bluuebunny/crossref_metadata_2025 huggingface dataset:
Powiązania migracyjne miast średnich w konurbacji katowickiej w latach 1999–2011
Authors: Runge Anna
Published: March 2021

W warunkach spadku popytu na pracę następuje różnicowanie się atrakcyjności poszczególnych miast, co w konsekwencji prowadzi do reorientacji kierunków migracji. Celem artykułu jest wskazanie roli miast średniej wielkości w złożonym układzie osadniczym, jakim jest konurbacja katowicka, w świetle powiązań migracyjnych. Powiązania migracyjne rozpatrzono w oparciu o dane dotyczące odpływu migracyjnego (wymeldowania na pobyt stały).  Ludność odpływająca z miast średnich konurbacji katowickiej w znacznej części (65,9% odpływu) kieruje się na obszary województwa śląskiego. Następuje przy tym wzmocnienie powiązań migracyjnych miast średnich w obrębie samej konurbacji katowickiej. Miasta średnie wykazywały silne powiązania migracyjne z miastami dużymi konurbacji. Zainicjowane zostały jednak zmiany w strukturze tych powiązań. Głównym kierunkiem odpływu migracyjnego z miast średnich wciąż pozostają Katowice, jednak wobec osłabienia rynku pracy oraz nasilania procesów suburbanizacji słabnie siła przyciągania innych miast dużych, zwłaszcza Sosnowca, Dąbrowy Górniczej i Zabrza. W największym stopniu wzrasta odpływ migrantów z miast średnich do miast małych i na obszary wiejskie, głównie powiatów będzińskiego i mikołowskiego. Miasta średnie nie stanowią dla siebie nawzajem atrakcyjnych kierunków migracji. Zaznacza się tu jedynie istotna i rosnąca rola Będzina. Zyskują na znaczeniu także Mikołów i Łaziska Górne. Natomiast Piekary Śląskie, Siemianowice Śląskie oraz Czeladź tracą swój dotąd znaczny udział w przejmowaniu migrantów z innych miast średnich.
Międzynarodowa ranga Mysłowic w 1913 r. Jako wyraz centralnych funkcji granicznych
Authors: Dragan Weronika
Published: March 2021

Celem artykułu jest ukazanie historycznego znaczenia Mysłowic na arenie międzynarodowej jako centralnego ośrodka ruchu granicznego. Poprzez analizę archiwalnego planu miasta i źródeł historycznych odtworzono bazę instytucjonalną Mysłowic w 1913 r., a następnie dokonano selekcji działalności gospodarczych bezpośrednio związanych z funkcją graniczną. Rozwój gospodarczo-społeczny miasta dokonywał się na tle ówczesnego podziału politycznego Europy, a zróżnicowanie ekonomiczne między zaborami zadecydowało o wykreowaniu Mysłowic jako swoistych „wrót” handlowo-emigracyjnych. Nadgraniczne położenie na styku trzech cesarstw oraz rozwój kolei żelaznej wpłynęły na ukształtowanie się specyficznej przestrzeni funkcjonalnej miasta, z dominacją działalności związanych z handlem hurtowym, transportem, spedycją, gastronomią oraz usługami noclegowy
Realizacja modelu zarządzania  i rozwoju przestrzennego miasta XXI w.
Authors: Opania Szymon
Published: March 2021

Analizując współczesne koncepcje miast przyszłości, można zauważyć wśród nich dwie ważne grupy projektów. Jedna z nich zakłada powstawanie w bliższej lub dalszej przyszłości samowystarczalnych energetycznie miast, które nie emitują dwutlenku węgla i przetwarzają odpady, natomiast druga to ta, która realizuje postulaty zrównoważonego rozwoju w budowie miast, stawiając sobie za cel istotne dla miasta priorytety. Ten podział na „wizjonerskie” miasta przyszłości i teraźniejsze działania naprawcze był od zawsze czytelny. Od zawsze też koncepcje „miast przyszłości” odpowiadały na potrzeby „miast teraźniejszości”. Wiodącym przesłaniem było zaspokajanie potrzeb ich mieszkańców, zapewnienie lepszych warunków życia i poczucia bezpieczeństwa. Wydaje się, że zgodnie z raportem Przyszłość miast – miasta przyszłości miasto przyszłości to połączenie właściwego wykorzystania nowoczesnych technologii oraz innowacyjnych systemów ułatwiających zarządzanie poszczególnymi aglomeracjami z potencjałem instytucji i firm oraz kreatywnością i entuzjazmem obywateli. Przedmiotem artykułu jest analiza w tym świetle działań władz miasta Grenoble, które zaczęło realizować ponad 30 zadań z zakresu zintegrowanego planowania, przyjmując za cel szczegółowy redukcję wytwarzanych gazów cieplarnianych. Realizowany w Grenoble projekt EcoCité, zlokalizowany jest na powierzchni 250 ha, w centralnej dzielnicy Presqu’île i jest jednym z najważniejszych działań inwestycyjnych sektora publiczno-prywatnego we Francji. Zakłada on realizację działań na kwotę 1,3 mld euro w przeciągu 15 lat.
The Black Sea, the Latest New Exploration Frontiers in Europe: Preliminary Results of an Escape Tectonics
Authors: Hasnan Zurriya Hayati , Ayub Amir , Ismail Mohammad Hishamuddin , Harris Mariah , Chin Soon Mun , Syed Khastudin Syarifah Nur , Mansor Nur Yusra , Tengku Hassan Tengku Mohd , Ahmad Sharif Noor Farahida , Legrand Xavier
Published: March 2021

