bluuebunny/crossref_metadata_2025 huggingface dataset:
Gas Hydrate Problems in Desert of Sultanate of Oman: Experiences and Integrated Inhibition Program
Authors: Nengkoda Ardian , Taha Wael Mohammed Anwer , Al-Harthy Abdulla Salim , Reerink Hendrikus
Published: May 2016

Currently, there are more than 10 oil producing station, in both North and South area operation of Petroleum Development Oman, which facing a unique gas hydrate problems. Most of these wells are producing by the support of gas lift. Therefore, it is very important that the gas lift network is kept optimally operating to maintain the intended production. The ambient temperature in Sultanate of Oman desert drops to as low as 5°C during the coldest 3 months in winter, when hydrates form in several gas lift lines. This causes affected wells to cease production and results in unscheduled deferment. So far, the problem was partly controlled by the use of methanol as hydrate inhibitor (a proven method used worldwide to restrict gas hydrate formation), however there are resulted many issues mainly HSE associated with the use of methanol. The main objectives of this project are to look the other chemicals alternative as hydrate inhibitor - move from methanol to another cost effective and safe chemical inhibitor and the goal is to ensure that the system is adequately inhibited against hydrate formation and that inhibitor injection is optimized. The second goal is to develop a warning system should hydrate start to form (prior to hydrate build up and pipeline blockage). The paper also defines laboratory testing as mandatory requirement to test an alternative hydrate inhibitor and practical facilities up grade.

Introduction

For many years, hydrate formation is a substantial problem oil and gas production, once plugs have formed; there are limited possibilities for removal. Common hydrate problem occur at sub sea pipeline, top side facilities or cold environment. Since the 1970's, the oil and gas industry has faced increasing costs associated with inhibition of gas hydrate formation, due to the development of offshore gas reservoirs. Gas hydrates are likely to form in subsea flowlines unless the water is removed down to the lowest dew point encountered, highly effective insulation is in place, or inhibitors are used. The first option is difficult when supersaturated condensates exist in the flowline even after the gas phase is stripped to saturation levels. Stripping condensate completely of water is prohibitively expensive and effective insulation is beyond current economic limits. Therefore, the most effective solution appears to be the use of inhibitors. Generically, there are two kinds of hydrate inhibitors: thermodynamic inhibitors, and the more recently identified low-dosage inhibitors.
Subsurface design for safe, efficient and reliable Carbon Dioxide storage projects
Authors: Wilkinson John Roland , Szafranski Robert C.
Published: May 2016

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

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.

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

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

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

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

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

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.
Wide Azimuth seismic: azimuthal analysis in offset vector domain for velocity and amplitude
Authors: Boelle Jean-Luc , Lecerf Didier , Navion Sylvain , Belmokhtar Ahmed , Ladmek Abdeljebbar
Published: May 2016

In 2005 a 3D high density wide-azimuth seismic survey was shot over the Irharen area (south east of Timimoun, Algeria). This acquisition was designed to better image the structure but also to improve fracture characterization and mapping, recognized as key in the description of this tight sand reservoir. The use of the offset vector binning concept, introduced by Cary (1999) and Vermeer (2002), on dense wide azimuth datasets is well suited for preserving the azimuthal information. An azimuthal residual velocity analysis based on semblance optimisation by scanning isotropic and anisotropic components of a parabolic elliptical model is proposed and tested successfully. The significant imaging improvement achieved with this land data case demonstrates the accuracy of the extracted azimuthal parameters for a better post-PSTM azimuthal residual moveout. After this correction, Common Image Gathers are ready for an azimuthal analysis of amplitudes. Taking advantage of the good sampling in offset and azimuth directions, the present study investigates the potential of Fourier analysis for describing the azimuthal variations of seismic amplitude.

