bluuebunny/crossref_metadata_2025_split huggingface dataset:
Subsurface design for safe, efficient and reliable Carbon Dioxide storage projects
Authors: Wilkinson John Roland , Szafranski Robert C. 
Published: May 2016

Abstract
Over the past several decades the oil and gas industry has developed full-system approaches for safe and cost-effective injection of methane, carbon dioxide and acid gas. Projects have been executed successfully in formations spanning a full range of depths, reservoir quality, pressures and temperatures. Injection has been into both aquifers and hydrocarbon bearing intervals. Lessons learned about site selection, storage design and site monitoring are directly applicable to current and future CO2 geo-sequestration projects. The standard for performance for geo-sequestration projects, as defined by the USA National Energy Technology Laboratory, is for 99+% permanence of storage and 30+% efficiency of pore space utilization. The focus of this paper will be on project design and well completion options to manage plume growth and promote safe, efficient and reliable storage in different geologic settings. Safe and reliable long term storage of carbon dioxide within a defined permit area will require knowledge and observance of limits on cap rock fracture pressures, formation stratigraphy and properties, knowledge of formation spill points and calculation of maximum rates of injection. Optimum design will achieve both permanence of storage and efficient use of pore space to mitigate adverse sweep related to gravity override of injected gas. To manage these issues in deep saline formations, with or without closed anticline structures, may require inclusion of brine withdrawal as part of the project design. Options for achieving the above will be discussed in the context of a staged development process.
By use of specific examples across a range of possible storage scenarios this paper will illustrate that site specific data, combined with detailed dynamic modeling, is very important to a complete assessment of storage site capacity and to design well completions that will achieve project objectives.
Hibernia Q Block - Waterflooding to Increase Field Liquid Recovery with the Presence of a Gas Cap
Authors: Stright Rita , Stylianides George Christos , Stackel Andrew W. , Ozen Ozgur 
Published: May 2016

Abstract
The problem cased by wax deposition during production and transportation of waxy oil has been receiving an increasing attention from the industry, especially with the off-shore projects expansion recently. Due to the high cost of those projects, an accurate modelling on wax precipitation and deposition is imperatively required to facilitate the design, development, and operation of those projects. While the wax precipitation models depict the thermodynamic behaviour of waxy oil, the modelling of wax deposition in production facilities and pipelines focuses on how soon wax would accumulate. The wax deposition simulation appears to be a more challenging task due to the high complexity and limited measured data available in the open literature. In this work, a compositional simulator is introduced to simulate the wax deposition in a pipeline. This model is founded on a thermodynamics model from our previous work and equipped with major wax deposition mechanisms as well as tuning function. Through four case studies, the model, with its prediction and tuning capability, has demonstrated a practical tool in flow assurance simulation. The results also suggest that a promising methodology can be applied in flow assurance study when the simulator is tuned with measurements from the high pressure deposition cell.
Acidizing Treatments for Tight Gas Sandstone Reservoirs
Authors: Al-Anazi Hamoud A. , Assiri Wisam J. , Al-Malki Bandar H. , Al-Kanaan Adnan A. 
Published: May 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
Stimulation of tight gas sandstone reservoirs is a challenge due to many variables contributed into acidizing efficiency such acids type, concentration, volume, stages, injection rate, reservoir temperature, fluids, and heterogeneity, clay type and content, and soaking time. The presence of authigenic clays in reservoirs necessitates proper design of acid treatment to avoid undesirable interaction of these clays with acids and released to cause pore plugging. Therefore, stimulation fluids need to be properly selected to avoid potential adverse results in these tight reservoirs.
The objectives of this study were to: investigate effectiveness of various acid recipes to stimulate Devonian sandstone tight gas reservoirs, determine the optimum acid formulation, and recommend the best practices to enhance stimulation treatments in gas wells.
Extensive laboratory experiments (compatibility, stability, solubility, corrosivity, and coreflooding) were conducted on sandstone cores recovered from gas reservoirs to assess the effectiveness of various acid formulations (organic, inorganic, and mud acids) and additives in enhancing gas relative permeability. A new acid treatment was developed and created wormholes in tight cores and resulted in increasing cores permeability by more than 12 fold. This recipe promoted reaction with silicate more than with clays to avoid potential of by-products precipitation while maintaining cores integrity. However, full strength mud acid found to cause core disintegration and sanding. An organic clay stabilizing agent was effective in stabilizing clays and preventing precipitation of acid reaction by-products. Experimental results are very promising and promoted field trials.
This study proposed an effective stimulation formulation for enhancing production of gas wells with low permeability or suffered from formation damage. It gives some guidelines on better practices for stimulation design to reduce flowback time needed to lift spent acid and help to achieve maximum production. Several candidate gas wells were selected for field trials using the proposed stimulation treatment. This paper will discuss results of the field trials, upon execution, along with damage diagnosis for the wells which were showed unexpected low productivity.
Sour Weight Loss Corrosion Management: An Extensive Review of Present Field Experience
Authors: Bonis Michel 
Published: May 2016