OBJECTIVE / SCOPE

The Black Sea is a Mesozoic-Cenozoic closed sea system representing one of the last few exploration frontiers in the vicinity of the European market. The overall prospectivity of the basin and associated regional prospective trends have been delineated using the integrated Play-Based Exploration approach. The tectonic evolution, basin formation, sedimentary infilling history, petroleum systems, and sedimentary plays have been investigated to search for new hydrocarbon potential in the basin.

METHODS, PROCEDURES, PROCESS

The seismic interpretation and mapping were based on 26 sparse 2D seismic lines (ION SPAN), which were acquired and processed in 2011-2012 by ION GTX. The multi-client data from offshore Russia, Crimea, and Ukraine were excluded due to geopolitical sanction. The seismic interpretation which was completed in the depth domain (PSDM depth) was calibrated using three Deep Sea Drilling Project (DSDP) wells namely Sites 379, 380, and 381 (Fig. 1) which penetrated only the shallower section namely the Top Miocene and Top Pliocene. However, the seismic markers where lacking well penetration were primarily interpreted based on seismic stratigraphy. Interpretation of the acoustic basement as well as crustal types were supplemented with gravity and magnetic data from Getech Globe’s database. Three key seismic lines (Fig. 1) were then selected to illustrate the overall basin geomorphology, structural evolution, and to subsequently identify play potential within the basins. The structural analysis was integrated with the seismic sequence stratigraphic analysis to understand the sedimentation history, depositional trends, kinematic evolution, and tectonic history.
Development of Plasma Sprayed Coatings to Improve the Erosion Resistance of Wire Wrapped Screens
Authors: Ochmann Lukas , Amro Moh'd M. , Gronde Bernd , Fischer Gundula , Weber Silke , Martin Dirk
Published: March 2021

The installation of sand screens in wells can fail in one of two ways: by causing an unacceptable high pressure drop in the near wellbore area or by losing the ability to retain particles. Four mechanisms can lead to a failure: plugging, corrosion, erosion and mechanical deformation. To increase the lifetime under erosive conditions, a coating for wire wrapped screens was developed and tested.

Erosion occurs, when formation particles hit the screen surface with high velocities or by continuous production of fines through the screen openings. The screen openings must keep a specified size in order to control the formation sand or gravel pack. If the opening size increases due to erosion, more particles are produced and erosion increases. A newly developed coating is put on the outside (i.e. facing the formation) of standard wire wrapped screens to make the slots resistant against erosion. The coating consists of ceramic or hard metal and is applied by plasma spraying. An extensive development and verification program was conducted to guarantee defined slot widths, corrosion resistance and mechanical strength of coating and screen.

A test facility was built to investigate the erosion resistance of sand screens. It consists of a flow loop to circulate a slurry of water and particles through 2″ coupons. Samples of standard wire wrapped, metal mesh and coated screens were tested. The tests were conducted with flow velocities of up to 18.5 m/s and particles of up to 100 micrometer for up to 60 h. The screens where compared under consideration of optical criteria, mass loss and functionality. The coated screens showed no sign of wear on the outside and kept their initial slot size. The slots of uncoated wire wrapped screens more than doubled in some places, when eroded under the same conditions. To test the functionality of the samples, sand retention tests were conducted before and after erosion. Since there were no changes in slot width, the coated screens show the same retention capabilities before and after erosion, while metal mesh screens that were eroded under the same conditions lost their ability to retain sand.

The newly developed coating improves the resistance against erosion, is able to withstand corrosive well environments and has mechanical properties suitable to be safely installed in any well. Therefore the coating has the ability to improve the lifetime of screens under erosive conditions.
A Hybrid Topside Structural Approach to the Management of Aging Fleet
Authors: Isnadi Biramarta , Lee Luong Ann , Ng Sok Mooi , Suhaili Ave Suhendra , M Nasir Quailid Rezza , Sham Hanisah , Puloh Kathy Ping , Omar Syahnaz , Saminal Siti Nurshamshinazzatulbalqish , Lihin Zul Hilmi , Khan Riaz
Published: March 2021

The objective of this paper is to demonstrate the best practices of Topside Structural Integrity Management for an aging fleet of more than 200 platforms with about 60% of which has exceeded the design life. PETRONAS as the operator, has established a Topside Structural Integrity Management (SIM) strategy to demonstrate fitness of the offshore topside structures through a hybrid philosophy of time-based inspection with risk-based maintenance, which is in compliance to API RP2SIM (2014) inspection requirements. This paper shares the data management, methodology, challenges and value creation of this strategy.