Introduction

The description of fracturation is a key information to optimize tight or carbonate reservoirs production, as a consequence many studies have been undertaken to get this information from seismic. In particular, anisotropic models have been proposed to link the fracturation to seismic anisotropy, Hudson (1980,1981), Schoenberg et al. (1980, 1995). P wave velocity is then depending on fracture orientation, which may cause azimuthal variation in the seismic velocity field. On the other hand, coefficients of anisotropy may be estimated from azimuthal variations in reflected P wave amplitude (Rüger, 2001).

Wide azimuth seismic acquisitions, which provide a full azimuthal illumination of the structures for a more accurate image, may additionally offer information on fractures orientation through the azimuthal analysis of the seismic response.

To meet these objectives, it is essential that the 3D wideazimuth character of the data be preserved throughout the processing sequence in order to get full benefit from the use of true 3D algorithms. In this perspective, the use of the offset vector binning concept, introduced by Cary (1999) and Vermeer (2002), on dense wide azimuth datasets is advantageous as it preserves offset and azimuth information, even after migration. In the present paper, we show how the Common Offset Vector (COV) processing is used to point out azimuthal variations in the velocity field and analyze the azimuthal variations of the reflected amplitude at a given horizon.
Use of Automated Mineralogical Scanning and Magnetic Anisotropy Techniques to aid Permeability Predictions in Fine Grained Carbonates and Micro-Porous Reservoirs
Authors: Watson Paul , Matthews Anna , Hailwood Ernie
Published: May 2016

I Introduction

The Upper Cretaceous - Danian Chalk Group of northwest Europe is an important producing reservoir in the North Sea. Chalk is a soft fine grained rock composed primarily of calcium carbonate (principally coccoliths), and is highly porous (20% plus porosity values), although most of the pores are sub 1micron in size. Traditionally, silica has been recognised either as fossil tests within this calcareous matrix or as distinct chert layers. Recently, however, XRD analyses revealed unexpectedly high levels of silica in chalk samples that show no obvious presence of silica in SEM and petrological studies. The assumption from these analyses is that the silica is distributed throughout the sample at the microscopic level. As with other fine grained microporous rocks, improved recovery depends on establishing the mineralogical constituents of the rock and the ability of reservoir engineers to extract the hydrocarbons contained within the micropores or microfractures.

In chalk reservoirs, recovery by injection of water depends on the wetting conditions of the rock and compaction by overburden due to water weakening the formation. Recent studies (Strand et al 2007) have concluded that the silica content of chalk is related to differences in wetting conditions and mechanical properties. It is also suggested that silica content may have affected the retention of porosity by inhibiting clay formation, and can also form intra-reservoir barriers.

In order to understand the relationship between permeability and mineralogy (in particular silica content) in chalk reservoirs, two well sections from the North Sea have been studied: Well A and Well B. Core samples studied from these wells span the Ekofisk and Tor Formations. In addition to standard carbonate sedimentological methodologies, samples have also been analysed by QEMSCANTM and MagporeTM techniques. Preliminary results of this ongoing study are presented here.

QEMSCANTM is an automated mineralogical scanning tool which uses a combination of SEM and EDS to evaluate the mineralogy of rock samples. MagporeTM uses magnetic anisotropy to evaluate the pore fabric of the lithologies. By combining these two techniques, it has been possible to define the 3D pore orientation data and relate these to bedding structures and mineralogy. It has also been possible to define various levels of silica within each sample, to map these mineralogically, and then to provide downhole plots which quantify silica concentrations through the well sections.
HSE in Design and Operation for Sour Gas Facilities
Authors: Al-Abri Ahmed Abdullah , Blyth Abi , Jewitt Ian
Published: May 2016

HSE challenges are substantial in sour gas projects; the poisonous nature of H2S introduces the risk of a toxic release with potential to cause multiple fatalities both inside and outside the site boundary.

