bluuebunny/crossref_metadata_2025_split huggingface dataset:
Well Design and Successful Field Installation of Openhole Sand Control Completions with Acid Stimulation in a Highly Deviated Well in Vietnam
Authors: Vu Hung , Tran Son , Nguyen Trang , Kannan Bharathwaj , Tran Khoa , Nguyen Thong 
Published: February 2021

ABSTRACT
Application of openhole sand control technology is becoming mandatory in the field, particularly with the given uncertainty in geomechanics, challenges to wellbore integrity while drilling, and sand production during the life of the well. The completion equipment readiness and success of the installation can be challenging in the event of extending the horizontal section to accommodate geological heterogeneity and maximizing well productivity. This paper discusses operational excellence recorded in Well A, in the Thang Long Field, offshore Vietnam, from well design perspectives ensuring maximum reservoir contact to outcome of well completion.
The well was targeted in the Oligocene reservoir, a thin oil rim with large gas cap overlay, and required drilling and completion for 1126 m horizontal length of 8 1/2-in. open hole. The completion design included multiple swellable packers for isolation of unwanted zones, 6 5/8-in. basepipe sand screens for the production zones, and a fluid loss control device to help prevent undesirable losses. Several torque and drag simulations were performed to help predict potential threats that could be encountered during completion string deployment or during space out of the inner wash pipe string.
One apparent challenge of this completion design was to deploy the lower completion string to total depth (TD) per stringent reservoir requirements, resulting in an approximate 1126 m length of the string in the horizontal section. Another task was to facilitate manipulating 1130 m of wash pipe inside the completion string to locate the seal assemblies accurately at the corresponding seal bore extension positions for effective acidizing treatment. Although these were long sections of completion string and wash pipe, the quality of acidizing stimulation to effectively remove mud cake should not be compromised to ensure positive production rates.
During operations, the completion string was run to target depth without any issue, and the wash pipe was spaced out and manipulated correctly. These operations subsequently led to a successful acidizing treatment and the proper closure of the flapper type fluid loss device. The completion design and operation were concluded successfully, significantly contributing to field production performance to date.
The novelty of the completion design and installation is the ability to deploy an 1126-m lower completion in long, highly deviated and horizontal openhole section coupled with acid stimulation in reasonable time and as per plan.
Impact of Data Quality on Well Operations: Case Study of Work-over Operations
Authors: Enyekwe Alfred , Urubusi Osahon , Yekini Raufu , Azoom Iorkam , Isehunwa Oloruntoba 
Published: February 2021

ABSTRACT
Significant emphasis on data quality is placed on real-time drilling data for the optimization of drilling operations and on logging data for quality lithological and petrophysical description of a field. This is evidenced by huge sums spent on real time MWD/LWD tools, broadband services, wireline logging tools, etc.
However, a lot more needs to be done to harness quality data for future workover and or abandonment operations where data being relied on is data that must have been entered decades ago and costs and time spent are critically linked to already known and certified information.
In some cases, data relied on has been migrated across different data management platforms, during which relevant data might have been lost, mis-interpreted or mis-placed. Another common cause of wrong data is improperly documented well intervention operations which have been done in such a short time, that there is no pressure to document the operation properly. This leads to confusion over simple issues such as what depth a plug was set, or what junk was left in hole.
The relative lack of emphasis on this type of data quality has led to high costs of workover and abandonment operations. In some cases, well control incidents and process safety incidents have arisen. This paper looks at over 20 workover operations carried out in a span of 10 years. An analysis is done on the wells’ original timeline of operation. The data management system is generally analyzed and a categorization of issues experienced during the workover operations is outlined. Bottlenecks in data management are defined and solutions currently being implemented to manage these problems are listed as recommended good practices.
Rock Compressive Strength: A Correlation from Formation Evaluation Data for the Niger Delta
Authors: Salawu Babatunde , Sanaee Reza , Onabanjo Olumayowa 
Published: February 2021