The SIM process adopted in this work is in compliance with industry standards API RP2SIM, focusing on Data-Evaluation-Strategy-Program processes. The operator HSE Risk Matrix is adopted in risk ranking of the topside structures. The main elements considered in developing the risk ranking of the topside structures are the design and assessment compliance, inspection compliance and maintenance compliance.

Effective methodology to register asset and inspection data capture was developed to expedite the readiness of Topside SIM for a large aging fleet. The Topside SIM is being codified in the operator web-based tool, Structural Integrity Compliance System (SICS).

Identifying major hazards for topside structures were primarily achieved via data trending post implementation of Topside SIM. It was then concluded that metal loss as the major threat. Further study on effect of metal loss provides a strong basis to move from time-based maintenance towards risk-based maintenance. Risk ranking of the assets allow the operator to prioritize resources while managing the risk within ALARP level.

Current technologies such as drone and mobile inspection tools are deployed to expedite inspection findings and reporting processes. The data from the mobile inspection tool is directly fed into the web based SICS to allow reclassification of asset risk and anomalies management.
A Novel Approach for Underbalanced Well Completions in Depleted and Highly Fractured Carbonate Reservoirs
Authors: Khalid Ali , Ashraf Qasim , Luqman Khurram , Hadj-Moussa Ayoub , Hamim Nasir
Published: March 2021

A prime objective of oil and gas operators is to maximize reservoir productivity and increase the ultimate recovery from all depleting fields. Underbalanced drilling is one such enabling technology that has been adopted world wide to achieve a number of objectives in maximizing the reservoir potential. Chief among these objectives are to reduce formation invasion damage, identify sweet spots in the reservoir, and reduce well costs.

Underblanaced operations however introduces more complexity into the successful drilling and completion of a candidate well. An improperly executed underbalanced operation can result in having less productivity in contrast to a conventionally drilled and completed well.

Pakistan a country currently highly dependent on foreign hydrocarbon fuels, once had total independence in at least natural gas. The southern part of Pakistan is known for its rich hydrocarbon potential, but most fields were discovered decades ago and have depleted at a rapid pace. Numerous fields in the vicinity have depleted to an extent that the reservoir pressure has reduced to a mere 3.9 PPG in EMW.

In the most recently drilled well the pressure depletion caused massive circulation losses while drilling the reservoir formation and the operator had resorted to pumping of heavy LCM pills and blind drilling to complete the section. After completing the well conventionally the operator made multiple attempts to kick off the well but observed no production. Subsequently multiple acid stimulation jobs were performed to reduce the formation damage, but all efforts were in vain. It was evaluated that the heavy LCM and drilled cuttings had bridged off and choked the reservoir skin completely from which there was no return. Ultimately the well had to be plugged and abandoned.

In relatively higher pressured and non-fractured formations the option exists to drill a well in underbalanced mode and trip the running string by balancing the well with a light weight fluid. For the subject case however, this option was impossible due to the highly fractured nature of the formation.

A plan was devised to include a downhole casing isolation valve in the last casing string and drill the well with an extremely light weight multiphase fluid. A rotating control device would be used to strip the running string in and out of the well. The completion packer was also to be stripped into a live well and set in place without the need of ever killing or balancing the well. By executing the mentioned methodology, the operator was able to drill and complete a well all the while keeping the reservoir formation in a virgin state. The paper discusses the planning, design, execution, and lessons learnt in underbalanced drilling and completion operations in the subject field.
Successful Integrated Production Optimisation from Multi-Zone Infill Wells Utilising First Application of Electrical Inflow Control Valve ICV in D-Field, Offshore Malaysia
Authors: Kumar Suman , Chandrakant Ashvin Avalani , Salleh Fairus Azwardy , Jamil Ahsan , Ibrahim Zulkifli , Chang Claire , Chiew Kwang Chian
Published: March 2021

Mature Field-D has produced at recovery factor (RF) less than 20% due to its geological complexity. As per re-development plan, four wells were drilled from newly built platform in 2020. Each well was completed with combination of oil and gas zones with maximum five zones per well. The gas zone is utilized as an in-situ gas lift, considering gas lift gas shortage and anticipated future requirement for artificial lift upon pressure depletion and water breakthrough.

All-electrical inflow control valve (ICV) and permanent downhole gauges (PDG) has been installed across each respective oil & gas zone. The system serves to provide zonal production control to mitigate high producing gas-oil-ratio (GOR) or water breakthrough zones. Single string multi-zone ICV completion enables maximum production from layers with varying reservoir properties and pressure depletion. In addition, gas zones completed with ICV enables cost-effective application of in-situ or well-to-well gaslift, facilitates future non-associated gas production for gas monetization project as well as gascap blowdown opportunities.

Application of all-electric smart completion has enhanced proactive surveillance and provided greater production control flexibility resulting in higher production than target. From the downhole data obtained from PDG, wells and network model were updated with good certainty and used to further optimize production at well, platform and field level. Multiple ICV configuration were simulated to maximize oil, minimize gas and water production considering facilities limitation in terms of liquid handling and gas processing to reduce carbon footprint. The gas zones have been utilized for in-situ gas lift using ICV. The smart completion has also enabled efficient unloading facilitated by real-time data acquisition and production control through ICVs leading to additional cost savings.

