bluuebunny/crossref_metadata_2025 huggingface dataset:
Some features of experimental setup design for isotopes separation by the laser assisted retardation of condensation method
Authors: Lyakhov K. A. , Lee H. J.
Published: March 2015

In this paper, we propose optimal design of experimental setup for isotope separation by laser assisted retardation of condensation method. Optimal parameters for this setup can be found from the optimization criterion based on the transport model for rarefied gas flow dynamics in external laser field specifically tuned for selective excitation of target isotope [J. W. Eerkens, Laser Part. Beams 23, 225–253 (2005)]. Constrains applied by condensation dynamics were also considered. Because product cut and enrichment factor corresponding to the optimal conditions are rather small, isotopes in this setup should be recovered iteratively. Proposed method to calculate optimal parameters of experimental setup can be applied for arbitrary chemical element isotopes separation, where target isotopomer chemical structure should provide its highest efficiency. Optimal design of experimental setup operation is demonstrated on the example of sulfur isotopes separation.
Chloroplast Dna Sequences Confirmed Genetic Divergence Within Calypogeia Muelleriana (Calypogeiaceae, Marchantiophyta)
Authors: Buczkowska Katarzyna , Gonera Patrycja , Bączkiewicz Alina , Rosadziński Stanisław , Rabska Mariola
Published: March 2015

Nine species of the genus Calypogeia Raddi are currently known from Europe: C. azurea, C. integristipula, C. neesiana,C. suecica, C. muelleriana, C. sphagnicola, C. fissa, C. arguta, and C. azorica. Recently, another species, morphologically resembling C. muelleriana but genetically distinct from it, was detected using isozyme markers. In the present study, relationships between the newly detected species (C. sp. nov.) and typical C. muelleriana were analyzed using the DNA sequencesdata of three regions from the chloroplast genome: introns of trnG and trnL genes and intergenic spacer trnH-psbA. Calypogeia sp. nov. differs from C. muelleriana s. str. (typical form) in all examined chloroplast regions. It differs as well from C. azurea, which was used as a reference species. The number of fixed nucleotide differences between C. muelleriana s. str. and C. sp. nov. is almost the same as between C. muelleriana s. str. and C. azurea. The results of the present study suggest a closer affinity of C. sp. nov. to C. azurea than to C. muelleriana s. str. in Europe, C. muelleriana s. str. was noted in Poland, Germany, Holland, United Kingdom and Azores. Samples determined as C. sp. nov., besides Poland, were so far detected also in North America
Active ex situ protection and reestablishment of Dianthus gratianopolitanus Vill. in the “Goździk siny w Grzybnie” reserve (Wielkopolska Province)
Authors: Jańczyk-Węglarska Jolanta , Węglarski Karol , Wiland-Szymańska Justyna
Published: March 2015

The following paper presents the results of observations of the size and condition of cheddar pink (Dianthus gratianopolitanus Vill.) population in the “Goździk siny w Grzybnie” reserve (Wielkopolska Province), as well as active cultivation of the species in ex situ controlled conditions and its reestablishment supporting the natural, endangered population in the reserve
Survival problems of archaeophytes in the Polish flora
Authors: Zając Maria , Zając Adam
Published: March 2015

These considerations have been based on the updated list of archaeophytes appearing in Poland. The extent of endangerment has been assessed for particular species according to the updated IUCN classification. Non-threatened and invasive species have also been taken into consideration. A number of quite fundamental changes have been made to the classification, as compared to the publication of Zając et al. of 2009.
Seed morphology and anatomy of Hypericum elegans Steph. ex Willd.
Authors: Szkudlarz Piotr
Published: March 2015

Hypericum elegans is a rare perennial distributed primarily in Central and Eastern Europe. Seed morphology and anatomy in H. elegans was studied on the basis of a seed sample from its only locality in Poland. Scanning electron microscopy revealed that the seed coat of mature seeds is composed basically of 3 cell layers: epidermal, subepidermal and sclerenchymatic. They are documented graphically here.
Rare and threatened vascular plants of the railways in Slovakia
Authors: Májeková Jana , Letz Dominik Roman , Slezák Michal , Zaliberová Marica , Hrivnák Richard
Published: March 2015

The paper presents data on the occurrence and secondary spreading of rare and threatened vascular plant species in railway habitats of Slovakia. We recorded 17 threatened vascular plant species and other 9 species that we considered to be rare in Slovakia. They grew at railway stations, mainly directly in the rail yard and also at the platforms or other similar facilities. Records of further 39 species were excerpted from literature sources. More native thermophilous species were represented among the recorded species as railway substrates provide suitable conditions for their growth. Also some archaeophytic segetal species were found quite frequent in the studied biotopes due to spreading of their seeds together with cereals transported by trains. Various habitats of railway transport facilities often provide suitable conditions for the secondary occurrence and further spreading not only of synanthropic or adventive, but also of rare and threatened plant species.
Presenting Risks Introduced by Android Application Permissions in a User-Friendly Way
Authors: Varga Juraj , Muska Peter
Published: March 2015