ABSTRACT
The purpose of this paper is to study the strength of rocks by determining their Unconfined Compressive Strength (UCS), correlate the determined strength to physical properties of rocks that can be measured from formation evaluation data and derive an equation that can be used to derive rock strength from formation evaluation measurements. The scope of this work is limited to the Niger delta basin from which core samples were taken.
The method used for this research was to collect data of existing core samples at different depths and in various fields in the Niger Delta, then determine the strength of each sample by unconfined compressive tests. The derived strength was then analyzed with corresponding formation evaluation data utilizing regression analysis. Then, comparisons were drawn between the correlations derived and other existing correlations in the industry to check whether any of the existing correlations fits the Niger Delta region.
The result is a model that takes formation evaluation data (Slowness, Young's Modulus and Poisson's ratio) as input in order to provide rock compressive strength for the Niger-Delta region. It was also observed that correlations built for other regions of the world do not yield accurate results when used for the Niger Delta region due to factors such as formation characteristics type of regression method, various sample collection conditions and so on.
Innovations of Gas Lift in Prolific, Long-perforations, and Multilayered Wells, Case Study in Sudan
Authors: Tang Xueqing , Dou Lirong , Wang Ruifeng , Wang Jie , Wang Shengbao , Wang Jianshun , Shi Junhui 
Published: February 2021

ABSTRACT
Jake field, discovered in July, 2006, contains 10 oil-producing and 12 condensate gas-producing zones. The wells have high flow capacities, producing from long-perforation interval of 3,911 ft (from 4,531 to 8,442 ft). Production mechanisms include gas injection in downdip wells and traditional gas lift in updip, zonal production wells since the start-up of field in July, 2010. Following pressure depletion of oil and condensate-gas zones and water breakthrough, traditional gas-lift wells became inefficient and dead. Based on nodal analysis of entire pay zones, successful innovations in gas lift have been made since March, 2013. This paper highlights them in the following aspects: Extend end of tubing to the bottom of perforations for commingled production of oil and condensate gas zones, in order to utilize condensate gas producing from the lower zones for in-situ gas lift.Produce well stream from the casing annulus while injecting natural gas into the tubing.High-pressure nitrogen generated in-situ was used to kick off the dead wells, instead of installation of gas lift valves for unloading. After unloading process, the gas from compressors was injected down the tubing and back up the casing annulus.For previous high water-cut producers, prior to continuous gas lift, approximately 3.6 MMcf of nitrogen can be injected and soaked a couple of days for anti-water-coning.Two additional 10-in. flow lines were constructed to minimize the back pressure of surface facilities on wellhead.
As a consequence, innovative gas-lift brought dead wells back on production, yielding average sustained liquid rate of 7,500 bbl/d per well. Also, the production decline curves flattened out than before.
Mathematical Model of Energy Storage in Gas Hydrate and its Flow in Pipeline Systems
Authors: Akinsete Oluwatoyin , Isehunwa Sunday 
Published: February 2021

ABSTRACT
Natural gas, one of the major sources of energy for the 21st century, provides more than one-fifth of the worldwide energy needs. Storing this energy in gas hydrate form presents an alternative to its storage and smart solution to its flow with the rest of the fluid without creating a difficulty in gas pipeline systems due to pressure build-up.
This study was design to achieve this situation in a controlled manner using a simple mathematical model, by applying mass and momentum conservation principles in canonical form to non-isothermal multiphase flow, for predicting the onset conditions of hydrate formation and storage capacity growth of the gas hydrate in pipeline systems.
Results from this developed model shows that the increase in hydrate growth, the more the hydrate storage capacity of gas within and along the gas pipeline. The developed model is therefore recommended for management of hydrate formation for natural gas storage and transportation in gas pipeline systems.
Mozambique Natural Gas Condensate Analysis: Offsetting Production Royalties with Production By-Products
Authors: Mazula Nelia 
Published: February 2021

