bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effects of Gas Additions to Deepwater Gulf of Mexico Reservoir Oil: Experimental Investigation of Asphaltene Precipitation and Deposition
Authors: Gonzalez Doris L. , Mahmoodaghdam Elham , Lim Frank , Joshi Nikhil 
Published: October 2012

Abstract
Conventional primary and secondary water flooding of Deepwater Gulf of Mexico (GOM) reservoirs typically result in substantial un-recovered oil providing an attractive target for enhanced oil recovery (EOR) processes. One of the challenges of applying EOR gas injection in these offshore reservoirs is the h igh oil asphaltene content. Anadarko Petroleum Corporation and Schlumberger have jointly investigated the effects of gas addition on the phase behavior of oil, especially its effect on asphaltene precipitation and deposition. The study focuses on the experimental results from various tests showing the instability of asphaltenes in oil from various gas injection scenarios.
Three common EOR injection gases: nitrogen (N2), carbon dioxide (CO2) and methane (CH4) were studied. N- heptane was (n-C7) also included for comparison of solids phase behavior during depressurization. Most asphaltene laboratory testing use n-C7 at ambient conditions, whereas asphaltene precipitation occurs with change in pressure and temperature during reservoir depletion processes.
The study collected PVT and flow assurance data for original live fluid and for additions of N2, CO2, CH4 and n- C7 at high pressure and temperature conditions. Measurements include asphaltene onset pressure (AOP), saturation pressure (Pb), swelling tests and asphaltene deposition tests. Other basic measurements of the corresponding dead oil include SARA analysis, viscosity, density and fluid characterization. Fluids from the field presented a compositional variation with a variety of asphaltene contents from 4 to 15.5%.
Results of experimental flow assurance assessments revealed the black oil has high propensity for asphaltene precipitation due to addition of injected gas. The addition of N2, CO2 or CH4 significantly aggravates the asphaltene precipitation condition of these fluids.
The comparison between the three gases showed that, when added in the same mole proportion, N2 was the strongest precipitant followed by CH4.
Reservoir Connectivity Analysis Using Long Term Interference Testing in a Waterflood Pilot in the Carbonate Marrat Formation of the Greater Burgan Field, Kuwait
Authors: Gazi Naz , Ali Farida , Al-Naqi Meqdad , Dashti Laila , Al-Qattan Abrar , Al-Farhan Farhan 
Published: October 2012

Abstract
Interference testing although primitive in terms of its introduction and idea to the petroleum industry, still stands to this day as one of the most cost effective and efficient ways of establishing communication between wells and determining the reservoir transmissibility in the region.
This paper discusses the methodology and results obtained from a four month pressure data acquisition campaign for a transient interference test performed in a carbonate reservoir known as Marrat, in the Giant Burgan field of Kuwait.
The Marrat long term interference test was conducted around a water injector pilot with distances as far as 0.9 km at the subsurface locations between the injector and producer wells. Therefore, the interference test was used to evaluate the transmissibility between the injector and the nearby observation wells. The producer wells were shut-in for the entire length of the test so as not to create any disturbances that could hinder the interpretation processes. After conducting this test, a better understanding of the subsurface uncertainty as well as communication between the wells was highlighted. Other objectives were added to the tests which were to determine the water bank distance from the injector, as well as to describe the least resistive path that the water prefers to travel in.
The tests showed that not all the wells responded to the pressure pulse, and therefore the assumption that a fault was isolating one of the wells. One of the main conclusions was a strong directional transmissibility that was at first associated with a high permeability corridor corresponding to the depositional environment. The other conclusion was the orientation of the fracture plane which could cause this high directional transmissibility. A comparison and integration of the acquired pressure data with a separate geologic stochastic model was constructed and discussed in this paper.
Based on the integration work of the interference test and the geologic study it was therefore concluded that a secondary recovery using water flooding would be beneficial and necessary for sustaining Marrat reservoir production in the long term based on the location of both producer and injector wells.
Extreme HPHT Wireline Data Acquisition: Planning for Success
Authors: Owens J. , Parry G. , Taylor B. 
Published: October 2012