The emergence of Android as a leading Operating System in terms of market coverage induced the rapid emergence of many mobile applications. A lot of these applications are prone to misuse because of their design. This paper deals with a new method of informing user whether applications installed on his device are potentially harmful or not. The introductory part provides some insight into security mechanisms used in Android. The main part deals with research we based our work on, proposal of our own methodology based on permission model and its implementation in application for real-time offline analysis of installed applications on device running Android. The last part of this paper deals with the evaluation of achievements reached by our methodology implemented in standalone application
Low Dosage Hydrate Inhibitors (LDHI): Advances in Flow Assurance Technology for Offshore Gas Production Systems
Authors: Clark Leonard W. , Frostman Lynn M. , Anderson Joanne
Published: March 2015

The use of Low Dosage Hydrate Inhibitors (LDHIs) is one of the optimum methods to control gas hydrate formation issues and provide flow assurance in offshore gas production systems. The application of this technology has several advantages to operators including providing the opportunity for significant cost savings, extending the life of gas systems, as well as providing the option to use combination products. This paper will review the use of Kinetic Hydrate Inhibitors (KHIs) and Anti-Agglomerants (AA) through recent case histories. It will also illustrate how these products can be used in conjunction with Corrosion Inhibitors (CI) as is typically required in gas condensate production systems, either as individual products or as combination products. The novel illustration of the use of LDHIs in sour conditions will also be provided via case histories at low to moderate subcoolings. Hydrates can form different structures depending on the gas composition of the produced fluids. The nature of the LDHI used needs to take this into account and new product developments in this area will be covered.

Introduction

Natural Gas Hydrates. When considering the production of hydrocarbon fluids from offshore gas systems, flow assurance is a significant issue which needs to be taken into account. An important element of flow assurance is the investigation into the possibility of gas hydrate formation and its subsequent control. The inhibition of gas hydrate formation needs to be taken into account as part of the production of offshore gas, especially as hydrates typically form at lower temperatures and higher pressures. Production facilities, particularly offshore wells and offshore transmission lines, may be operating under conditions where hydrate formation is favourable.

Gas hydrate formation occurs when natural gas molecules are surrounded by water molecules to form 'cage'-like structures. Gas hydrates are similar in appearance to ice. Both materials have crystalline structures that exhibit similar characteristics – with the important difference that the natural gas hydrate has a natural gas guest molecule as an integral part of its structure. Examples of typical hydrate forming gases include Nitrogen, Carbon Dioxide (CO2), Hydrogen Sulfide (H2S) and light hydrocarbons (such as methane through to heptanes). Depending on the gas composition and the pressure, gas hydrates can form at temperatures of up to 86 °F where gas co-exists with water.
"On the Fly" Stratigraphic Basin Modelling From Seismic Interpretation Workstations
Authors: Albouy E. , Cacas M.-C. , Dobranszky G. , Laigle J.-M.
Published: March 2015

Seismic intepreters already use the principles of sequence stratigraphy to help interpret the geometry and sedimentary facies of the sedimentary bodies seen on seismic data. Linking seismic interpretation to a well database containing information on bathymetry and lithology, by using ultra-rapid algorithms simulating sediment transport, can help the interpreter to rapidly test and modify the stratigraphic scenario inherently present in the geometry and nature of the surfaces that have been picked. This "on the fly" stratigraphic modelling should make seismic stratigraphic interpretation easier and simpler to perform.

Various image-processing techniques can also be of help to the interpreter, both in determining depositional environment from seismic textural analysis and in a more rapid identification of the key toplap, onlap, downlap and truncation surfaces present in the seismic data. Again, linking the textural information with the well database can lead to a better use of both types of data.

The above techniques have been applied to seismic and well data of the National Petroleum Reserve Alaska, as a structured workflow involving the construction of a detailed geomodel and time-to-depth conversion cube. For each of the sequences picked on the seismic, the direction and composition of the principal sources of clastic supply are determined, and paleobathymetrical maps are generated, all of which are coherent with the well data (interpreted lithology and depositional environment) and the picked thickness of the sequence on seismic. The interpreter can then choose to view the seismic data of the next sequence in «true stratigraphic position» by shearing to fit the modelled bathymetrical profile of the underlying sequence. He or she may also choose to review and reinterpret the well data or repick the seismic surfaces in the light of the realistic paleogeographical scenario generated by the stratigraphic modelling.

