoir or in production tubing, resulting in partial or total loss of well productivity. This is especially a large concern in reservoirs with high gas-oil ratio (GOR), as more gas can dissolve in the oil and strip out the asphaltene. This anticipated asphaltene precipitation mechanism might be responsible for several partially or totally damaged wells in Field-A with asphaltene precipitation.
An extensive laboratory study including solubility tests, saturate aromatic resin asphaltene (SARA) analysis, compatibility tests and coreflood experiments was performed in this study. Solubility tests were conducted at reservoir temperature (220 °F) and elevated pressures using asphaltene obtained from a bailer sample to determine the effectiveness of different solvent systems. SARA analysis was performed to assess the stability of the reservoir oil of interest. Compatibility tests and coreflood experiments at reservoir conditions were also conducted to assure solvent system compatibility with formation fluids. In addition, other factors including the overall cost and environmental impact were taken into account in choosing the most suitable solvent system.
Initial lab testing presented a number of candidate solvent systems with high asphaltene solvency power. Some solvent systems were ruled out because they were damaging to core permeability as indicated from the compatibility tests and coreflood experiments. A case study of two successful chemical treatments performed on Well-A with a time interval of more than two years is presented in the paper. The first treatment was successful in restoring productivity of Well-A while the second one was able to remove the partial organic deposition damage with a cost saving of 60%. Using the selected solvent system, a two-stage remediation procedure was implemented to dissolve the organic deposition in the horizontal open-hole section of this well. The first stage included bullheading the solvent, allowing it to soak for 24 hours to clean out the tubing. The second stage involved injecting the solvent in the open-hole section using coiled tubing (CT) with jetting/pulsing mechanism. Results showed an increase in the wellhead pressure by 40% and consequently well productivity, indicating the successful dissolving of the organic deposition.
This paper presents a new methodology in incorporating all the mentioned analytical techniques into choosing the most proper and cost effective asphaltene treatment solution for a specific reservoir to have a successful field treatment.
Cost Reduction and Still Fit for Purpose: A Sharing Economy Approach to Standardized Oil & Gas Plants
Authors: Hauwert Peter , van Reijzen Sander A. , Simons J. Richard 
Published: November 2016

Abstract
The cost of process equipment has exploded in recent decades. Enhanced document requirements and more strict environmental and safety requirements are facts. In practice, too much overdesign and an overload of technical specifications, which are in many cases contradictive, have created a substantial CAPEX increase. The big question nowadays is: "How to bring down the CAPEX of projects and create healthy and sustainable upstream projects for the coming future?" The industry calls for a cost reduction, which is often translated into a "standardized approach". But how should an operator approach standardized processes and equipment, while a fit-for-purpose design seems necessary to cope with different field conditions?
The present paper deals with these questions in order to investigate how to achieve substantial cost reductions without compromising safety, operability and efficiency. Based on projects for several operating companies, a study was performed to compare three built onshore, marginal gas plants with different design philosophies: Design fully according operator specifications;Design according reduced specifications by combined operator/suppliers team;Design according engineering practice standards.
All plants were normalized for comparison. The conclusion is that a cost reduction of nearly 50% for option c is proven, and that there is a method to achieve this for other projects.
Besides the influence of specifications, some critical aspects were identified which contribute in attaining low CAPEX projects: A real cooperation in small, focused teams of operators, contractors and suppliers. This should start in an early stage, to link conceptual selection to basic design and project execution.Use pre-designed standardized process building blocks that are proven in use to create a fit-for-purpose solution, while being flexible enough to allow the end user influence where necessary.Approach process packages as black boxes and rely on the experience of the supplier to design the most cost-effective solution.
These principles can be strengthened by a different contracting strategy and trust-based engineering. Although most applicable for smaller projects, the principles may be more broadly applicable. We present and discuss in detail the pathways to come to structural CAPEX reductions for oil & gas projects, thereby coming up to par with the 21st century.
An Integrated Workflow to Mitigate Drilling Vibrations and Increase Daily Footage
Authors: Bailey J. R. , Pastusek P. E. , Junaibi H. Al , Awadhi M. Al , Katheeri Y. Al , Niznik M. R. , Akyabi K. S. , Page C. G. 
Published: November 2016