Learning from recent sour projects emphasises a "keep it in the pipe" philosophy: appropriate materials selection, use of high-integrity components for facilities, wells and flow lines, and removal of as many leak sources as is practicable. Effort is also required to reduce personnel exposure, either through minimum intervention / minimum manning, or by spacing facilities to minimise the impact of a toxic cloud. However, the implementation of these apparently simple elements involves a complex balance of HSE goals against operability, maintainability, availability and Capex/Opex targets. Conflicting factors include:• Very high costs associated with corrosion-resistant materials.• Potential maintainability / operability hindrance associated with removal of leak sources (valves, flanges, instrumentation).• Availability losses imposed by prohibiting online maintenance (forcing turnaround maintenance shutdowns).• Costs and operability difficulties associated with large-scale plant spacing.

The solution lies in a design that optimises these elements to achieve risk levels that are as low as reasonably practicable, or ALARP. In doing so, it is important that the HSE Risk Assessment methodology aligns with the Reliability, Availability and Maintainability (RAM) premises, and that both are underpinned by the Operations Philosophy. This critically requires Operations input from a very early stage of the project.

Emergency Response capability also needs to be considered early in sour projects, since this too will underpin fundamental design and Operations Philosophy decisions such as layout spacing and requirements for cascade air systems and safe refuges. As a result, H2S release detection mechanisms; personnel H2S response training and respiratory protective equipment will also play a critical role in the ALARP demonstration.

Critically, Sour Gas developments should take an asset lifecycle view to understand the feasibility of incremental facility changes, field Simultaneous Operations (SimOps) and replacement of aging equipment.

Finally, there must be a consistent and integrated approach to HSE in sour projects all along the value chain, since the chain is only as strong as its weakest link, and there are no second chances with H2S. "Sour Mindset" responsibility must be demonstrated during design, throughout construction and commissioning, and into operations, by both Company and Contractor personnel. Only by this means can ALARP really be achieved.
Case Study: High Angle Directional Drilling with 9-5/8-in. Casing in Offshore Qatar
Authors: Van Zyl Daniel , Stephens Jeffrey Tod , Turki Mounir , Abed Malek , Al-Athbah Hamad Rashid
Published: May 2016

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

In Qatar, Occidental Petroleum is faced with the task of drilling high angle wells through an unstable formation before entering the productive zone. Casing while drilling is becoming a powerful tool in mitigating both lost circulation as well as wellbore stability issues. The unstable Nahr Umr formation lies directly above the Shuaiba payzone and is typically drilled with 12-1/4-in. bits. The Nahr Umr shale tends to slough in shortly after drilling, leading to stuck BHA's and difficulty running 9-5/8-in. casing. Exposure time with the Nahr Umr is increased due to the requirement of continuous angle building and turning to land near horizontal. This paper details the case history of directional casing drilling (DCD) that have been utilized in offshore Qatar and the lessons learned.
Issues & Design Trends In Onshore Gas Reception Facilities
Authors: Zomerman Jannes Jan , Bradley Adam , Sikkenk Jan , Bras Ed
Published: May 2016

In pursuit of greater safety, lower environmental impact and lower capital expenditure, it is desired to reduce (or preferably eliminate) upstream offshore processing. Specifically for offshore platforms, the biggest capital expenditure savings can be achieved by either designing the offshore production facilities to be unmanned platforms or having subsea completions without a platform. In both cases all produced wellhead fluids will need to be transported untreated to shore in trunklines.

A major contributor to HSE incidents in the upstream oil and gas industry is the logistics of bringing people to and from the platforms by boat or helicopter transport. Being able to avoid the necessity of this people transport will greatly improve the overall safety performance of the gas production.

Furthermore, zero-effluent discharge offshore can be achieved by sending all of the produced fluids to the onshore plant for processing and disposal, as an alternative to the standard offshore processing and reinjection.