It marks the first installation of an all-electric smart completions offshore Malaysia and Asia Pacific. This paper will explain the functionality of all-electric ICV system and outlines the methodology undertaken to optimize production at well, platform and field level utilizing industry recognized well and network models.
Full-Scale Fracture System Analysis of Shale Reservoir and its Petroleum Significance
Authors: Shi Xuewen , Tong Yanming , Liu Wenping , Zhao Chunduan , Liu Jia , Fang Jian
Published: March 2021

Ascertaining the characteristics of fracture system at different scales integratedly is very important for performing efficient exploration and development activities of specific shale gas reservoirs.

In this paper, an area around 250 square kilometers in Changning Block of Sichuan Basin is taken as an example, which belongs to Chinese Shale Gas Development Demonstration Plot. Seismic structural interpretation was performed detailedly based on original seismic amplitude cube and derived edge-detection cubes, and then the technologies of finite element horizon flattening, orthogonal decomposition principal component analysis, seismic discontinuity patch auto-extraction and paleo-stress field inversion were applied, together with the existing regional geological understanding and fracture information in wells, to figure out the staging and grouping of fracture system at seismic scale (i.e., at large and middle scales), at the same time to clarify the regional tectonic evolution and its genetic relationship with fractures at different scales such as the ones revealed by seismic data and cores or image logs.

The following conclusions were reached. (a) The tectonic movements affecting the development of fracture system in study interval mainly happened during Yanshanian-Himalayan periods, i.e., 3 compressional tectonic episodes which were nearly in S-N direction in Late Yanshanian period, in NNE-SSW direction in Early Himalayan period, and in NWW-SEE direction in Middle Himalayan period respectively. (b) The Late Yanshanian tectonic event primarily formed long-axis anticlines and synclines, thrust faults and fault-related fractures, all of which were nearly in E-W trending, and fold-related fractures in different directions. (c) The Early Himalayan tectonic event mainly formed genetically related conjugate fracture sets including strike-slip faults and shear fractures both in NNW and NE directions, and transverse extensional fractures. (d) The Middle Himalayan tectonic event chiefly formed thrust faults, and related fractures and folds in NNE~NE direction, and transverse extensional fractures. (e) Furtherly our work demonstrated that such kind of fracture system analysis was of great significance in building discrete fracture network, providing precautionary advice for drilling engineering, and optimizing completion program and field development plan, etc. Hence, integrated fracture system analysis at full scales to reach more meaningful and robust conclusions is essential work for unconventional resources evaluation and characterization.
The Simulation and Pilot Application of Low Salinity Water Flooding for Offshore Low Permeability Reservoir
Authors: Shi Hongfu , Liu Yingxian , He Yifan , Xu Wankun
Published: March 2021

The use of LSWF (Low Salinity Water Flooding) is becoming more prevalent in recent years which can both improve the recovery factor and reduce the cost compared to other EOR (enhanced oil recovery) technics. This is especially important for the offshore oilfield development at present. Moreover, good quality of injected water is more applicable to low permeability sand which is characterized as smaller pore-throat radius and is easier damaged. Therefore, LSWF technology is proposed to address the above production problem while reduce the investment of equipment upgrade.

In this paper, we presented the optimization and implementation of LSWF for offshore low permeability reservoir. Firstly, we provided a critical review of LSWF included the main mechanisms, laboratory test and field effect. Secondly, we designed and conducted several laboratory core flood tests. Thirdly, a lot of synthetic models were established to simulate the effects of LSWF and to optimize the field program. Finally, the production performance of the pilot wells was discussed.

After LSWF, the water injection well presents the phenomenon of "scissors" - the injection pressure drops significantly below the safety pressure while the injection volume increases. Moreover, the decline of pilot well groups decreased by 20% ~ 26% compared with non-water flooded. The estimated recovery factor increased by 12%, which is consistent with other field tests worldwide. In summary, LSWF is a feasible, neconomic and efficient method for offshore low permeability reservoir production.
Near-Critical Reservoir Fluid Mixture Identification and Phase Behaviour
Authors: Ling Ru Piin , Hussain Mansoor , Razak Amin Nizar , Ashqar Ayham , Jamaludin Junirda , A Karim M Azan
Published: March 2021

To appraise hydrocarbon and its properties of a low permeability formation within deep Baram delta reservoirs. Formation X is low permeability silty sandstone. It forms along other formations stacked sandy shale reservoirs. The stacked formations are interpreted as Hydrocabon bearing formations based on the openhole and pressure data. However, the reservoir in question, showed features different from the adjacent reservoirs. This manuscript appraises the reservoir and illustrates the workflow followed to identify its fluid type and the best method to produce the hydrocarbon.

Triple combo logs identified formation X as hydrocarbon bearing with low permeability and low porosity. Formation pressures gradients indicated the formation to be oil; however, the bottom hole sample, when pumped out, indicated alternating of oil and gas despite the low differential pressure.

