bluuebunny/crossref_metadata_2025_split huggingface dataset:
Sand Monitoring in Gas Wells: Enhanced Methodology of Sand Sampling via Combination of Online Sand Sampler and Acoustic Sand Monitors to Determine Max Sand Free Rates for Identification of Quick Gain Opportunities and to Quantify Sand Production
Authors: Kunasekaran Sarran Raaj , Sidek Sulaiman , Ambrose Jonathan , Mackie Alex 
Published: November 2020

Abstract
Sand production from wells are one of the operators’ biggest nightmare as the cascading effect can cause some major harm to the surface equipment as well as lead to a costly cleanup effort. Sand sampling in gas wells is considered a rare activity due to the difficulty of containing the gas flow. The objective of this paper is to elaborate on why this activity is crucial to be performed in sand prone gas wells and more importantly the value it can bring to the asset owner. The paper will also elaborate further on the benefits of coupling the online sand sampler with the acoustic sand monitors to improve accuracy and reliability of readings
The paper will elaborate the major difference in sampling for oil wells and gas wells. Operators of oil fields have the liberty of sampling from an existing sampling point to obtain the sand count. However, obtaining the sand count in a gas well is not as straight forward as it is for oil wells hence the importance of this activity. Quantification of sand produced in gas wells are also a challenge as only amount of sand is reported from the desander flushing. The paper will contain a detailed procedure on the methods to quantify sand production as well as the process flow to determine the max sand free rates safely to meet the objectives of this project.
Some of our wells were ‘accused’ of producing sands at certain flowrates. Since the wells were not equipped with any type of permanent sand monitoring equipment, there were no conclusive ways of proving that the wells were sand free. Due to that, the wells flowrates were curtailed to protect the asset from the effect of sand production. With the completion of this activity, we could conclusively prove that the wells were free from producing sands at the existing rates. On top of that, from the process of determining the max sand free rates (MSFR) this activity gave us enough confidence to produce our wells at a proved sand free rate. In conclusion, not only does this activity allow us to prevent further production deferments, this activity also allows us to increase production by beaning up the wells if possible
This is a very flexible method that can be used as the main method to sample sand in gas wells. It is a very cost-effective method as well as logistically friendly to mobilize to even offshore fields.
Is Chemical EOR Finally Coming of Age?
Authors: Delamaide Eric 
Published: November 2020

Abstract
Chemical flooding is one of the classical EOR methods, together with thermal methods and gas injection. It is not a new method; indeed, the first polymer flood field pilots date back to the 1950s while the first surfactant-based pilots can be traced back to the 1960s. However, while both gas injection and thermal methods have long been recognised as field proven and are being used at a large scale in multiple fields, it is not the case for chemical EOR.
Although there have been over 500 polymer flood pilots recorded, and almost 100 surfactant-based field tests, large scale field applications are few and far between. This situation seems to be evolving however, as more and more large scale chemical projects get underway. This paper proposes to review the status of chemical EOR worldwide to determine whether it is finally coming of age.
The status of chemical EOR projects worldwide will be reviewed, focusing on recent and current large-scale field developments. This will allow to establish what is working and where the industry is still encountering difficulties. This review will cover North America, South America, Europe, the Middle East, Asia and Africa.
It is clear that polymer flooding is now indeed becoming a well-established process, with many large-scale projects ongoing or in the early stages of implementation in particular in Canada, Argentina, India, Albania and Oman in addition to China. Strangely enough, the US lags behind with no ongoing large-scale polymer flood.
The situation is more complex for surfactant-based processes. At the moment, large-scale projects can only be found in China and – although to a lesser extent – in Canada. The situation appears on the brink of changing however, with some large developments in the early stages in Oman, India and Russia. Still, the economics of surfactant-based processes are still challenging and there is some disagreement between the various actors as to whether surfactant-polymer or alkali-surfactant polymer is the way to go.
This review will demonstrate that polymer flooding is now a mature technology that has finally made it to very large-scale field applications. Surfactant-based processes however, are lagging behind due in part to technical issues but even more to challenging economics. Still there is light at the end of the tunnel and the coming years may well be a turning point for this technology.
Integrating Reservoir Characterisation, Diagnostic Fracture Injection Testing, Hydraulic Fracturing and Post-Frac Well Production Data to Define Pressure Dependent Permeability Behavior in Coal
Authors: Johnson Raymond L. , You Zhenjiang , Ribeiro Ayrton , Mukherjee Saswata , Salomao de Santiago Vanessa , Leonardi Christopher 
Published: November 2020