Abstract
A wide review of field experience on Sour Weight Loss Corrosion (SWLC) is summarized in this paper, from 127 distinct field cases documented either from in house experience or external sources covering oil and gas producing facilities, wells and surface facilities. This gives access to a large practical background and to quantitative information which allows better documenting corrosion rates, discriminating corrosion factors and lastly recommending consistent mitigation solutions.
It is shown that SWLC is frequently much lower than Sweet corrosion in comparable operating conditions except for the H2S content. Unfortunately there are specific and still not easily predictable conditions which may lead to very severe localized corrosion. Although quite rare, these cases are impressive as corrosion rates are currently above 10 mm/yr, even in apparently mild conditions.
Leading and secondary corrosion factors are brought out from this analysis. The flow velocity and flow regime are shown to be the most leading factors of the transition between negligible and intermediate and severe corrosion categories. It is also highlighted that very severe corrosion cases require "pit promoters" (sulfur, oxygen, bacteria…) and a galvanic effect with surrounding non corroding surfaces.
It is now needed to better understand key SWLC mechanisms before pretending assuring a reliable SWLC prediction over the whole range of possible operating conditions of our future sour fields. This is now the next step of this long term activity on SWLC. Nevertheless this review already allows defining preliminary criteria to classify any application between the 3 given categories. At the same time it provides a number of possible "analogues" to new developments.
The definition of leading corrosion factors is also used along this paper to introduce the most appropriate mitigation solutions. It is particularly outlined that mitigation solutions on C Steel facilities must be as much focused on the avoidance of detrimental factors such as oxygen, sulfur, solids, bacteria, dead legs and on the promotion of sufficiently high flow velocities … as on chemical treatments.
A Proven Approach to Mitigating Drilling Vibration Problems in offshore Western Australia
Authors: Craig Andrew David , Hanley Chris , McFarland Brad , Shearer David Robert , King Patrick David 
Published: May 2016

Abstract
NOV Downhole has developed a new approach to systematically model the potential for vibration in a given drilling application using computational and analytical methods. This approach utilizes a custom set of software tools to evaluate the drillstring natural frequencies.
The software allows the user to construct a finite element model of the Bottom Hole Assembly (BHA) and drillstring system using geometric and material definitions of the individual components that make up the entire drilling system. The software also permits the user to define a three-dimensional well path. Additionally, the user defines specific application variables that are used by the software as the calculation routines run, such as the drilling fluid densities and Weight-On-Bit (WOB) ranges for the drilling intervals evaluated.
In these calculation routines, the software identifies the operating RPM's at which the BHA and drillstring system will resonate in the axial, lateral, and torsional directions at a variety of depths along the well path and with the different WOB ranges specified by the user.
A case study will be presented where the software package was used to identify resonant vibration as the cause for a catastrophic drillstring failure. The drillstring model in the software was further validated on the following well by data from a downhole dynamics recorder. For the next well drilled by the Operator, vibration "roadmaps" were created using the software package to clearly represent high risk resonant vibration zones for use at the rigsite. Rig personnel were trained on the application of these roadmaps and drilling parameters for all sections on the well were selected based on this information.
As a result of this pre-drilling analysis and real-time application high risk vibration zones were avoided and the drillstring did not experience the large amplitude resonant vibration observed on previous wells, reducing the risk of drillstring failures.

Introduction
Drillstring vibration has been identified as a leading cause of drilling inefficiency and Non-Productive Time (NPT). Excessive drilling vibration can result in such problems as downhole tool or electronics failures, increased fatigue rates, twist-offs or other mechanical failures1,2.
Historically, drilling vibration problems have been addressed with basic sets of rules associated with general drilling practices. These can include reduced bit and drilling parameter aggressiveness, changes to the drillstring such as adding complex tools to absorb the impact of vibrations, altering the design of individual components, or in extreme cases the removal of expensive components liable to failure. More recently, the use of real-time monitoring for reassurance has become commonplace. Most of these methods have negative consequences including reduced ROP and increased cost and do not often address the root cause of the problem.
Multi-Layer Testing: Theory and Practice
Authors: Ansari Asfandiar Mehdi , Mahmoud Yahia I. 
Published: May 2016