During the PVT measurement the sample was first re-pressurised until a single phase was achieved and it was then subjected to Differential Liberation and Constant Composition Experiments (CCE). These experiments showed the Bubble Point pressure of the sample to be higher than the reservoir pressure, thereby indicating two mobile phases in the reservoir and the probability of a Gas-Oil Contact (GOC). The Experiments were also successfully simulated and matched using the Peng Robinson Equation of State. The Laboratory experiments directly contradicted the interpretation of Wireline Logs and pressure gradient both of which, indicated single phase light oil.

The collected bottom hole sample indicated that both oil and gas are mobile at reservoir level, this finding is supported by PVT laboratory experiments. The Differential Liberation, CCE experiments and EOS fitting demonstrated the fluid to be two Phases at Reservoir Condition where both phases are likely to be mobile. Therefore, it is suspected that the fluid will go from being Gas to Oil with increasing depth without going through GOC, i.e. with continuous compositional grading as is possible for fluids near their critical temperature. This phenomenon could not be captured using open hole conventional logs and therefore the is team is currently investigating the best practice to identify such reservoirs.
Study on Boundary of Control Models and Mechanisms of Acid Rock Reaction in Carbonate Reservoirs with Different Dolomite Mass Fraction
Authors: Yan Jun , Cui Mingyue , He Anle , Qi Ning , Cui Weixiang , Wen Xiaohong
Published: March 2021

The understanding of acid rock reaction kinetics is the basis for the proposal of carbonate rock acidizing and acid fracturing. So far, the study of acid rock reaction kinetics in carbonate reservoirs is mostly focused on limestone reservoirs. The difference in acid rock reaction characteristics between limestone and dolomite reservoirs is obvious. In order to clarify the boundaries of control models and mechanisms of acid rock reaction in dolomite reservoirs, to guide the optimization of acidizing and acid fracturing proposal for carbonate reservoirs with different dolomite contents.

The experimental study of acid rock reaction kinetics was completed with carbonate cores with different dolomite mass fraction, and the difference of acid corrosion mechanism between limestone and dolomite was analyzed by scanning electron microscope.

The dolomite acid rock reaction kinetics equation under the control of different factors was established, and it was clarified that the temperature 90°C and the rotation speed 500r/min are the boundary of the surface reaction and mass transfer control mode. The study found that under the same experimental conditions, the acid rock reaction rate of dolomite is much lower than that of limestone; as the dolomite mass fraction increases, the acid rock reaction rate decreases rapidly, when the dolomite content exceeds 75%, the reaction rate of acid rock is reduced to the lowest and tends to be stable. Limestone is dominated by surface dissolution, with good dissolution effect, fast dissolution rate; dolomite is dominated by point dissolution, with holes on the surface, poor dissolution effect and low dissolution rate. Compared with limestone, the particle size of dolomite crystal is much larger, and the specific surface area is small, which is also the reaction rate of acid rock in dolomite is slower than limestone, this is also a main reason why the reaction rate of dolomite acid rocks is slower than that of limestone. So the acidizing or acid fracturing methodology of the dolomite reservoir is different from that of the limestone reservoir. The acid rock reaction rate and hydrochloric acid concentration should be appropriately increased within the allowable range to improve the uneven etching of the fracture wall, thereby increasing increase the conductivity of acid fracture.
Utilizing Pseudo Well Connections to Simulate Multi-Stage Hydraulic Fracturing - Example Based On the Study of a Tight Gas Asset
Authors: Lokhandwala Aamir , Joshi Vaibhav , Dutt Ankit
Published: March 2021

Hydraulic fracturing is a widespread well stimulation treatment in the oil and gas industry. It is particularly prevalent in shale gas fields, where virtually all production can be attributed to the practice of fracturing. It is also used in the context of tight oil and gas reservoirs, for example in deep-water scenarios where the cost of drilling and completion is very high; well productivity, which is dictated by hydraulic fractures, is vital.

The correct modeling in reservoir simulation can be critical in such settings because hydraulic fracturing can dramatically change the flow dynamics of a reservoir. What presents a challenge in flow simulation due to hydraulic fractures is that they introduce effects that operate on a different length and time scale than the usual dynamics of a reservoir. Capturing these effects and utilizing them to advantage can be critical for any operator in context of a field development plan for any unconventional or tight field.

This paper focuses on a study that was undertaken to compare different methods of simulating hydraulic fractures to formulate a field development plan for a tight gas field. To maintaing the confidentiality of data and to showcase only the technical aspect of the workflow, we will refer to the asset as Field A in subsequent sections of this paper. Field A is a low permeability (0.01md-0.1md), tight (8% to 12% porosity) gas-condensate (API ~51deg and CGR~65 stb/mmscf) reservoir at ~3000m depth. Being structurally complex, it has a large number of erosional features and pinch-outs.