Abstract
Defining pressure dependent permeability (PDP) behaviour in coalbed methane (CBM) or coal seam gas (CSG) reservoirs using reservoir simulation is non-unique based on the uncertainty in coal properties and input parameters. A diagnostic fracture injection test (DFIT) can be used to investigate bulk permeability at a reservoir level and at lowered net effective stress conditions. As coal has minimal matrix porosity and under DFIT conditions cleat porosity is fluid saturated with reasonably definable total compressibility values, the DFIT data can provide insight into PDP parameters. At pressures above the fissure opening pressure, pressure dependent leak off (PDL) behaviour increases exponentially with increasing pressure. Many authors have noted that with decreasing pressure PDP declines exponentially with increasing net effective stress. Thus, PDP behaviour can be defined by PDL.
In this paper, we show how combined analyses, using typically collected field data, can be used to better define and constrain the modelling of PDP. We illustrate this process based on a well case study that includes the following data: fracture fabric and porosity reasonably defined from image log and areal core studies; DFIT data acquired under initial saturation conditions; hydraulic fracturing data; and longer term production data. These analyses will be integrated and used to constrain the parameters required to obtain a rate and pressure history-match from the post-frac well production data.
This workflow has application in other coal seam gas cases by identifying key variables where hydraulic fracturing performance has been unable to overcome limitations based on pressure or stress dependent behaviours and often accompanied by low reservoir permeability values. While this is purposely targeting areas where only typically collected field data is available, this workflow can include coal testing data for matrix swelling/shrinkage properties or other production data analysis techniques.
Direct Approach for Contact Angle Measurement of Neutral Wet HSP Proppants
Authors: Al-Boghail Fawaz , Al Moajil Abdullah , Al-Arawi Abeer , Al-Darwish Sajad 
Published: November 2020

Abstract
Neutral wet proppant plays a pivotal role in maximizing the flow back of fracturing fluids and the recovery of produced hydrocarbons. An accurate and repeatable contact angle measurements are extremely challenging because of proppant spherical shape and small size. This paper presents a methodology of direct contact angle measurements in spherical particles examined with high strength coated ceramic proppant.
20/40 and 25 HSP non coated proppants were used for the study. Coating material was applied to the proppant sample to obtain non-wetting characteristics. KRUSS Drop shape Analyzer was utilized to measure the contact angle using a modified pendent drop method. Step by step procedure is detailed and possible sources of errors were identified, and recommendations were introduced accordingly.
HSP coated proppant showed contact angle measurements of 117-120° and 84-114° with deionized water and hydrocarbon samples, respectively. Ideally, a neutrally wetted surface would have a contact angle of 90°. This indicates that the proppant is neutral to slightly oil-wet. Wetting characteristics are dependent of hydrocarbon type. For instance, Condensate 2 have a contact angle of 102.3° indicating neutral wetting characteristics, whereas Condensate 3 shows contact angle of 84.5° indicating slightly oil-wet character. Geometry of hydrocarbon droplets modified the adhesion tension of oil, nevertheless had insignificant effect with water drops. For example, tripling the droplet size of Condensate 2 and Diesel resulted in increment in contact angle values of 12° and 15°, respectively.
New Method of Well Integrity Screening for Carbon Dioxide Storage Well
Authors: Zulkarnain Nurul Nazmin , Abu Bakar Mohd Azuan , Zakaria Nur Atiqah 
Published: November 2020

Abstract
The issue of global warming is widespread nowadays with an increase in the surface temperature of the earth. Carbon dioxide, CO2 emission from industrial energy is one of the contributing factors to this issue. The concept of CO2 storage is one of the potential solutions to achieve zero CO2 emissions from the oil and gas industry. In order to have an effective cost solution, existing wells are suggested as CO2 injection wells. Therefore, the structures of the existing wells are assessed to observe the sustainability of the well towards CO2 injection since the wells previously drilled without considering their potential secondary life.
Well screening is carried out through 19 development wells in the RSK field. The method used in this screening including; information gathering through the master database, selection of screening criteria and risk quantification. The screening criteria consist of cement quality and quantity, casing metallurgy and wellhead grade. The screening results will be categorized under three different risks; low, high and unknown-risk. Each of the categories and the evaluation methods will be discussed in-depth in this paper.
The assessment resulted in 44% of low-risk well, 50% of the high-risk well and the remaining 6% of the unknown-risk well. The high-risk well is when the well does not meet one or more screening criteria set out, while the low-risk well clearly shows the well fit all the standard as CO2 compliance well. The unknown-risk is classified when there is no sufficient information to do the evaluation. It can be observed that most of the high-risk wells are from the first drilling campaign, while the latest campaign contributes to most of the low-risk well. To reduce the severity of high-risk well, squeeze cementing, geopolymer cement, wellhead modification and workover can be suggested. At the same time, detailed report searching from operators and service companies can be recommended to unknown-risk well.
The study is a quick look well screening for CO2 storage well. In order to strengthen the screening result; reservoir continuity, caprock integrity and comprehensive well assessment concentrating on packer integrity, tubing integrity, injection pressure, internal and external pressure and corrosiveness of injection fluid can be carried out to transform the high-risk well into a low-risk well and classifying the unknown-risk into a specific class.
Utilizing Surface Microseismic Monitoring to Improve Understanding of Natural Fractures in Sichuan Shale Gas Play
Authors: Jing Cui , Chen Yanyan , Jing Xianghui , Wang Bing , De Heng , Huang Zheyuan , Wen Ran , Zhang Caiyun , Zhou Nie 
Published: November 2020