Abstract
Data acquisition in extreme environments of high pressure and/or high temperature (HPHT) with pressures up to 30,000 psi and temperatures up to 500°F requires not only specialist technology capable of surviving these conditions, but also many months of preparation and planning to ensure a successful operation.
The aim of this publication is to provide an overview of what is involved in the planning, preparation and execution of an extreme HPHT wireline data acquisition, from the customer setting the information objectives through to data delivery. This includes developing an agreed quality plan between the data provider and the customer covering testing and deployment of the latest extreme HPHT logging equipment.
All aspects must be considered to minimize risks including detailed tailoring of the logging programmes to manage time in hole, ensure accurate depth control and by employing a deployment risk management process, to ensure that what goes in the hole comes out again.
The implementation of these procedures is illustrated with a case history of a series of HPHT exploration wells drilled in the Central Graben of the North Sea (the "HPHT Heartland" of the North Sea). Bottom hole conditions were predicted to approach 400°F and 15,000 psi. These extreme conditions negated the use of conventional wireline tools and so, from initial early planning discussions between client and service provider, new detailed programmes were designed and implemented as a specific "Quality Plan" to use the advanced HPHT wireline logging tools.
Integrated Reservoir Delineation and Development of Deep, Tight Carbonates: Kuwait Case Study
Authors: Al-Anzi Ealian H. , Rao Narhari Srinivasa , Al-Ashwak Samar , Kidambi Vijaya Kumar , Al-Ajmi Neema Hussain , Rao Jonna Dayakar , Al-Ateeqi Khalid , Al-Mayyas Rawan Hussain , Al-Anzi Abdullah Motar , Allan Stefanic Odreman , Acharya Mihira N. , Chakravorty Sandeep , De Kyser Tom 
Published: October 2012

Abstract
Deep, tight carbonate reservoirs of Pliensbachian, Sinemurian, and Hettangian Stages of the mid-Mesozoic Era are becoming very important in the continued pursuit of hydrocarbon prospects in North Kuwait. At present, a total of 21 wells have penetrated the targeted reservoir zones. Of these, 12 have been tested for hydrocarbon production covering a large area of about 1700 sq km. Further, six wells have produced oil and gas, with two deemed commercially successful.
The entire workflow to characterize these reservoirs is focused on delineating faults and associated fractures in individual wells. Detailed seismic study and volume curvature maps, revealed the existing fault and fracture corridors. Sub-seismic faults and subtle reverse faults with fractures were detected by log correlations and borehole image. Due to paucity of cores in these zones, descriptions of cuttings samples were used to identify faults and fracture zones, based on the presence of large euhedral crystals in the midst of cryptocrystalline dolomite, suggesting the percolation of hydrothermal fluids through fractures.
Many of the wells were drilled with an overbalanced mud system, leading to near-borehole porosity and permeability damage to the rock matrix and to the fracture system. Damage to natural fractures intersecting the well can prevent their detection, leading to missed potentially productive intervals. Mobility of hydrocarbons in these tight, fractured carbonate reservoirs depends upon (i) wells intersecting a natural fracture system that is sufficiently permeable and connected to a large volume of reservoir rock and (ii) the near-borehole area not having suffered irreversible damage due to overbalanced drilling.
In summary, the proposed reservoirs are very tight carbonates (average 3 pu porosities) and a fracture play is considered to be the key factor in production. Acid stimulation produced multifold increases in productivity. Most of the wells were drilled overbalanced, which has negative impact on the producibility due to formation damage.
First Fully Sulfide Stress Cracking Resistant Drillpipe System
Authors: Jellison Michael , Redlinger Thomas , Howie William 
Published: October 2012