A further trend in recent developments is that of poorer-quality feedstock gas. Amongst others gas is becoming more sour, containing up to 40% H2S and up to 70% CO2. This, coupled with the elimination of offshore processing facilities requires the injection of chemicals to combat trunkline corrosion and formation of hydrates. The higher quantities of acid gases, free water (condensed and formation water), injected chemicals and increased corrosion products all have to be handled by the onshore gas-reception facilities that have to produce acceptable quality gas for the downstream facilities.

The onshore facilities also have to be robust for transient conditions like receiving significant slugs of production water during pigging and start up. As the gas and condensate specifications are getting more and more stringent stable operation of the units downstream the slugcatcher is essential to ensure on specification products. To realize this the downstream condensate stabiliser train needs a continuous feed of condensate even when water slugs enter the slugcatcher. Furthermore, potential water breakthrough to the condensate stabiliser train brings challenges to the design of the stabiliser column.

These trends require the onshore gas-reception facilities to do more, and in more difficult circumstances. This in turn is leading to more complex gas-receiving facilities and an increase in the unit's cost. As the experience with the onshore gas-receiving facilities without offshore platform is still building up, it is essential that sufficient time and effort is spent in the design phase to identify the possible risks and challenges.
Fracture characterization of a tight gas reservoir using seismic attributes derived from singular value decomposition of azimuthal AVO data.
Authors: Chao Gabriel , Maultzsch Sonja , Cadoret Thierry , Deplante Christian , Varela Isabel
Published: May 2016

This work presents a pilot study of the application of a seismic inversion technique for fracture density and fracture orientation in an area where available well data revealed the presence of open fractures. The inversion method is based on a singular value decomposition of azimuthal AVO data. This decomposition allows us to calculate seismic attributes which are linked to the fracture density of the fracture network through anisotropic rock physics modeling. The outcome of this pilot study is promising since the obtained results are consistent with existing image log data; however, further testing and research on a larger area are needed to assess if the fracture characterization results are consistent with geological interpretations and other analysises of fracture networks in the reservoir.

Introduction

The characterization of fracture networks in naturally fractured reservoirs can potentially play an important role in the optimization and enhancement of hydrocarbon production. Accurate maps of fracture density can aid in identifying areas of high occurrence of fractures and sweet spots. However, the determination of fracture density is a difficult and challenging problem that often involves the integration of different types of data at different scales. At the log scale, image logs and dipole sonic logs are employed to characterize fractures locally, while at the seismic scale azimuthal AVO and shear wave splitting techniques are used in seismic fracture characterization studies.

In this work we study the application of an inversion method to obtain the distribution of fracture density and fracture orientation in a pilot study covering a small area of a tight gas sand reservoir known to be fractured at least at one well location. The inversion method is based on a singular value decomposition (SVD) of the representative azimuthal AVO responses for the target reservoir. By means of singular value decomposition it is possible to calculate seismic attributes that provide a direct mapping with fracture density. This mapping is then used in the inversion of fracture density. The singular value decomposition method was originally implemented by Causse and coauthors for conventional AVO inversion (Causse et al., 2007). Varela and coauthors extended this methodology to invert for fracture density using azimuthal AVO and applied it both to synthetic data (Varela et al., 2007) and to laboratory experiments in a geological scale model (Varela et al., 2009). It is worthwhile to mention that one of the main advantages of this inversion method is that it is based on exact solutions of the AVOAz response calculated according to a full anisotropic modelling of the fractured reservoir and does not rely on the standard AVOAz approximations (Ruger et al., 1997). The seismic modelling in this work is based on the anisotropic rock physics model of Chapman (Chapman, 2003).
Petroleum Resource Assessment Methodologies and Petroleum Systems Modeling
Authors: Wygrala Bjorn
Published: May 2016