Abstract
The highly complex geology of the Sichuan Shale gas play, especially in relation to natural fracture systems at different scales, affects the hydraulic completion efficiency and performance. Ant-tracking-based workflows and borehole image data are regularly used to optimize completion campaigns, but bridge-plug-stuck and screen-out risks are still high. The lack of sufficient understanding and accurate identification of the natural fracture systems are the major challenges to address these engineering risks.
Surface microseismic monitoring campaigns were conducted over several wells of the Changning field, Sichuan Basin, China. The surface receivers were placed in a radial pattern to record microseismicity generated by hydraulic fracturing. The failure mechanism of all mapped microseismic events (i.e., strike, dip, rake, etc.) was extracted using a moment tensor inversion (MTI) method. Improved understanding of the natural fracture systems and their influence during the hydraulic fracturing process has been achieved by integrating the regional geological data, pumping data and MTI results.
Several hydraulic fracturing cases that stimulated near natural fracture systems were investigated. The microseismic monitoring results show that (i) most of the hydraulically induced fractures located in the vicinity of the natural facture or fault did not propagate along the regional maximum stress direction, (ii) the bridge plug got stuck and (iii) screen-out happened frequently in these areas. Moment tensor inversion reveals that (i) the dominant failure mechanism of the natural fractures different from hydraulically induced fractures, (ii) more than one group of natural fractures develop along different directions.
Real-time adjustments of the pumping schedule and bridge-plug settings were conducted to reduce engineering risks based on the improved understanding of natural fractures, which proved effective. The innovation of using surface microseismic monitoring results to improve understanding of natural fractures and reduce the engineering risks in real time represents a key step forward to mitigate natural fracture influence and improve the effectiveness of stimulation.
The First 7-in. Single-Trip Multizone STMZ Gravel Pack Completion Best Practices and Lessons Learned in Malaysia Offshore
Authors: Bakar Hasmizah , Faris W Hassan W M , Kumar Suman , Faliq Jamal Ajmal , Magna Bela Sunanda , Fiqri Hairi Helmi , Latif Nurlizawati , Hashim Saharul , Tham Dennis , Shahabuddin Syukri 
Published: November 2020

Abstract
A 7-in. single-trip multizone (STMZ) gravel pack system was installed successfully in two wells in the T field, Sarawak offshore. This paper highlights the system performance and knowledge obtained during this first-time installation performed in Malaysia. The most common sand control techniques established in the H, I, and J sands of this mature field include stacked gravel pack, 9 5/8-in. single-trip multizone gravel pack, and openhole standalone sand screen (OHSAS) systems. Internal gravel pack completions have provided proven, robust sand control for the sand-prone reservoirs in the T field and can save four to five days of rig time depending on the well configuration, compared with the standard stacked gravel pack completion, which was initially planned during the field development plan (FDP) stage. This paper presents the extensive technical works performed post-FDP approval to ensure the change from the 7-in. stacked gravel pack to the 7-in. single-trip multizone gravel pack completion was executed safely and efficiently and most importantly able to maximize the recoverable reserves from the multiple unconsolidated reservoirs. The technical challenges, such as unexpected drilling of additional zones, limited annulus clearance between the 7-in. liner and gravel pack tool string to reverse out proppant efficiently, intersands spacing, and gross sand interval constraints within certain tolerance because of bottomhole assembly (BHA) limitations, are also discussed. The 7-in. single-trip multizone gravel pack installation helped reduce rig time and provided a cost savings of nearly USD 1.1 million. Subsequently, the two oil-producing (OP) wells (two OP wells and four OP strings) are producing sand-free at higher than expected reserve and flow rates.
Using Alcohol-Treated CO2 to Reduce Miscibility Pressure during CO2 Injection
Authors: Saira Saira , Yin Hang , Le-Hussain Furqan 
Published: November 2020