Abstract
Pressure transient analysis (PTA) for a multi-layer well, producing commingled from more than two non-communicating reservoirs, has always been a challenge. To address this challenge, innovative data acquisition techniques and novel multi-layer analysis procedures were developed in the 1980's. However, very limited practical application of these theoretical procedures has been reported in the literature.
This paper attempts to fill in this important gap. The paper summarizes the practical application of different theoretical multilayer testing (MLT) data acquisition and procedures to commingled wells in the RasGas Company Limited (RasGas) operated area of Qatar's North Field, the largest offshore non-associated gas reservoir.
Comparison of the different MLT analysis methods as applied in RasGas suggests that the rate-normalized (RN) PTA method, despite its strong theoretical basis, is the least reliable in this field application. On the other hand, in spite of their theoretical limitations, results from the Selective Inflow Performance (SIP) method obtained during this work are more reliable and consistent with other observed data (cross-flow, well productivity, etc).
Based on the above work, a way forward in MLT analysis has been developed, relying on the SIP testing approach to provide not only information on changes in individual layer pressures, but also reliable time-lapse changes in individual layer productivity, which is very important for monitoring individual reservoirs in commingled wells.

Background
The North Field, located offshore in Qatari waters, represents the largest accumulation of non-associated gas in the world. RasGas Company Limited is one of the major operators of the North Field in Qatar, producing since 1999.
Ages and Correlation of Cenozoic Strata of Iraq
Authors: Grabowski George J. , Liu Chengjie 
Published: May 2016

Introduction
Cenozoic strata are important reservoirs and seals for oil and gas in Northeast Iraq. Correlation of these strata traditionally has been lithostratigraphic, with formations placed within a general age framework based mainly on larger benthic foraminifera. However, the age ranges of many of these fauna are long, and in some cases the fauna are specific to depositional environments, thus limiting their utility in basin-wide correlation. In addition, many of the Miocene-Oligocene rocks are unfossiliferous, including evaporites, which precludes the application of biostratigraphy.
We have been revising the ages of the Cenozoic strata of Iraq using samples from 56 subsurface and outcrop sections from the Iraq Petroleum Company (IPC) collection. We have studied 85 samples of basinal marls for plankton biostratigraphy (planktonic foraminifer and nannofossil) and analyzed 265 samples on shelfal carbonates and anhydrites for strontium stable isotope (87Sr/86Sr) age-dating. Identification of microfossils from many thousands thin sections provides supplementary age constraints. This study is also supported with reevaluation and incorporation of existing IPC biostratigraphic interpretations. With the improved chronostratigraphic framework, we have reinterpreted and correlated depositional sequences in widely spaced regional wells and outcrops and large numbers of wells within fields.
The work has resulted in new age interpretations and correlations of the Cenozoic strata of Iraq and revisions in the interpretation of the Cenozoic depositional history of the region. This impacts our understanding of the distribution of reservoirs and seals for petroleum exploration as well as the correlation of reservoir units within fields. The ages also constrain the timing of closure of the Tethys Ocean, formation of the Zagros Foldbelt, and evolution of Mesopotamian Trough.

Paleocene-Eocene
Paleocene-Eocene strata lap onto an unconformity at the top of the Cretaceous (Figure 1), with the basal sediments as old as Danian-Selandian in the folded Zagros Mountains, South Iraq, and parts of west-central Iraq. Thick shelf-margin carbonates formed in the Eocene along the northeastern side of the northwest-trending Mesopotamian Foredeep. These shelf-margin carbonates prograded into the basin, where much thinner basinal facies accumulated. The basinal Paleocene and Lower Eocene Aaliji Formation is absent in the central part of the basin, where the oldest Cenozoic unit is the Jaddala Formation, which ranges in age from Lutetian to Bartonian. These rocks are absent due to non-deposition by onlap and/or downlap as revealed in seismic lines, or because the section is highly condensed and not represented in well and outcrop sections. Bartonian and Priabonian shelfal and shelf-margin carbonates are absent locally due to presumed Miocene erosion around Kirkuk Field (Figure 2).
Sequence Stratigraphic Framework of the Arab Formation Reservoirs, Dukhan Field, Qatar
Authors: Stephens Nat P. , Puls Dave , Albotrous Hilal , Al-Ansi Hussain , Fahad Al-Tamimi 
Published: May 2016