Abstract
A workflow that combines optimization of the drill string and bottomhole assembly (BHA) design during well planning and then applies advanced surveillance tools to a well-trained drilling crew yields reduced vibrations, higher drilling rates, and less trouble cost. This methodology is based on the premise that an efficient drilling operation requires optimized tool designs, advanced diagnostics using real-time drilling parameters, and onsite training of efficient drilling practices and the proper use of rig control systems.
The use of efficient modeling procedures to compare alternative drill string and BHA designs provides valuable insights into the string and tool selection process. A method to select the optimal stabilizer contact locations for the BHA tools helps to avoid lateral vibration dysfunctions, and a torsional vibration model can quickly evaluate the resistance of alternative string designs to harmful torsional stick-slip vibrations. Provided the proper hardware, a well-trained driller can be more effective with automated drilling performance evaluation tools that provide real-time drilling parameter recommendations based on optimizing Mechanical Specific Energy (MSE), torsional vibration stick-slip severity, and Rate of Penetration (ROP).
BHA lateral vibrations modeling is field-proven and has been applied globally. One case study will show an application of the model to select a BHA design with specified rotary speed sweet spot. The torsional vibration model can be used in both a design process and in a real-time surveillance mode. In one case study, stick-slip vibrations were too severe to drill ahead with a tapered string design that was selected to lower the equivalent circulating density (ECD). The model helped identify the increase in stick-slip resistance obtained by substituting a portion of the smaller pipe with larger pipe. A real-time surveillance tool provides automated drilling performance analysis and makes recommendations to the driller on bit weight and rotary speed. The recommendations are based on the torsional vibration model results, operating in a surveillance mode, and the MSE and ROP. Rig control systems impact drilling dynamics and efficiency in ways that are not well understood by most drillers, and training on awareness and mitigation of these effects can avoid severe dysfunctions.
4D Processing Pilot over a Giant Carbonate field, Offshore UAE
Authors: Lafram Abderrahim , Francois Pierre , Hubans Christian , Saeed Al Kaabi Ahmed , Benson Marc 
Published: November 2016

Abstract
Time lapse seismic is a proven technology for reservoir monitoring. It allows accessing useful information about the fluid movement, pressure changes and so on. This technology, however, has still some limitations in term of area of application. Shallow marine Middle East carbonate reservoirs are one of them.
In order to test this limit, ADMA-OPCO performed a 4D pilot (OBC/OBC) over a giant carbonate field, where the 2013 monitor has repeated the geometry of the 1994 base (parallel shooting). In this paper, we describe the challenges of the 4D processing of this data, the applied solutions and some results.
The water bottom over the pilot area ranges from 15 to 25 m. The main challenges of this 4D processing are: –Geometry errors in the legacy OBC data: they have negligible impact in 3D but they increase the 4D noise. Significant time was spent correcting these errors.–Noise contamination: the 2C component over the area is highly contaminated by Scholte waves and guided waves. Additionally, the geophone of the monitor data was highly impacted by current noise. It was necessary to bring the hydrophone and geophone to a satisfactory S/N before summation, in order to derive reliable operator for PZ summation. One important point for this 4D project was to favor the less statistical and less adaptive process.–Multiple attenuation: in 4D, the multiple can be highly non repeatable because of changing sea water conditions. The area is known for its severe contamination of short period multiples due to shallow-marine, hard sea bottom environment. After PZ summation, an optimized 3D deconvolution was performed.–4D time and amplitude destriping: it was important to remove the distortion due to different acquisition conditions, coupling etc.
The data integrity analysis and correction, the optimal denoise and demultiple, the careful attention paid to the acquisition-related distortion removal as well as adapted 4D QCS allowed to obtain an interpretable 4D signal which gives useful information about the reservoirs.
These successful results were made possible by a careful control of the noise and multiple attenuation, favoring the use of the deterministic and constrained processes over the adaptive processes even if these latter may be superior in 3D processing; and a robust S/N separation in the 4D crossequalisation/parallel processing were designed and applied. These elements enabled to get an interpretable 4D signal under the very challenging conditions of the considered area and reservoirs.
Hydrate Management Analysis Applying MEG Injection for Gas and Condensate Fields: A Dynamic Approach
Authors: Scott D. W. , Villalobos A. , Kwok C. K. , Scott W. F. 
Published: November 2016