ABSTRACT
Oil is often produced in developing parts of the world with limited infrastructure where stakeholders are often challenged with comprehensive build-outs that include roads and even airports. In these environments production by-products such as natural gas condensates can be unfeasible to commercialize due to low quantities relative to the cost of processing and transportation. This study looks at work done in Mozambique on natural gas condensate characterization and commercialization studies to provide recommendations to new projects for facilities design and contract negotiation to consider ways of using production by-products, such as condensate, in the royalty negotiation process, especially in remote and developing regions. These results can also be used in future petroleum projects in Mozambique.
Advancing Models of Facies Variability and Lacustrine Source Rock Accumulation in Rifts: Implications for Exploration
Authors: Scholz Christopher A. 
Published: February 2021

ABSTRACT
Important syn-rift hydrocarbon discoveries in the Tertiary East African Rift and in the South Atlantic subsalt basins have in recent years promoted renewed interest in the variability of source and reservoir rock facies in continental rifts. This talk considers several important new observations and developments in our understanding of the sedimentary evolution of lacustrine rift basins. Offshore subsalt basins in the South Atlantic demonstrate the importance of lacustrine carbonates, and especially microbialites, as reservoir facies in extensional systems. The role of rift-related magmatism is significant in these basins, both as drivers of hydrothermal systems around and within rift lakes, and as a source of solutes that facilitate carbonate accumulations. In the Tertiary East African Rift, substantial new hydrocarbon resources have been identified, including onshore siliciclastic reservoirs in remarkably young and shallow parts of the sedimentary section in the Albertine Graben. Rollover anticlines and fault-related folds serve as important structures for several new fields in the East African Rift, but larger structures affiliated with accommodation zones, in many instances located far offshore in the modern lakes, remain untested. Lacustrine source rocks that accumulated in stratified lake basins are the source of the oil and gas in these systems, however there is still much to be learned about their spatial and temporal variability. There is observed considerable variation in the character of organic matter on the floors of modern African lake basins, even adjacent ones. A number of factors likely govern the amount of total organic carbon preserved within the basins. These include 1) primary productivity; 2) degree of siliciclastic dilution, which is controlled in part by offshore slopes and the extent of onshore catchments, and 3) physical limnology, controlled by climate and basin-scale physiography, and the fetch-depth ratio of the lakes, which determines the likelihood of water column stratification. Scientific drilling in the African Rift lake basins is providing considerable information on the high temporal hydroclimate variability of the region, especially in the later Tertiary and Quaternary, which substantially controls basin lithofacies.
Integrated Geophysical Interpretation of Kerio Valley Basin Stratigraphy, Kenya Rift
Authors: Osukuku Godfred , Masinde Abiud , Adero Bernard , Wanjala Edmond , Ego John 
Published: February 2021

Abstract
This research work attempts to map out the stratigraphic sequence of the Kerio Valley Basin using magnetic, gravity and seismic data sets. Regional gravity data consisting of isotactic, free-air and Bouguer anomaly grids were obtained from the International Gravity Bureau (BGI). Magnetic data sets were sourced from the Earth Magnetic Anomaly grid (EMAG2). The seismic reflection data was acquired in 1989 using a vibrating source shot into inline geophones. Gravity Isostacy data shows low gravity anomalies that depict a deeper basement. Magnetic tilt and seismic profiles show sediment thickness of 2.5-3.5 Km above the basement. The Kerio Valley Basin towards the western side is underlain by a deeper basement which are overlain by succession of sandstones/shales and volcanoes. At the very top are the mid Miocene phonolites (Uasin Gishu) underlain by mid Miocene sandstones/shales (Tambach Formation). There are high gravity anomalies in the western and southern parts of the basin with the sedimentation being constrained by two normal faults. The Kerio Valley Basin is bounded to the west by the North-South easterly dipping fault system. Gravity data was significantly of help in delineating the basement, scanning the lithosphere and the upper mantle according to the relative densities. The basement rocks as well as the upper cover of volcanoes have distinctively higher densities than the infilled sedimentary sections within the basin. From the seismic profiles, the frequency of the shaley rocks and compact sandstones increases with depths. The western side of the basin is characterized by the absence of reflections and relatively higher frequency content. The termination of reflectors and the westward dip of reflectors represent a fault (Elgeyo fault). The reflectors dip towards the west, marking the basin as an asymmetrical syncline, indicating that the extension was towards the east. The basin floor is characterized by a nearly vertical fault which runs parallel to the Elgeyo fault. The seismic reflectors show marked discontinuities which may be due to lava flows. The deepest reflector shows deep sedimentation in the basin and is in reasonable agreement with basement depths delineated from potential methods (gravity and magnetic). Basement rocks are deeper at the top of the uplift footwall of the Elgeyo Escarpment. The sediments are likely of a thickness of about 800 M which is an interbed of sandstones and shales above the basement.
Evaluation of Anti-fouling Surfaces for Prevention of Mineral Scaling in Sub-surface Safety Valves
Authors: Charpentier T. V. , Neville A. , Baraka-Lokmane S. , Hurtevent C. , Ordonez-Varela J-R. , Nielsen F. Møller , Eroini V. , Olsen J. H. , Ellingsen J. A. , Bache Ø. 
Published: February 2021