Introduction

The aim of the present work was to test the application of algorithms designed to assist seismic interpretation for petroleum exploration by using the principles of forward stratigraphic basin modelling. We used a data set from the North Slope, Alaska which is freely available online from the United States Geological Survey (see below). The data to be fitted by the stratigraphic forward modelling included the thickness of stratigraphic intervals between markers picked on seismic data, the bathymetry and the lithological content of these interval identified in wells.
Coiled Tubing Deployed Bottom Intake ESP Developed for Al Rayyan Field, Offshore Qatar ... Nine Years of Experience
Authors: Hood K. , Sanden J.
Published: March 2015

This paper presents a review of a coiled tubing deployed, bottom intake (CTDBI) electrical submersible pump system (ESP) developed specifically for use in the Al Rayyan Field, offshore Qatar. The evolution of this technology to its present form will be reviewed along with the systematic approach used to enhance the original design and improve system run life. Also presented are workover, operational and economic considerations as compared to conventional ESP systems commonly run offshore. The review will also include the well completion design and how it functions and accommodates the ESP.

Introduction

Al Rayyan Field is located approximately 45 miles off the northern coast of Qatar in the Arabian Gulf. The field was discovered in 1976, however commercial development did not begin until 1996 through the application of horizontal drilling. Oil production is from carbonate reservoirs that require artificial lift. With its relatively low GOR and low bottom-hole temperature, Al Rayyan was an ideal candidate for ESP's.In order to be economically viable, the field development plan called for high production rates as well as a work over process that was more cost effective than conventionally deployed ESP systems requiring a drilling rig to pull and run. Al Rayyan Field currently has 13 producing horizontal wells, all equipped with CTDBI ESP's.

In 1996 the CTDBI ESP system was the first of its kind to be deployed. The key drivers behind developing this technology were to reduce workover cost and improve ESP availability with an ultimate goal being to achieve better overall project economics. In a typical conventional ESP system, the ESP string is run on jointed production tubing with a power cable strapped to the outside. The produced fluid reaches the surface via the conveyance tubing for which a drilling rig or pulling unit is required to run and pull. In the conventional ESP system the motor(s) are placed at the bottom of the ESP string, while in the CTDBI design the motor(s) are at the top. This difference makes the system unique and is why it is termed "bottom intake" (Figure 1).
Geomechanical Modelling of a Pore Collapsing Carbonate: Compaction and Subsidence of a Field in Oman
Authors: Dudley John Wesley , van der Linden Arjan , Mueller Guy Francois
Published: March 2015

A field in Oman provides a good example of compaction and subsidence due to a pore-collapsing carbonate formation. The field is comprised of a gas reservoir in the Natih formation and an oil reservoir in the deeper Shuaiba formation. Both reservoirs are formed by high porosity carbonates that can display a highly compressible "pore collapse" response with depletion. Both reservoirs are in production. Gas production from the Natih reservoir started in the early 70's, and continues at present from a dozen wells producing from the center of the field. Oil production from the underlying Shuaiba reservoir began in the late 60's, and the field has been under waterflood since the early 70's. All 450+ Shuaiba producers/injectors are drilled through the compacting Natih reservoir. Compaction damage to these oil wells is a major incentive for understanding the compaction and subsidence in this field. This paper presents the results of a detailed geomechanical study done to predict subsidence and compaction for the field. Core, log and field data are all incorporated to create a calibrated 3D geomechanical model for predicting ongoing field subsidence and estimating compaction potential. Key to this is an understanding of the field geology and diagenetic controls on rock strength and compaction in the Natih reservoir. Core compaction tests show the reservoirs are highly compressible pore collapsing carbonate formations. Although this is highly non-linear compaction behavior, in-situ field compaction measurements show an averaged, more linear response This fact advocates against using a 'pore collapse trend' to predict in-situ compaction. The measured field subsidence in the late 1990's & early 2000's is successfully predicted assuming an average linear material response, provided the variable diagenetic character of the field is honored for the pore-collapsing facies. Extrapolation of the model indicates compaction strains at the end of field life in the order of 5% in the crest of the field and a maximum subsidence of about 2 meters.
Large LNG Ships - The New Generation
Authors: Greer Matthew Noble , Richardson Andy J. , Sandstrom Robert E.
Published: March 2015

Extended Abstract

Introduction

Qatargas II (a joint venture of Qatar Petroleum and ExxonMobil) and ExxonMobil have collaborated to develop and implement a new generation of larger, more efficient LNG ships. They will be industry's first LNG ships with cargo capacities greater than 200,000 m3 (Figure 1). Through the application of several new technologies for LNG ships, along with optimization of marine systems and transportation efficiencies, this new generation of ships represents a significant step change in reducing the cost for delivery of liquefied natural gas to markets worldwide.

This initiative represents a key element of the Qatargas II project, whose goal is to develop 15 MTA of gas from the Qatar North Field. While the geographic location of the Qatar gas resources allows sales to both the East and the West, the remoteness from new markets in Europe and America calls for innovation and integration across the full value chain in order to achieve project success. For the transportation element of this value chain, the focus has been on how to achieve economies of scale and efficiency improvements via large ships.