The study involved comparing analytical fracture modeling, explicit modeling using local grid refinements, tartan gridding, pseudo-well connection approach and full-field unconventional fracture modeling. The result of the study was to use, for the first time for Field A, a system of generating pseudo well connections to simulate hydraulic fractures. The approach was found to be efficient both terms of replicating field data for a 10 year period while drastically reducing simulation runtime for the subsequent 10 year-period too. It helped the subsurface team to test multiple scenarios in a limited time-frame leading to improved project management.
A Novel Approach to Successfully Cement the Long Horizontal Liners Across Khuff-C Reservoir in High-Pressure Gas Producer Land Wells: A Case History from Saudi Arabia
Authors: Ali Wajid , Mata Freddy Jose , Al-Turki Faisal Abdullah
Published: March 2021

Maintaining zonal isolation is vital to well economics and productive life. Well integrity is becoming more challenging with the drilling of deeper, highly deviated, and horizontal wells worldwide. Oil companies are focused on to enhance the well productivity during drilling long horizontal wells in a harsh environment by achieving maximum accessible reservoir contact. These wellbore geometries incorporate additional challenges to design and deliver a dependable barrier. In this paper, a case study about cementing the longest liner across Khuff-C reservoir has been presented discussing the main challenges, engineering considerations, field implementation, results, and conclusions.

The well was drilled horizontally across Khuff-C carbonates using oil-based drilling fluid. The 5-7/8-in open hole section was planned to be cemented in single stage, utilizing 8370 ft of a 4-1/2-in liner. Careful attention was paid to estimate the bottom hole circulating temperature, using the temperature modeling simulator. A 118-lbm/ft3 slurry was designed to keep the equivalent circulation density intact. Gas migration control additives were included in the slurry design to lower the slurry's transition time, in order to reduce the chances of gas migration through the cement slurry. The slurry was batch-mixed to ensure the homogeneity of the final slurry mixture. A reactive spacer was designed to improve the cement bonding from long term zonal isolation perspective. Additionally, the spacer was loaded with optimum amounts of surfactant package to serve as an aid to remove the mud and to water-wet the formation and pipe for better cement bonding. Centralizers placement plan was optimized to allow around 63% average standoff around the pipe, staying within the torque and drag (T&D) limits. The cement treatment was performed as designed and met all zonal isolation objectives.

The process of cementing horizontal liners comes with unique procedures. There are several challenges associated with carrying out wellbore zonal isolation for primary cementing of horizontal liners, therefore, a unique level of attention is required during the design and execution stages. The slurry design requires careful formulation to achieve the desired specifications while ensuring its easy deployment and placement in the liner annulus. By planning in advance and following proven techniques, many of the problems associated with the running and cementing of deep and long horizontal liners can be alleviated.

This paper highlights the necessary laboratory testing, field execution procedures, and treatment evaluation methods so that this technique can be a key resource for such operations in the future. The paper describes the process used to design the liner cement job and how its application was significant to the success of the job.
Reducing Uncertainties to Shape the Future of Exploration
Authors: van Mastrigt Pieter , Quinn Michael J.
Published: March 2021

For any given Exploration oil and gas portfolio and associated opportunities, successful business decisions can only be made on the basis of technically robust estimates of the subsurface risk versus the resource potential and estimate of the associated upside(s). Ideally, these estimates should incorporate the entire spectrum of opportunities for the complete portfolio and they should be made in a consistent and comparable way. However, as Explorers, we are often faced with data that is incomplete, limited, of variable quality, and/or inconsistent. As a result, subsurface evaluation may be seen more as educated guessing rather than a robust science of evaluation grounded in facts and defensible logic. In their January 2020 paper "Randomness, serendipity, and luck in petroleum exploration" authors Milkov and Navidi (Ref 1.) go quite a bit further and demonstrate that luck is a significant factor in the exploration success equation. They also showed a general lack in long-term consistency in exploration results of individual companies. Indeed, after we looked at PETRONAS’ own historical POSg versus actual technical success rates and observed only a fair to poor relation between actual technical success rate and the pre-drill POSg estimate. A similar—albeit less worrisome—observation was made for volume ranges and fluid phase predictions. Clearly, there is, and always has been, a phenomenal challenge for the Petroleum Geoscientists to provide the sought after estimates as accurately as possible, and we were no exception.

In a bid to improve on this PETRONAS set out on a more disciplined approach to characterizing subsurface uncertainties on its conventional exploration efforts. Over time, more accurate characterizations of such exploration risk and resource potential have followed from a series of procedural guidelines, enhanced capability training program and careful governance of exploration workflows. With improved capabilities and workflow consistency, our evaluation teams have delivered substantially better subsurface evaluations. This in turn has led to more confident decision-making on e.g., individual drilling decisions and new play entries. While our newly implemented workflows are not groundbreaking in isolation, in combination they have delivered notable success and an improved ability to shape the future growth for PETRONAS. In this article, we will highlight the main contributing changes and demonstrate that the overall improvements are indeed impactful. We are not directly challenging the article of Milkov et. al., but are convinced that professionalism and scientific discipline is the deciding factor in the Exploration success equation.
Controlling Costs and NPT: An Economical Approach to Wellbore Strengthening Offshore Vietnam
Authors: Nanda Kumar Kishen , Moroni Luigi , Kongto Abhijart , Tran Thanh Bao , Nguyen Hoang Nghia , Tran Tuan Lam , Do Ngoc Chau
Published: March 2021

There are many challenges while drilling highly inclined and depleted formations offshore Vietnam that result in various wellbore stability issues such as severe losses, stuck pipe, cavings, tight-hole and pack-offs. These issues may be independent of mud type and can occur when drilling with both oil/synthetic-based and water-based muds. These depleted sections typically consist of sandstones interbedded with claystone & siltstones. Traditionally, the wellbore strengthening fluids solution applied to drill through these sections with synthetic and water-based mud in Vietnam faced limited success.