Abstract
As the severity of sour drilling applications has increased, the requirement for drill stem materials resistant to sulfide stress cracking (SSC) has accelerated. Sour service drillpipe, traditionally manufactured with SSC resistant upset tubulars and tool joints, has been available for some time. Sour Service drillpipe metallurgy is not specifically controlled by NACE MR 0175/ISO 15156,1 however these tubulars and tool joints are often evaluated in accordance with the standard. The friction welds joining the upset tubulars and tool joints were not resistant to SSC and were not evaluated. This has been acceptable for many sour drilling applications since the weld is not the mostly highly stressed region of the drillpipe joint and because the operator has a certain degree of control over the environment through the drilling fluid properties and additives. As more severe environments with higher Hydrogen Sulfide (H2S) concentrations were identified for exploration and development, it became apparent that a fully SSC resistant drillpipe system including the friction welds was necessary.
This paper presents the successful development and qualification of SSC resistant friction welds for critical sour applications. It describes the engineering and manufacturing philosophy employed, laboratory testing procedures with results presented and applications for the SSC resistant drillpipe. Since NACE MR 0175/ISO 15156 does not address friction welds the engineering team developed unique and innovative criteria together with testing procedures for the new weld technology. A new patent pending four-point bending test procedure and fixture were developed that employed unpolished samples that represent the surface finish of the product in service, in contrast to the polished samples used in NACE TM0177 testing. This paper provides background information on the evolution of sour service drillpipe and reviews case histories where sour service drillpipe has been successfully used including the new pipe with SSC resistant friction welds. The paper can benefit drilling engineers involved in critical sour drilling operations.
A Variational Approach to the Numerical Simulation of Hydraulic Fracturing
Authors: Bourdin Blaise , Chukwudozie Chukwudi , Yoshioka Keita 
Published: October 2012

Abstract
One of the most critical capabilities of realistic hydraulic fracture simulation is the prediction of complex (turning, bifurcating, or merging) fracture paths. In most classical models, complex fracture simulation is difficult due to the need for a priori knowledge of propagation path and initiation points and the complexity associated with stress singularities at fracture tips.
In this study, we follow Francfort and Marigo's variational approach to fracture, which we extend to account for hydraulic stimulation. We recast Griffith's criteria into a global minimization principle, while preserving its essence, the concept of energy restitution between surface and bulk terms. More precisely, to any admissible crack geometry and kinematically admissible displacement field, we associate a total energy given as the sum of the elastic and surface energies. In a quasistatic setting, the reservoir state is then given as the solution of a sequence of unilateral minimizations of this total energy with respect to any admissible crack path and displacement field. The strength of this approach is to provide a rigorous and unified framework accounting for new cracks nucleation, existing cracks activation, and full crack path determination (including complex behavior such as crack branching, kinking, and interaction between multiple cracks) without any a priori knowledge or hypothesis.
Of course, the lack of a priori hypothesis on cracks geometry is at the cost of numerical complexity. We present a regularized phase field approach where fractures are represented by a smooth function. This approach makes handling large and complex fracture networks very simple yet discrete fracture properties such as crack aperture can be recovered from the phase field. We compare variational fracture simulation results against several analytical solutions and also demonstrate the approach's ability to predict complex fracture systems with example of multiple interacting fractures.
Transitional Kick Tolerance
Authors: Santos Helio , Sonnemann Paul 
Published: October 2012

Abstract
Kick Tolerance (KT) is commonly defined as the maximum volume of a given type of influx (typically gas) which can be successfully contained and circulated out of a well using the Driller's Method. Used properly, many companies believe KT calculations help to quantify safety margins that exist between expected wellbore conditions and incrementally higher well design limits. However, one big issue in the industry today is the lack of consistency about KT calculation, leading to significant confusion and increased risk. Situations occur when drilling a well in which one company involved may argue that there is enough KT to keep drilling, whereas another company argues the opposite. Another factor limiting the value of most kick tolerance methods employed today stems from almost exclusive focus on the KT at the end of a hole section, without accounting for erratic trends of pore pressure and possible deviations from the drilling program. Confusion and lack of standards regarding KT often prevents effective use of the concept to assess the risks while drilling. After a brief introduction describing the two most common methods used to calculate KT, the paper presents an example highlighting the limitations and issues when using the current approach to calculate KT. In the example, KT is sufficient to meet various company policy requirements, but control of the well is lost when a kick within original well design limits enters the well. The concept of Transitional Kick Tolerance is then introduced, which has been developed to overcome the limitation caused by focus on single point KT calculations and which provides substantial benefits in the context of changes that occur while drilling the section.
First Successful Rigless Conversion of Subsurface Safety Valves from Tubing Retrievable to Wireline Retrievable in the Middle East
Authors: Yateem Karam S. , Hanbzazah Shadi M. , Alsyed Samih M. , Fouad Alaa , Mahamed Saleh M. 
Published: October 2012