Industry Settings and Drivers for Large LNG Ships

Industry relies on an LNG shipping fleet that has evolved considerably over the last fifty years. From the early 1970s through the mid-1980s, the fleet experienced steady growth (Figure 2). Following a period of relative stability in the mid-1980s, the fleet again saw significant growth that continues today. Interestingly, although the number of ships in the fleet has increased considerably, cargo capacity for new LNG ships has remained relatively stable for the last 30 years (Figure 3). A significant increase in cargo capacity from roughly 75,000m3 to 140,000m3 was realized in the mid-1970s and has remained the standard until only recently.
Saharan Aquifers Protection in Oil and Gas Upstream Activities in Algeria: A Sustainable-Development Challenge
Authors: Okba Dhina
Published: March 2015

In the south of Algeria – where almost all oil and gas upstream activities are carried out – Non-renewable groundwater preservation remains the most important challenge given the water scarcity Algeria is beginning to face.

The aim of this paper is to point out how manageable it is - for an oil and gas company - to reach its main objective as an industrial company without jeopardizing these valuable resources.

Contamination and overexploitation are the two major threats to be taken into account when dealing with Northern Sahara Aquifers System (NSAS) protection. Thus, Groundwater preservation includes both protection against contamination and water use optimization.

Besides, well construction quality and integrity are decisive conditions to efficiently prevent any contamination risk during both drilling and producing phases. Hence, regarding well construction, FMEA risk analysis method is fit for purpose to consider all potential failure modes and their effects that might endanger these aquifers.

On the other hand, standardization efforts have to take into account the contrasting aspect of the environment within the whole country. Sahara, in deed, represents a singular ecosystem with its own characteristics and vulnerabilities. Such diversity is seen as a real challenge when elaborating and fulfilling standards.

Introduction

Algeria's economy is still substantially relying on oil and gas sales that consist of 98% of the total exports earnings and contribute to 35% to the GDP. Thus, the main task Sonatrach has been entrusted with is to generate wealth to kick-start the development process.

Although Sonatrach is well established countrywide, upstream activities (exploration, drilling and production) are mainly performed in the south – Hassi Messaoud being the main oilfield – where strategic groundwater reserves spread out. These reserves are well-known as the "Northern Sahara Aquifers System" (NSAS).

To correctly figure out the vital importance of the NSAS, it sounds of great helpfulness to remind that Algeria belongs to a dry region of the world that is facing a severe water shortage. Thus, the challenge for Sonatrach is to optimize oil and gas production operations, keeping in mind that the NSAS valuable reserves might be protected and preserved.
Reservoir Connectivity in a Complex Fractured Reservoir: The Relationship Between Fracturing and Facies in the Upper Cretaceous Apulian Platform of the Maiella Mountain, Southern Italy
Authors: Di Cuia R. , Gout C. , Balzagette L. , Masse P. , Vieban F.
Published: March 2015

Understanding connectivity in complex, low-porosity, fractured carbonate reservoirs is fundamental for the correct assessment of their potential. In this kind of reservoirs, fracturing is essential. It is very difficult, using only subsurface data, to correctly define the 3D distribution of the fracture network because the characteristics as fracture density and fracture type are often doubtful.

The Upper Cretaceous Rudist Carbonates of the Apulian Inner Platform represent a superb reservoir for some of the most prolific southern Italy HC fields (figure 1). This reservoir is deeply buried underneath a thick pile of allochothonous thrust sheets but the outcrop equivalent in the Maiella Mountain allow to study its 3D architecture and characteristics.

Fracturing is not randomly distributed but the pervasive fracture distribution at bed scale (background fractures) is closely related to the distribution of different sedimentary facies.

This relationship is a key starting point to correctly model the reservoir behaviour in terms of three-dimensional connectivity (fracture connectivity network) and of identification of potential fracture-related good hydrocarbon storage intervals.

The multi-disciplinary outcrop acquisition method and integration used for this study are innovative: they are designed to get the most interactive contribution between sedimentary, stratigraphic, mechanical and structural analysis.

Generally, fine-grained sedimentary facies (the more abundant and continuous in the inner platform) are characterised by higher fracture densities (for all fracture orders). In such sedimentary facies, typical fracture sets are often sub-parallel and bed-confined. These facies, with higher fracture porosity could represent important HC storage intervals within the reservoir.