Abstract
Mineral scale formation and deposition in down-hole completion equipment such as subsurface safety valves can cause dramatic and unacceptable safety risks and associated production losses and operational costs. Current scale removal strategies involve both mechanical and chemical technologies, each of them having their own advantages depending on the type of mineral scale and its location. However, these techniques are often costly and of limited efficiency.
The current study assesses the ability of a range of chemically and morphologically modified coatings to prevent/reduce mineral scale surface fouling. Building-up on previous work done under static conditions, this paper presents results from scaling tests under laminar and turbulent dynamic conditions using a rotating cylinder electrode under in a complex (mixed) scaling environment (supersaturated w.r.t. calcium carbonate, barium sulfate, strontium sulfate, barium carbonate and strontium carbonate). The study shows that if properly selected, surface treatments represent a promising approach to reduce scale deposition on downhole equipment surfaces that are critical to maintain equipment functionality and thereby well safety barrier integrity. By analyzing the scaling behaviors observed within the set of surfaces tested, suggestions of the controlling factors in anti-fouling on these systems are presented and discussed.
Synergistic Properties of Phosphonate and Polymeric Scale Inhibitor Blends for Barium Sulphate Scale Inhibition
Authors: Shaw S.S. , Sorbie K.S. 
Published: February 2021

Abstract
Barium sulphate is one of the most difficult types of scale to inhibit in oil and gas production systems, due to its physical hardness and its chemical and thermal stability. Barium sulphate is most commonly inhibited using either phosphonate or polymeric scale inhibitors (SIs) deployed at sub-stoichiometric concentrations. What is less well known in the oil industry is the effect of using combinations of two (or more) SIs synergistically for enhanced scale inhibition performance. A positive “synergistic” effect would be where, for example, 5ppm of A + 5ppm of B performed better than 10ppm of either A or B. In this paper, a series of static barium sulphate inhibition efficiency (IE) test results are presented, in which a series of pairs of SIs have been tested to determine their synergistic properties at pH 5.5 and 95°C. Polymers can be blended with phosphonates, or alternatively pairs of phosphonates or polymers may be applied. In all cases, the synergistic IE is compared with the IE of each SI tested independently at the mass dosage (i.e. the same concentration in mg/L or ppm). Each separate single SI used in the work has been tested previously for barium sulphate IE at pH 5.5, 95°C in order to determine the minimum inhibitor concentration (MIC) for each species (Shaw et al, 2012a, 2012b). Previously, 9 phosphonate and 9 polymeric SIs have been tested individually and, in this work, 34 SI combinations have been tested to examine their synergistic properties. The MICs of the synergistic blends are compared with the normal MICs of the individual SIs. Surprisingly, in most cases, the IE of the blends is usually higher over the range of SI concentrations tested (i.e. the MIC of the blend is lower), compared to that of each SI tested separately. Certain “pairs” of SIs used together yield a significantly beneficial effect, e.g. DETPMP and HMTPMP. Some mechanistic reasons why these synergistic pairs work particularly well are suggested.
Improving Scale Inhibitor Squeeze Design for Naturally Fractured Reservoirs
Authors: Spooner Victoria E , Stalker Robert , Wright Rob , Graham Gordon M 
Published: February 2021