Wellbore strengthening (WBS) is a proven and effective solution especially for narrow-drilling margin and depleted formations. The basic concept of WBS relies on the creation and simultaneous plugging of small fractures with appropriate WBS material. The resulting elevated stress around the wellbore strengthens the borehole by creating an increased hoop stress that leads to an increase in near wellbore stresses. Proprietary modelling software can be used to calculate the pressure induced fracture apertures for wellbore strengthening applications and determine the optimum particle size range to bridge these fractures, allowing fluids to be designed to minimise wellbore instability.

This design process was used to optimize material additives to effectively bridge fractures, for wellbore strengthening, and pore throat openings in porous/permeable formations for the prevention of seepage losses and differential sticking. A review of the application procedure identified the optimum method to apply the wellbore strengthening material which would minimise product consumption and reduce well costs. After extensive modelling simulations and testing, this fluid design was applied to drill two challenging wells in Vietnam.

This paper presents the process of modelling, based on formation geo-mechanics information, customization and laboratory testing of the fluids design coupled with a successful and economical method of application in the field. Application of this process enabled the operator to drill through the depleted challenging sections with a maximum overbalance pressure of 3,200 psi, conduct logging and coring runs and complete the well at a lower cost and with zero fluids related non-productive time compared to previous wells.
A Success of Modified Water Based Mud as Drilling Fluid Optimization to Drill Shale Formation at South-S Wells
Authors: Hadinata Dwie , Mulia Yuliawan , Rudyanto Theodore , Laharan Adi , Haurissa Poultje , Soemantri Hedriawan , Subroto Borman , Suradilaga Rangga , Sugianto Rudi
Published: March 2021

This paper is to explain the optimization of using Modified Shale Inhibitor Water Based Mud (WBM) to drill up to 5,500 ft interval of K-formation reactive shale on South-S Gas Wells.

By combining a comprehensive method consists of drilling fluid laboratory test and lessons learned in S area, the optimization was done by determining the amount or concentration of Polyamine & KCl combination, pure Polyamine, Polyamine & NaCl combination, and Pure KCl-Polymer in WBM system as a shale inhibitor. The comparison of shale inhibitor compositions were made by comparing the achieved optimization of drilling fluid program such as drilling time, cost economic, and environment aspect.

The basic idea of the WBM optimization was to improve drilling time during drill 5,000 ft footage in 12-1/4" hole section in reactive shale formation as per drilling program. Laboratory test consists of Linear swelling meter with various parameter concentration of Polyamine & KCl combination, pure Polyamine, Polyamine & NACl combination, and Pure KCl-Polymer in WBM system as a shale inhibitor and cation exchange capacity test (CEC or MBT) was done using composite of offset well shale cutting. Experience showed that on 12-1/4" hole section, while facing reactive shale (CEC 18 - 24 meq/100 gr) from K-formation on South-S, modified WBM was proven to eliminate reactive shale issues and lead to budget saving without environmental issues.
Improving the Stratigraphic Concept of Channel Complex Reservoir of a Brown Field: A Case Study in Field A
Authors: Dzulkifli Izyan Nadirah , M. Yusoff Amy Mawarni , Basri Abdul Hakim , Jamaludin Izzuddin , M. Som M. Rapi , M. Akram M. Faizal , M. Diah M. Amri
Published: March 2021

Major reservoirs in Field A namely A-2, A-3U, A-3M, and A-3L, are deposited within a multi stacked channel complex system within Group I in Malay Basin. These reservoirs were previously understood based on existing data to have no or very minimal vertical communication between them and are treated as separate systems.

In 2018, three wells were proposed to drain the attic oil in the north region of A-3U reservoir. When drilling these infill wells, it was discovered that the pressure has exceeded initial reservoir pressure although the reservoir has been idle for almost a year prior to the drilling. The results of the multi-rate test of two of the three infill wells that are less than 1 km apart are significantly different from one another. Post drilling, more tests were executed to investigate the connection between the sand. Studies were also done by incorporating the static and dynamic reservoir modeling data.

Based on the result of the tests and studies, it was concluded that all of the major sands are connected at some areas. This new finding on the connectivity might be able to explain the additional volume needed to history match some of the reservoirs.