Abstract
As part of the sustainability and growth initiatives of all offshore operating companies to identify and prioritize optimum monoethylene glycol (MEG) injection rate in offshore operations, a hydrate management study was developed using dynamic simulation to optimize long-term planning of maintenance activities and to develop associated long-term maintenance budgets. This workflow includes a parametric study to understand and evaluate the impact of the insulation material as a mitigation measure where inhibitor injection is not possible.
An economic analysis was performed to compare a base case (constant MEG injection rate) with a different scenario of an optimum MEG injection and the introduction of an additional production platform in 2018, where some of the main economic premises that need to be considered are included. The analysis evaluated a gas and condensate offshore system, based on three platforms that send their production to a process facility that treats a production rate at export conditions. After treatment, the gas is separated in two export gas pipelines. A dynamic simulation was used to obtain the MEG injection rate considering a physical model and a fluid characterization that included hydrate curves and phase envelopes.
In addition to this study, pressure, temperature, holdup, and flow regime were calculated. It is not expected to have hydrate formation in the two export pipelines due to the insulation layer that allows an increase in fluid temperature. The insulation layer was obtained by performing a parametric study with the pipeline thickness. This is one of the suggested hydrate solutions from this study.
The proposed workflow addresses the challenges of hydrate analysis by using an efficient and fast tool that can model different dynamic flow behaviors by running fast sensitivity runs for multiple transient scenarios (what-if-scenarios). This solution provides effective and low-cost MEG inhibition by eliminating unnecessary injected volumes at certain times.
GUPCO Experience with Giant Fields: Case Studies from Egypt
Authors: Noureldien Darhim M. , Nabil Salah 
Published: November 2016

Abstract
GUPCO is one of the largest E&P Companies in Egypt and Middle East. It has a vast infrastructure with a large number of wells, platforms, pipelines and offshore facilities. GUPCO's peak production exceeded 600,000 BOPD in 1983 while it produces around 100,000 BOEPD today from more than ten geological formations in Gulf of Suez (GoS). GUPCO produced more than 4.6 billion STBO which represent more than 43% of Egypt's total cumulative oil to date. And in spite of that, we still have many opportunities and success yet to achieve.
As one of the petroleum industry leaders, GUPCO was and will always seek success and excellence in managing its assets. For more than fifty years, GUPCO used to follow the highest standards available in petroleum industry, and applied them in all areas to achieve that outstanding excellence. From day one, GUPCO realized that understanding subsurface features and optimizing recovery from different fields are the key areas among all. As a result, GUPCO had made concerted efforts in those areas in specific.
Managing giant fields is not an easy task; it requires special knowledge and experience to manage such critical asset since each 1% increment of oil recovery means tens of millions of oil barrels. And because GUPCO has four giant fields, it was serious for us to do our best to maximize their value. GUPCO started that early whilst exploration phase, appraisal, development and currently in maturity phase. Along these different phases, we utilized wide spectrum of tools starting from basic technical elements (e.g. flow equations, DCA, MBE, PTA… etc.) reaching to state-of-the-art techniques and technology available (e.g. Numerical Modeling, Artificial Intelligence and EOR) at which GUPCO uses numerical reservoir simulation extensively, utilizes neural network in different applications, and already applied TAP (Thermally-Activated Particles) technique which is called commercially BrightWater® to improve sweeping efficiency, and also studied feasibility of Low Salinity Waterflooding (LoSalTM) which is planned to be implemented in near future after upgrading water injection facilities.
In this paper, we are going to present various case studies with detailed elements GUPCO followed to accomplish that success in managing giant fields, and how such powerful techniques contributed in maximizing our asset value. We'll explain also what we did from day one highlighting different challenges we faced and how we managed to solve them, and more importantly, we'll elaborate our experience in dealing with giant fields under all levels of field's maturity, highlighting the importance of many tools we've utilized. And ultimately, proposing guidelines to be followed whilst applying Waterflooding for utmost benefit.