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

Petroleum resource assessments are used to quantify discovered and undiscovered ('yet-to-find') petroleum that is technically and economically recoverable within a certain time frame, typically 30 years. The importance and economic impact of these assessments is enormous, especially in the light of globally dwindling resources. Resource assessments are however made using a range of methods, none of which can be described as being scientifically rigorous, especially in applications in frontier areas or areas with sparse data. Petroleum resource assessment methods can be subdivided into those that are applicable vs. those that are not applicable in frontier areas with only limited or no data. Methods that require detailed production data and therefore cannot be used in frontier areas include material balance, historical performance and reservoir simulation methods. Those that can be used in frontier areas include analogies, volumetric, delphi and Petroleum Systems Modeling methods. The latter is already recognized by leading assessment agencies such as the USGS as providing the most rigorous approach. According to the USGS, "Petroleum Systems Modeling incorporates the geoscience data required for resource assessments in ways that strengthen the assessment process" and "quantitatively extend the 'total petroleum systems' (TPS) that is employed in USGS resource assessments". Petroleum systems modeling can require more effort to compile and structure the data, however it provides clearly superior results as they are based on all of the available G&G data, conceptual models can be used if no data is available, uncertainties can be included in the analysis, all of the controlling parameters are coupled and geologic processes and time are included in the assessment. They offer the only resource assessment workflow which is documentable, logical, repeatable, quantitative and consistent within the contraints of the available data. In this presentation, the authors use both conceptual and real applications to illustrate how petroleum systems modeling is applied to petroleum resource assessments and what the benefits of the methodology are.
Leveraging Emerging Technologies to Increase Production from Unconventional Reservoirs: Case Study of India
Authors: Choudhary Yogesh Kumar , Bhat Sumit , Kumar Arunesh
Published: May 2016

With a sustained growth rate of 6.2%, India is set to become the third largest economy following the USA and Chinaby 2035. In accordance with the growth rate, it is estimated that India's import dependence is likely to increase from the current level of 72% to approximately 90% by 2035. With a large dependency on imports to meet commercial energy requirements, the demand/supply gap in oil and gas in India will inevitably grow. Unconventional energy resources are becoming increasingly more important in the quest for energy security because of the continuing decline of production from proven reserves (4 to 6% decline has been observed in mature fields), accompanied by the increasing price of crude oil and natural gas. Potential sources of unconventional energy in India, proven or speculated, are coal bed methane (CBM), shale oil/gas, tight gas, and gas hydrates.

With the recent advancement in 3D seismic analysis and technologies developed to analyze core samples, these have enabled a better understanding of CBM fields and other unconventional reservoirs. Because of the low permeability of these formations, economical production from unconventional reserves can only be obtained using a hydraulic-fracturing stimulation technique. Advancements in fracturing techniques from the conventional "perf-and-plug" method to multistage fracturing have enabled stimulation treatments in long intervals in a rapid and cost-effective manner. The use of advanced and proven numerical simulators in designing hydraulic-fracturing treatments has exponentially increased the success of treatments. Development of cleaner and environmentally acceptable fluids for stimulation treatments has reduced formation damage and is critical for effective stimulation of these unconventional sources of energy.

Case studies from Indian fields where such emerging and effective technologies are being implemented are presented. Best practices developed to exploit CBM reservoirs and lessons learned from the mature fields in overcoming several operational challenges are discussed.

Introduction

India, an emerging economy, has undergone unprecedented levels of economic expansion, along with countries like China, Russia, Mexico, and Brazil. With a gross domestic product (GDP) growth rate of 8.8% in Q1 2010, by 2035 India is set to become the third largest economy following the USA and China, assuming the forecasted compounded annual growth rate (CAGR) of 6.2%. The GDP of India grew from USD 36 billion to 1.25 trillion over the last five decades. This expansion increased primary energy consumption in India by about 5% (CAGR) over the last two decades; whereas, for the rest of the world, this increase was only 2% (CAGR). India comprises 16% of the total world population and, with a CAGR of 1.54%, it is expected to cross 1.5 billion by 2035; therefore, energy will be one of the most critical aspects supporting the economy and human development.