Laterally discontinuous coarse rudist associations and coarse-grained sedimentary facies are characterised by scarce fracturing but also by relatively good matrix porosity. These facies can also be considered as good HC storage intervals which could be isolated from the rest of the reservoir.
Managed Induced Fracturing Improves Waterflood Performance in South Oman
Authors: Saeby Jan , Bjorndal Hans-Petter , van den Hoek Paul
Published: March 2015

Novel modelling technologies that includes induced fractures in a dynamic reservoir simulator has been used to analyse subsurface aspects of an inverted 5-spot injection pilot. The techniques have allowed an accurate depiction of growing induced fractures. Simulation results indicate that induced fracture growth is limited at injection rates < 200 m3/d but that higher injection rates will result in fracture propagation and a risk of rapid water breakthrough. The results have been validated by field observations. A controlled and cautious increase in injection rate has resulted in a positive production response with rate increases of 50–100% in three of the four producers in the pilot.

Results from the pilot have increased the current reservoir understanding and reduced subsurface uncertainties. The knowledge gained is being included in an updated Field Development Plan that will be issued in 2005. The plan will incorporate an optimised injection strategy by a careful and controlled ramp up in injection rate. This project has also advanced induced fracture research with a field verification of the predictive capabilities of the modelling technology.

Introduction

The Marmul Haima West sandstone reservoir in South Oman, containing heavy and viscous crude (22 ºAPI, Î¼o = 90 cP) and on production since 1980, was initially developed on depletion/solution gas drive using vertical wells. To boost production and improve recovery, an aggressive waterflood development using horizontal wells was initiated in 1999. The development was, however, stopped prematurely in 2000 after excessive induced fracture growth resulted in water short-circuiting and poor well performances.

To improve subsurface understanding and redefine a development strategy, an inverted 5-spot produced water injection pilot project was initiated in 2002 with the procurement and construction of dedicated water cleaning and injection facilities and drilling of 5 new vertical pilot wells (i.e. wells I-1, P-1, P-2, P-3 and P-4). A map of the field and the placement of the 5-spot pilot have been shown in Figure 1.
Acid Gas Injection Facilities for Gas Disposal at the Shute Creek Treating Facility
Authors: Wall Robert A. , Kenefake Daryl A.
Published: March 2015

Acid Gas Injection (AGI) facilities have been constructed and are currently being commissioned at the ExxonMobil Shute Creek Treating Facility in Southwestern Wyoming, United States. The successful startup of the Shute Creek AGI facilities will demonstrate the feasibility of using AGI compression, liquefaction, and pumping technology on large scale projects to dispose of waste acid gases.

Overview

This paper discusses the purpose of AGI facilities at Shute Creek and provides an overview of the equipment and processes implemented in the Shute Creek facilities which include acid gas compression, water removal, liquefaction, and pumping. Commissioning of facilities on CO2 and safety considerations of the AGI facilities are also discussed.

This paper has been prepared for presentation at the International Petroleum Technology Conference (IPTC) in Doha, Qatar scheduled for November 21–23, 2005.

Background

Purpose of AGI. The AGI facilities at Shute Creek Treating Facility are intended to replace aging Claus sulfur recovery units. Installation of the AGI facilities will eliminate bottlenecks and avoid downtime associated with the sulfur recovery units. In addition, the AGI facilities allow Shute Creek Treating Facility to exit a historically weak Sulfur market and reduce SO2 emissions.

The AGI facilities at Shute Creek consist of centrifugal compressors, centrifugal pumps, coolers, separation equipment, pipelines and wells to dehydrate and inject acid gas generated in the gas sweetening process. An overall block flow diagram of the Shute Creek AGI facilities is shown in Figure 1. In conjunction with the installation of the AGI facilities, Cogeneration facilities were also installed to generate steam and power for plant consumption.

Unique Characteristics of the Shute Creek AGI Facilities.

There are currently about 80 AGI plants in operation throughout the world. Most of the operating facilities are located in Canada and the United States; however, about 10% of operating AGI facilities are located outside of North America. Most AGI facilities constructed to date consist of reciprocating compressors discharging directly into injection wells. AGI facilities in North America typically have design capacities of less than 5 MCFD. The Shute Creek AGI facilities are anticipated to be the largest in the United States with a design capacity of 65 MCFD of acid gas composed primarily of Hydrogen Sulfide, H2S and Carbon-Dioxide, CO2.
Eliminating Perforating-Related Formation Damage in Gravel-Pack Applications Utilizing New One-Trip-Sand Control Completion Technology
Authors: Garfield G.
Published: March 2015

Formation damage caused by perforating is among the highest risks in well completion. This paper examines a new technology for completing wells in unconsolidated formations that installs a liner hanger and sand control mechanism in a single trip to eliminate explosive perforation charges and associated formation damage risk. In addition to eliminating perforating, the technology reduces the cost of well construction by allowing the production liner, flow conduit, primary cementing, and sand control tools to be run in a single trip.