Abstract
In the Upper Jurassic Arab C and D reservoirs, three 3rd-order sequences are interpreted in Dukhan Field, Qatar and are refered to as the Kim1, Kim2, and Kim3 sequences (after Hardenbol et al., 1998). At Dukhan, the Arab C and D reservoirs have produced since 1949. Over 800 wells have been drilled in Dukhan, 180 of which have been cored. Based on sedimentological analysis of the cores, environments of deposition (EODs) have been assigned to cored wells. Twenty three EODs were identified and grouped into five facies tracts: Sabkha, Beach, Ramp Interior, Ramp Crest, and Outer Mid Ramp. Parasequences and parasequence sets were recognized in the core data, and sequences were interpreted from the parasequence stacking patterns as well as evidence for exposure. Log-based correlation provides a method for extending the sequence stratigraphic framework from cored to uncored wells across the field.
Within a sequence stratigraphic framework, the spatial positions of facies tracts and corresponding EODs are predictable. Based on lateral changes in EODs and onlap patterns, we have determined that deposition dip is towards the northeast. Capping the Kim1 sequence, the Arab D consists of a 20 foot thick interval of cross-bedded, coated-grain grainstone in the southern portion of the field. To the north, the grainstone package of the Kim1 sequence passes into a deeper-water EOD with a higher percentage of packstone and wackestone. Above the Kim2 sequence boundary, a transgressive wedge thins toward the south. The Kim2 sequence contains Ramp Interior and Beach facies tracts that prograde to the northeast. The top of this sequence occurs in the Sabkha facies tract. The Kim3 sequence is initiated by the Lower Qatar Anhydrite, a regional feature that forms a seal between the Arab D and C reservoirs. The transgressive system tract of the Kim3 sequence is capped by coarse grain beaches and shallow subtidal lagoon EODs of the lower Arab C reservoir. The maximum flood is indicated by distinctive thrombolitic horizons in core. The upper Arab C represents the highstand of the Kim3 sequence and is composed of upward thinning and increasingly restricted EODs of the Sabkha facies tract.
In the Arab C and D, reservoir quality is highly influenced by depositional texture. Well-sorted, cross-bedded grainstones in the shoal and beach EODs consistently have excellent interparticle porosity with permeability over 100 mD and commonly exceeding 1000 mD. Deeper-water EODs consists of a greater percentage of packstone and wackestone with intraparticle porosity and microporosity. These low-energy EODs typically exhibit permeability less than 20 mD. Sabkha EODs are of low to moderate reservoir quality except where dolomitization has improved permeability. Placing EODs in a sequence stratigraphic framework provides a method by which we can predict lateral changes in rock properties and, within 3D geologic models, distribute rock properties insightfully.
Qp Approach for Pipeline Integrity Management in Mature Production Fields
Authors: Amara Kamal Ben , Al-Sulaiti Rashed 
Published: May 2016

This reference is for an abstract only. A full paper was not submitted for this conference.
Mature production field operators are faced with various challenges to operate assets under safe but yet economical practices. These challenges range from changing flow characteristics, particular higher water cuts, higher demands for optimized production and more tight economics. Integrity of equipments present in the process circuit represents one of the major challenges operators are faced with. Pipelines represent the backbone of the whole circuit and their integrity and capability to ensure safe and continuous flow is of paramount importance to operators. Within this discipline, limitations of survey and inspection technologies, the high volume of data generated by these inspection activities and intrinsic uncertainties imbedded within theses technologies make these challenges even more challenging. In this context QP approach was to create an integrity environment based on an integrated approach involving latest technologies in data processing, Geographic Information Systems, Corporate Reference Documents for best practices endorsed at corporate level to address these challenges. The paper aims at discussing these approaches and share experience with other operators in this regard.
Constraining in-situ stresses at BETA by analysis of borehole images and downhole pressure data
Authors: Pei Jianyong , Wessling Stefan , Hartmann Andreas , Bartetzko Anne 
Published: May 2016

Abstract
This paper presents the analysis of in-situ stress magnitudes from observed borehole failures. Knowledge about the state of in-situ stress is important for many applications in the petroleum industry such as predicting sanding potential and reservoir behavior during depletion, and defining the range of safe mud weights to prevent lost circulation or wellbore collapse while drilling.
Borehole breakouts and drilling-induced tensile fractures revealed by wellbore image logs are often used to determine the orientation of principal stresses and to constrain stress magnitudes. One difficulty encountered in doing this is a lack of knowledge of the specific wellbore conditions, including mud pressure and temperature, at which each feature occurred. While-drilling images are acquired a very short time after the drill bit has passed the formation. It is however possible to use while-drilling images to pinpoint the time interval during which failures initiate and to monitor failure growth overtime, since continuous downhole annular pressure measurements provide constraints on conditions under which the failure has occurred.
Using wireline acoustic image data from one well, and LWD high-resolution resistivity images in a second well, we demonstrate the approach and evaluate the resulting uncertainties. Although use of real-time data does reduce uncertainties, the uncertainty in the magnitude of maximum horizontal stress remains large due to uncertainties in the formation strength. Therefore, the results presented are preliminary, and will be improved in later research when better data are available.

Introduction
BETA (the Baker Hughes Experimental Test Area) is located south of the city of Tulsa, in northeastern Oklahoma. It is a unique field research facility where downhole tools can be tested and various researches can be performed. Over time, more than one hundred wells were drilled at BETA and therefore an abundance of well logging data is available. The geology at BETA has been carefully studied based on core analysis and the lithology is well known [10]. Bedding is flat-lying and laterally continuous, and therefore measurements made in one well can be applied with little depth correction to other wells.