Abstract
In the oil and gas industry, safety systems are put in place to prevent the release of hydrocarbons and protect assets against any undesirable events. This can be accomplished by installing protective measures that monitor the process components, and can also control the process in case of undesirable events. The Surface Controlled Subsurface Safety Valve (SCSSSV) is one major component, which is mainly installed in wells that are located offshore or close to populations and environmentally sensitive areas. These SCSSSV can be categorized into two types depending on the deployment/retrieval methodology. The first type is referred to as the Wire Line Retrievable Subsurface Safety Valve (WLRSSSV), which is installed and retrieved by rigless well intervention and installed inside the production tubing. The other type is the Tubing Retrievable Subsurface Safety Valve (TRSSSV) and these valves are part of the tubing completion.
Due to its numerous advantages, like full bore access, and not to retrieve the valve before any intervention, TRSSSV are gaining more popularity. Saudi Aramco uses these types of valves and most of the new completions are designed with TRSSSV. Unfortunately, as these types of valves are part of the completion, any failure to close these valves results in a disturbance in the safety system of the well, which will lead to performing an expensive workover, which is not only costly but the process means killing the well, and therefore inducing damage to the reservoir.
This paper presents in detail the procedure applied to these inoperable TRSSSVs to regain the safety of the wells and put them back on production without the need to de-complete the well. The direct business impacts are restoring the well safety system, wells’ productivity in addition to cost avoidance of (onshore and offshore) workover operation to replace the malfunctioning TRSSSVs. The paper will also cover common mitigation measures to mitigate TRSSSV failure and avoid their conversion.
Implementing Knowledge-Sharing Systems and Establishing a Culture to Share Lessons Learned Within a Multidisciplinary Company Enhancing Effective Knowledge Transfer
Authors: Hinze Iris , Perry Phil , Jacob George T. , Wise Wade V. 
Published: October 2012

Abstract
Today's oil and gas industry relies increasingly on integrated multi-disciplinary services to provide effective risk management, wellbore and reservoir delivery while minimizing operating costs, cost of failure and non-productive time (NPT). New collaboration technologies enable the rapid storage, transfer and consumption of information and require robust but flexible knowledge management techniques to fulfill the requirements of a global learning organization.
New tools need to be developed and successfully implemented tools need to be expanded to enable cross-disciplinary teams and communities the ability to capture, share and reuse validated knowledge efficiently. This paper presents how a single-domain lessons-learned system was extended to represent the entire spectrum of the upstream industry; assuring interdisciplinary information is reusable in multiple communities and market segments.
The paper presents the challenges inherent in leveraging a common classification scheme; lessons-learned framework, enterprise platform, and search-and-retrieval systems with the goal of connecting people and making the collective knowledge seamlessly accessible across different business units, time zones and geographies.
Also discussed is how building a common framework and incorporating the lessons-learned system into communities of practice, training and certification programs helps drive acceptance/implementation of the program.
Finally, we showcase how the system has been used to deliver game-changing performance in time savings to locate relevant information and how re-use of stored knowledge enables performance improvements in wellbore delivery.
Production Increase with Electric Heating Production Line Technology in an Extra-Heavy Oil Field in Colombia: Successful Case of Flow Assurance
Authors: Escobar-Remolina J. C. , Barrios W. , Ecopetrol S. A , Silva B. 
Published: October 2012