The perfless completion system uses telescoping tubes that extend from the liner into the formation by applying hydraulic pressure and mechanical force. Once the tubes are extended (or telescoped), the liner is cemented in place. The tubes, which contain sand control media, form conduits from the formation to the casing ID. No large, high-horsepower fluid pumping treatments are required. Neither are after-completion drilling mud and fluid-loss control measures, both of which can cause formation damage. The new completion method eliminates gravel packing and minimizes intervention in completion operations, saving substantial rig time. It also simplifies operation logistics, especially in remote or offshore environments.

This new technology was developed by a Joint Investment Project (JIP) that included three major operators, a large service provider and a small technology company. This paper describes initial field test results of the new system, cost comparisons with existing methods, and expected economic benefits over the lifetime of wells in typical applications of this new technology.

Introduction

Reducing or eliminating formation damage caused by perforating can result in a more productive well over its lifetime. The history of formation damage caused by perforating has been well documented. Fractured and compacted zones, perforation gun debris, and broken formation blockages are common types of damage that can occur inside the perforation tunnel. Studies have shown that conventional perforating of cased wells can cause an increase in skin values, especially over the extended lifetime of the well. Studies have also shown that increasing the depth of penetration will increase not only the skin value of the well, but also the amount of fines in a perforation tunnel.
Probabilistic Reserve Estimation Constrained by Limited Production Data: An Integrated Approach
Authors: Minhas Haq Nawaz , Matteo Eugenio , Eikeland Kjersti Margrete , Mengoli Marina , Beswetherick Simon
Published: March 2015

Large uncertainties in structure and facies had been recognized in a major gas field in Pakistan after early production. The conventional reserve estimation methods had failed in providing a reliable estimate of gas-in-place (GIIP). It was possible to get a good history match of one-year production data using a wide range of GIIP through a slight and acceptable adjustment of porosity and permeability. The resulting possible range of GIIP could easily vary by a factor of 1.5. Structural uncertainties did not warrant volumetric estimates either. Material balance technique was questionable due to non-uniform drainage of the reservoir. Clearly these deterministic techniques of reserve estimation were not applicable at this stage of production considering the complexities of the reservoir. A probabilistic technique was therefore developed that addressed both static and dynamic uncertainties in an integrated approach while honoring the available production history. Combined treatment of static and dynamic uncertainties also ensured a better coverage of the entire sample space, thus making the probabilistic approach more reliable.

Latin Hypercube Sampling (LHS) helped minimizing the number of simulation runs while providing a reasonable coverage of the sample space. Yet we ended up with almost 1500 simulation runs. The process of history matching, ranking and keeping track of all these simulation runs demanded an innovative workflow. A number of software tools were used to automate and optimize this process. Out of 1500 simulation runs, the 200 best runs having minimum objective function through history matching were selected. These runs were later used for production forecasting, for providing a range of reserves, and for sensitivity analysis to identify the most influential variables. Structure and NTG were identified as the two most critical variables for *GIIP while residual gas saturation was identified as an additional sensitive variable for reserves. Different geostatistical realizations had little impact on GIIP or reserves.
Detecting and Modeling Cement Failure in High-Pressure/High-Temperature (HP/HT) Wells, Using Finite Element Method (FEM)
Authors: Shahri Mehdi , Schubert Jerome Jacob , Amani Mahmood
Published: March 2015

A successful cement job results in complete zonal isolation while saving time and money. To achieve these goals, various factors such as well security, casing centralization, effective mud removal, and gas migration must be considered in the design. For the cement job to be successful, the permeability of the set cement must be low enough to prevent any fluid flow through the cement, possibly damaging the casing. Therefore, the design of the cement must be such that it prevents:Micro-annuli formationStress crackingCorrosive fluid invasionFluid migrationAnnular gas pressure

In High Pressure/High Temperature (HPHT), cases, a more flexible cement which expands more than conventional cement may prevent cement failure.

The stress in the cement is strongly dependent on temperature and pressure as well as the lithology and in-situ stress. Since the stress is so dependent on temperature, the temperature variation must be precisely predicted to achieve the proper design of the cement slurry and eliminate excessive time spent waiting on cement. In addition, a post-job analysis is necessary to ascertain zonal complete isolation and avoid unnecessary remedial work.

By increasing the flexibility of the set cement (lowering the Young's modulus) we could reduced the tensile stress in the cement sheath during thermal expansion. This could be a solution to the problem of cement stability in high temperature cases.

Here we report the use of the Finite Element Method, (FEM), to investigate the stress fields around and inside the cement in and to forecast the condition of cement failure. This study mostly focuses on the cement-casing boundary. This method is more powerful than conventional stability methods since complex boundary conditions are involved as initial conditions and are investigated simultaneously to more accurately predict cement failure.