Abstract
Scale Inhibitor (SI) squeeze treatments continue to be an important method for delivering chemical to the production system. However, while SI squeeze treatments in unfractured reservoirs can generally be readily simulated in matrix flow models, designing such treatments for application in fractured reservoirs is less routine, and resulting field treatment lifetimes can be disappointing. One reason for this is that the flow process and transport mechanisms by which the inhibitors are retained in fractured formations differs considerably from simple matrix flow. In this paper we expand upon previously published work examining the impact of squeeze treatment design on the outcome of a SI squeeze treatment for a fractured well using a novel fractured well squeeze model.
In previous papers, we highlighted the importance of diffusion-controlled transport of SI in low permeability tight matrix fractured reservoirs where little matrix flow is possible. In this paper, we report continuing developments of the fracture squeeze model and demonstrate how differences between advection and diffusion-controlled inhibitor transport can significantly alter the predicted squeeze treatment lifetimes, and suggest appropriate treatment design modifications to improve SI squeeze treatments in such fractured reservoirs.
This paper will demonstrate that such differences in transport mechanisms directly impacts the distribution of scale inhibitor within the near-wellbore region during the treatment phase. In fractured systems, this SI distribution is affected both by the extent of propagation of injection fluid through the fracture network and rate of diffusion into the surrounding matrix rock. This work examines the influence of factors such as injection rate, soak time, inhibitor diffusivity and retention/release properties on the matrix material.
By adjusting injection parameters such as injection rate and soak time in the treatment design, a more desirable distribution of scale inhibitor can be obtained, resulting in improved predicted treatment lifetimes. Thus, using the fracture squeeze model to provide a fuller simulation of the inhibitor transport, retention and release mechanism active in a fractured reservoir, we highlight potential placement issues for such reservoirs and demonstrate methods to improve squeeze design for fractured wells.
TOTAL's Experience on the Development and Implementation of a Scale Management Strategy in Central Graben Fields
Authors: Baraka-Lokmane Salima , Hurtevent Christian , Zhou Honggang , Saha Pratik , Tots Nourdine , Rieu Frédéric , Lastennet Ronan , Sugiarto Tomi 
Published: February 2021

Abstract
In Central Graben, North Sea, there is generally no free water production, most of the produced water is condensed water; however wells have been treated against scale build up at perforation level by performing acid washes using mainly acetic acid. Wells reacted differently after acid treatment: Some wells showed a significant productivity improvement, others showed good results but limited in time, some wells presented no gain after acid treatment and some other wells are scaling on a more aggressive basis after acidification. This paper shows that these behaviours are linked with the lithology of the different reservoirs. A better understanding on the scale formation and mechanism is essential in order to optimize the well intervention planning and timing to treat the wells. This study showed that calcium carbonate and sodium chloride are the only scale deposits susceptible to precipitate at the bottomholes of wells. The precipitation of sodium chloride has been induced by the high salinity of water associated with a high temperature at bottomholes as well as an inversion of the Joule- Thomson coefficient. Calculations showed that evaporation is slightly higher for Elgin reservoirs comparing to Franklin reservoirs, this is due to Joule-Thomson effect slightly stronger and a higher temperature reservoir for Elgin reservoirs. These high temperatures at the bottomholes induced the formation of calcium carbonate precipitation, this conducted to the loss of productivity. From the subsurface safety valve (SCSSV) to the surface facilities, the reduction of temperature caused a reduction of solubility of zinc sulphide and lead sulphide. In terms of chronology, halite scale occurred first, followed by carbonate scale and finally formation of sulphide scale at lower temperature.