Establishing stratigraphy concepts of a reservoir particularly in a channel complex system is an ongoing process, in this case, a brown field of almost 20 years of production. All data including new well data and dynamic data plays a vital role for a better understanding of the reservoir. It is essential to incorporate the updated geological understanding into the static model to have a representative simulation for better history matching and prediction. Moving forward, instead of building a separate grid model for each reservoir, a larger framework consist of intercalated reservoir grids will be built with this new geological understanding for dynamic simulation.
Handling High-Intensity Brine Influxes Using Flow-While-Drilling FWD Techniques in a Salt Formation in Chinarevskoye Field
Authors: Aidoo Ato , Zenzin Valeriy , Kropochev Yuriy , Akulov Konstantin , Vitvitckii Evgenii , Arystan Abylaikhan , Juchiac Emil , Palten Peter-Joern , Amanbayev Yerlan , Higginson Tim , Amangeldiyeva Diana , Aliyeva Aida
Published: March 2021

This case study describes the approach taken when drilling an 11 5/8-in. hole section through a salt formation on the Chinarevskoye field in the West Kazakhstan Oblast region where high-intensity brine influxes and subsequent flow had been encountered. The intensity of the brine flow, when encountered, had ranged from 5,000 to 6,000 L/min at an equivalent kick density of 2.2 SG, and it is believed to be among the most intense brine flow experienced in the world during drilling operations.

Standard well control measures proved to be inefficient because of the narrow margin between pore pressure and fracture pressure gradients. Several techniques were applied to combat such influxes in a safe manner with minimum associated nonproductive time (NPT). The high-pressured formation in this hole section is associated not only with brine influxes, but also with losses and gas increase scenarios. As a result, the company adopted unconventional drilling techniques with a combination of planned flow-while-drilling (FWD) and mud-cap drilling techniques to reach total depth (TD).

These two techniques created a viable and cost-effective solution to mitigate such challenges, helped the company to drill to the planned section TD, and consequently complete the well within the defined authorization for expenditure (AFE) without associated NPT. The paper will cover and emphasize techniques, along with details on running casing and cementing the hole section, which required an unconventional approach for success. The paper will also briefly outline the equipment used, such as rotating control devices (RCDs), a choke manifold, and a separator when drilling this section and their limitations. Despite the complications, the well was successfully drilled, and this experience provided an opportunity for learning.

The marked improvements in well control, loss management, and cementation displayed that combining knowledge and experience can reduce the negative impact on well costs when drilling similar cases.
Single-Pile Offshore Structures as a Cost-Effective Alternative to Small Fixed Platforms in Shallow Water
Authors: Chatterjee Prabir Kumar
Published: March 2021

The present paper proposes an alternative to small offshore platforms with tripods and four-legged jackets by a single-pile structure for shallow water depths. The pile will be driven into seabed without a jacket and stability of the structure against environmental loads will be ensured by a few tie members connected to seabed with the help of specially-designed small concrete foundations. Tie members will be bolted to both the pile and the foundation. Four different cases of single-pile structures in three different water depths (20.0m, 31.5m and 15.0m) are presented. Omnidirectional waves of 10.0m height along with wind and current are considered in the study. Analytical method is suggested to simulate interaction of concrete foundations with soil that can be easily implemented in structural analysis. Structural design is performed as per API RP 2A working stress design method. The results indicate that the proposed single-pile structures have considerable reserve strength against failure due to extreme environmental loads and impact from medium sized boats.
Operations Readiness and Assurance OR&A on Pipeline Transient Analysis at A Floating Storage & Offloading FSO to Cater for Field-A Gas Production
Authors: Mahmud Nurul Syuhada , Kuanji Jennyfer
Published: March 2021

COMPANY-A is the operator of Field-A gas field that started operation in Country-A in 1996. Reliable and smooth condensate handling is key to ensure the continuous gas production and hence, maintaining the gas supply assurance. To cater for the reduced condensate throughput and export, COMPANY-A hired Company-B to refurbish a Floating Storage and Offloading vessel (FSO) named FSO-B; a new player and has minimum experience in oil and gas industry. Operation readiness review is crucial to ensure the safe operations in Field-A. In this paper, a review on the pipeline transient analysis and process safety focusing on condensate export line from SPM, flexible hose and piping modification on FSO-B is described as a showcase.

The review that referred to API standard and internal PETRONAS Technical Standards (PTS) has contributed in determining the revised operating envelop of the SPM and FSO-B compared to the initial project proposal. The technical operation and design review resulted in the avoidance of potential loss of process containment (LOPC), production deferment and PETRONAS reputation as prominent gas supplier within the region. It is important to ensure that the operating envelop is suitable with the production profile.

With the operational readiness exercises, FSO-B was designed correctly and ensured of safe operation. FSO-B was commissioned on time and started operation without much delay and hence, securing the gas supply of 60 MMSCFD from Field-A to Customer-C, and exporting up to 1500 BPD condensate smoothly without interruption. This exercise has contributed to safeguard the tangible value of maintaining the gas production as well as keeping the intangible value of PETRONAS reputation.

The operational readiness especially on the pipeline transient analysis review is significant novel to be replicated in other similar operations in PETRONAS and in similar operations in other operators.