Abstract
In recent years the oil industry has focused primarily on the exploitation of heavy and extra-heavy oil reservoirs. On the other hand these crudes represent current worldwide one of the greatest potential contributions to reserves to the energy industry. The production, treatment and transportation of these crudes are a real challenge, because these crudes increase the viscosity exponential from the reservoir to the gathering collection plant. This causes a dramatic increase in the well pump pressure system, reducing the production capability of the lifting system and optimal management of fluids, resulting in lost in the flow assurance system committing millions of dollars annually in non-effective remedial techniques. This article describes a successful case of flow assurance technology application to an extra-heavy oil of 9.0 °API, using electric heating of the well production line along 900 meters in a Colombian oil field. The selected well to apply this technology increases its daily oil production over 160%, well head pressure decreases 95%. Chemical dosification was optimized and BS&W values required by the control system were reached by heating technology. Additionally, lighter crude of 25 °API, used as a diluent, to move this extra-heavy oil through the production line was avoided in 100%.
Forecasting Gas Production in Organic Shale with the Combined Numerical Simulation of Gas Diffusion in Kerogen, Langmuir Desorption from Kerogen Surfaces, and Advection in Nanopores
Authors: Shabro V. , Torres-Verdín C. , Sepehrnoori K. 
Published: October 2012

Abstract
We introduce a new numerical algorithm to forecast gas production in organic shale that simultaneously takes into account gas diffusion in kerogen, slip flow, Knudsen diffusion, and Langmuir desorption. The algorithm incorporates the effects of slip flow and Knudsen diffusion in apparent permeability, and includes Langmuir desorption as a gas source at kerogen surfaces. We use the diffusion equation to model both lateral gas flow in kerogen as well as gas supply from kerogen to surfaces.
Slip flow and Knudsen diffusion account for higher-than-expected permeability in shale-gas formations, while Langmuir desorption maintains pore pressure. Simulations confirm the significance of gas diffusion in kerogen on both gas flow and stored gas. Relative contributions of these flow mechanisms to production are quantified for various cases to rank their importance under practical situations.
Results indicate that apparent permeability increases while reservoir pressure decreases. Gas desorption supplies additional gas to pores, thereby maintaining reservoir pressure. However, the rate of gas desorption decreases with time. Gas diffusion enhances production in two ways: it provides gas molecules to kerogen-pore surfaces, hence it maintains the gas desorption rate while kerogen becomes a flow path for gas molecules. For a shale-gas formation with porosity of 5%, apparent permeability of 59.7 μD, total organic carbon of 29%, effective kerogen porosity of 10%, and gas diffusion coefficient of 10−22 m2/s, production enhancements compared to those predicted with conventional models are: 9.6% due to slip flow and Knudsen diffusion, an extra 42.6% due to Langmuir desorption, and an additional 61.7% due to gas diffusion after 1 year of production. The method introduced in this paper for modeling gas flow indicates that the behavior of gas production with time in shale-gas formations could differ significantly from production forecasts performed with conventional models.
Autonomous Spilled Oil and Gas Tracking Buoy System and Application to Marine Disaster Prevention System: Part 1
Authors: Kato N. , Senga H. , Suzuki H. , Okano Y. , Ban T. , Takagi Y. , Yoshie M. , Tanaka T. , Sakagami N. 
Published: October 2012

Abstract
This paper describes the ongoing project on autonomous spilled oil and gas tracking buoy system and application to marine disaster prevention system for 5 years since FY2011. The objectives of this project are as (1)autonomous tracking and monitoring of spilled plumes of oil and gas from subsea production facilities by an underwater buoy robot, (2)autonomous tracking of spilled oil on the sea surface and transmission of useful data to a land station through satellites in real time by multiple floating buoy robots, (3)improvement of the accuracy of simulations for predicting diffusion and drifting of spilled oil and gas by incorporating the real-time data from these robots.