Introduction

There are many of challenges dealing with cementing wells under High Pressure High Temperature (HPHT) conditions. Cement design and placement are very critical under these conditions. Since the casing stability is very dependent on cement integrity, and bonding with the casing and formation, operators must do everything feasible in order to insure a successful cement job.
A Modified Purcell/Burdine Model for Estimating Absolute Permeability from Mercury-Injection Capillary Pressure Data
Authors: Huet Caroline Cecile , Rushing Jay Alan , Newsham Kent Edward , Blasingame Thomas Alwin
Published: March 2015

This paper presents the development and validation of a new semi-analytical, statistically-derived model for estimating absolute permeability from mercury-injection capillary pressure data. The foundations of our new model are the classic Purcell and Burdine equations which relate absolute permeability to capillary-pressure/wetting-phase-saturation properties. We also incorporate characteristic capillary pres-sure behavior using the Brooks-Corey power-law model.

The final form of our proposed model allows us to compute absolute permeability as a function of effective porosity, irreducible wetting phase saturation, displacement or threshold pressure, and basic pore size characteristics. We tested and correlated our model using 89 sets of mercury-injection (Hg-air) capillary pressure data – including core samples from both carbonate and sandstone lithologies. In summary, we found that our model consistently yields accurate results for a wide range of rock properties.

Introduction

The fundamental relationships between pore size/geometry and basic rock properties (e.g., effective porosity, absolute permeability, etc.) are well-documented in the petroleum and petrophysics literature. Moreover, the literature is replete with models for estimating or predicting permeability from basic rock properties. Nelson4 has developed a comprehensive re-view of the literature, and he has identified five major categories of permeability models based on the physical rock attributes used in the model development:The five major model categories specified by Nelson are:Petrophysical models,Models based on grain size and mineralogy,Models based on surface area and water saturation,Well log models, andModels based on basic rock pore dimensions.

In this paper, we focus on models that incorporate basic rock pore characteristics and dimensions, and specifically, pore characteristics as determined from capillary pressure data. Nelson has further classified these particular models as direct types since they not only relate rock permeability directly to the pore dimensions and connectivity, but also incorporate fundamental theories of fluid flow through porous media. Most of these direct methods – especially the early models developed in the 1940s and 1950s – use mercury-injection capillary pressure data to quantify the rock pore and pore throat characteristics.
Natural Gas Scenario - Pakistan Case Study
Authors: Zubairi N.A. , Qureshi N.A. , Haseeb A.
Published: March 2015

World Natural Gas scenario has changed rapidly in the last decade and Natural Gas is set to play an increasing role in meeting the future energy needs as demand rises across the world. Natural Gas demand has increased by 75% over the past twenty years and its share in the total energy consumption is globally expected to increase from 23% in 2002 to 28% by the end of 2005. Pakistan has proven reserves of 796.32 Bcm (28.10 Tcf) and net annual gas consumption of 34.09 Bcm (1.203 Tcf). At present Pakistan's energy mix comprises 50% of Natural Gas share and there is continuous rise in gas consumption with a target to extend it to about 55%. Paper discusses chronology of Pakistan's Natural Gas starting from first find in 1952 and development of most extensive transmission and distribution network over the years. Conclusively, the paper would focus to demonstrate the upcoming challenges in Pakistan to meet the growing demands in addition to the opportunities that such challenges bring along.

Introduction

Natural Gas has already played a vital role in shaping the industry outlook and meeting energy demands in North America, Western and Eastern European countries, and industrialized Asia due to its availability and environmental acceptance. The availability of Natural Gas worldwide and specifically the abundance in Middle East, coupled with its environmental acceptability and various applications across all sectors, will continue to play an increasingly important role in meeting demand for energy in the World. Natural Gas is one of the cleanest, safest, and most useful of all energy sources. Natural gas is the most precious energy source which has extremely efficient BTU input to BTU use ratio. It is also a major feedstock for the production of ammonia for use in fertilizer production and a cleaner fuel choice for power plants.

World Natural Gas Scenario

The World gas scenario has changed rapidly in the last decade. Today Natural Gas is the fastest growing primary energy source. Presently world Natural Gas proven reserves are 6,337 Tcf. More than 75% of world gas reserves are held by ten countries, which represent 40% of the total natural gas exports through pipeline and/or LNG. Pakistan is ranked at number 30 and represents 0.4% of world gas reserves.
Generation of Probabilistic Reserves Distributions From Material Balance Models Using an Experimental Design Methodology
Authors: Vahedi Arman , Gorgy Faryar , Scarr Kynan David , Sawiris Ramzy , Singh Updesh , Montgomery Paul , Clinch Simon , Sawiak Angela
Published: March 2015

Overview of Malampaya Field:

The Malampaya-Camago Gas-Condensate field is a Tertiary Carbonate build-up that is situated offshore to the northwest of Palawan Island (Philippines) below 800–1200m of water. It was discovered by Occidental in 1989 (Camago-1) and is operated by Shell (45%) with Chevron (45%) and the Philippines National Oil Company (10%) as equity partners. The field has been supplying gas from five subsea production wells since late 2001 to three Gas to Power plants on Luzon Island. Available subsurface data include a 2001 high resolution 3D seismic survey, five production wells and six exploration/appraisal wells with wireline and borehole image data, including spot core in selected wells, pressure and well test data. A schematic of the Malampaya gas to power project is shown below.

Overview of Experimental Design (ED) Methodology

An extensive reservoir characterisation study was carried out by Chevron on a non-operated asset in 2004 to determine gas-in-place and reserves distributions. This paper outlines the Experimental Design (ED) methodology used in the study which using material balance models integrated the static and dynamic reservoir uncertainties with the excellent reservoir pressure history data that exists for the field.

The methodology incorporated a unique and "state-of-the-art" method for screening over 20,000 reservoir realisations to allow only those realisations that showed a close match to the pressure history to be included in the generation of GIIP and reserves distributions. This aspect of the ED methodology proved to be very powerful in generating reserves distributions in a "hands-off" approach without the requirement for traditional manual adjustment of reservoir parameters to get a "history match".
Integration of Microelectrical and Sonic Reflection Imaging Around the Borehole - Offshore UAE
Authors: Borland William H. , Holderson Jakob , Bu Al Rougha Hamad Ahmed , Sultan Akmal Awais , Chakravorty Sandeep , Al-Raisi Muatasim
Published: March 2015

Horizontal wells are commonly used worldwide to improve recovery of petroleum resources. Offshore Abu Dhabi, the carbonate reservoir contains sub-seismic features such as faulting and fractures that impact production and enhanced recovery. This paper is an attempt to identify and link fractures and faults observed near borehole with surface seismic in order to provide insight into their extent, distribution, characterization and implications on the reservoir production. The study resolved structural interpretation uncertainty in the 3D seismic, highlighted the variability in the injected water front advancement, and provided a methodology to link fine scale observation from micro-electrical image logs to intermediate sonic measurements and surface seismic.

Conventional sonic logging is similar to refraction seismic experiments carried out on the earth's surface except that, for the sonic, the source is higher frequency and the source receiver distance and receiver spacing is much closer. This allows the sonic to achieve a higher resolution velocity measurement over a shorter interval.

Sonic logging waveforms can also be processed for reflection information in a similar way to reflection surface seismic. Its higher frequency source thus allows for much higher resolution reflection information tens of feet away from the well.

The structural dip computations from pilot and horizontal image logs were linked with sonic reflections to mark probable fault locations and to construct a geological cross-section, which used to define the different reservoir layers that intersected along the well trajectory. Structural lineaments (faults and fracture zones) within a given reservoir layer were extended away from borehole by utilizing sonic waveforms. Due to small fault displacement (<4 m) the fault was not originally picked on the surface seismic, but overlaying the interpretation on the attributes indicates the possibility of a fault. The results were subsequently validated by injection profile. Mapping these lineaments improved seismic interpretation, which ultimately lead to better well placement and validated existing dynamic data.
Reservoir Surveillance and Smart Fields
Authors: Potters Hans , Kapteijn Pieter Karel
Published: March 2015

One of the chief challenges facing the EP industry is to increase the recovery of hydrocarbons from the existing asset base. With access to new resources getting more difficult and production declines facing several major mature provinces, the awareness that we need to manage our assets differently is growing. Recovery optimization is therefore a growing issue with significant future capital, technological and workforce competence development implications.

One of the approaches to address the challenge is the "Smart Field" (a.k.a. "digital oil field") concept, introducing advanced system engineering and optimization concepts to asset management. This includes new IT-enabled ways of collaborative working and tight integration of surface and subsurface technologies. In this paper we will focus on novel approaches and technology for detecting and monitoring subsurface changes, an area often referred to as reservoir surveillance or reservoir monitoring. On the basis of examples we will argue that a paradigm shift in reservoir management is called for to ensure optimal field development..

Introduction

Traditional approaches to recovery optimization are too multi-faceted to do justice to in a few introductory remarks. However, there is ample evidence that if technological advances were adopted faster, hydrocarbon recovery for many types of fields would improve faster as well, and the value to investment ratio (VIR) for several types of new technology far exceeds unity. In the past decade, the increased role of IT to process, integrate and visualize data has provided many examples. Workflow process integration, encapsulation of knowledge in a shared earth model, advanced 3D visualization, increasing detail in reservoir models, and remotely controlled operation centers are increasingly adopted by most operators.

Another trend, which seems to be progressing at a slower pace, is the increasing awareness that the above IT-enabled advances, in spite of their undisputed value, are insufficient. For instance, more detailed reservoir simulation will certainly contribute to a better representation of available data, and industry thrusts to build more precise models, using tens of millions of grid blocks, should therefore pay off. However, the question whether available ("traditional") data is sufficient to turn precision into accuracy --an important distinction-- is asked less frequently than it should.