Abstract
CO2 injection is one of the most promising enhanced oil recovery (EOR) techniques because it can also reduce greenhouse gas through CO2 sequestration. However, effectiveness of CO2 injection dependent on CO2 miscibility. If reservoir is depleted, reservoir pressure is usually not high enough to achieve miscible or near-miscible conditions during CO2 injection in oil reservoirs. In this paper we investigate whether the required miscibility pressure can be reduced by substituting CO2 with alcohol-treated CO2.
Experimental measurements of interfacial tension (IFT) and swelling behavior were made using a high-pressure and high temperature visual cell at 70 °C. Two sets of fluid pairs were used (i) pure CO2 and oil, and (ii) alcohol-treated CO2 and oil. Two types of oil were used: a mixture of 35% hexane and 65% decane (C6-C10 mixture), and pure decane (C10). Ethanol and methanol alcohols were used to prepare alcohol-treated CO2 (a mixture of alcohol and CO2 equilibrated at experimental pressure and temperature). The experiments were matched using an equation of state to provide a quantitative measurement of the miscibility pressures. This study has identified that capillary rise method can be used for IFT measurements down to 0.04 mN/m. The conventional pendant drop method can only be used for IFT values greater than 1 mN/m. For IFT values greater than 1 mN/m, both methods are in close agreement. Validation of IFT simulated model with experimental IFT results showed a good agreement. Results showed that for pure C10, ethanol-treated CO2 cause 0.4 mN/m to 1.5 mN/m IFT reduction leading to 1.1 MPa minimum miscibility pressure (MMP) reduction and methanol-treated CO2 cause 0.4 mN/m to 2.2 mN/m IFT reduction leading to 0.2 MPa MMP reduction. While for C6-C10 mixture, ethanol cause 0.02 to 1.42 mN/m reduction in IFT and methanol cause 0.02 to 0.2 mN/m. Both alcohol have similar reduction of 1.1 MPa in MMP. Results also suggest that alcohol-treated CO2 leads to a better oil swelling behavior for both type of oil which helps to release oil from rock pore. However, ethanol presence in alcohol-treated CO2 shows more oil swelling than methanol. Experimental observations reveal that alcohol-treated CO2 is effective than pure CO2 for IFT reduction and enhancing oil swelling. Furthermore, experiments should be performed using real field crude oil.
Quick Caprock Integrity Analysis for CO2 Storage Sites in Malaysian Fields.
Authors: Mohd Ali Siti Syareena , W. Zairudin W. Ahmad , Abu Bakar Zainol Affendi , Kantaatmadja Budi Priyatna , Ismail Issham 
Published: November 2020

Abstract
The purpose of this research work is to establish a quick method for caprock integrity assessment for carbon dioxide (CO2) storage site selection. There are three main components to evaluate a seal potential which are through seal capacity, seal geometry, and seal integrity. This research work focuses on evaluation of seal characteristics through its pressure behaviour and evidence of potential leakage. Various logs data such as gamma ray, sonic logs, density logs, and resistivity are utilized to establish 1D pore pressure analysis. At the same time mud logs data are used to investigate the similarity of hydrocarbon from reservoir and seal (if any). In this study, two mature brownfields namely Camos and Zhann have been identified and evaluated for their seal characteristics, thickness, environment of deposition and pressure regimes differences in order to determine their seal effectiveness through integration of pore pressure analysis, background gas or gas while drilling evidence and seal capacity from Mercury Injection Capillary Pressure (MICP) data. Camos field, a depleted carbonate field in Sarawak Basin with continuous seal shows an overpressure regime with gas chimney in immediate seal above it. Meanwhile Zhann field, a depleted clastic field in Malay Basin shows slight overpressure in deeper reservoirs and hydrostatic in most of the multistack sand reservoirs. Both fields show the evidence of effective seal through their own geological characteristics, pore pressure and gas component analysis. Nevertheless, both fields have their own challenges to be converted to potential storage sites. A detailed understanding and analysis are required for seal integrity evaluation which can lead to better plan establishment that may further reduce risks during selection of CO2 injection site and help to execute future well or field monitoring design.
Multi-Sensor Time-Domain Electromagnetic Measurements for Quantitative Evaluation of Multi-Barrier Corrosion
Authors: Dutta Sushant , Iqbal Pervaiz , Olaiya Joseph 
Published: November 2020

Abstract
A state-of-the-art time-domain electromagnetic tool is presented that is capable of quantifying four barriers individually, and inspecting a fifth barrier qualitatively. The working physics and salient features of the tool and its underlying technology are described.
The new tool uses time-domain electromagnetic (TEM) or pulsed eddy current (PEC) technology, which has set the benchmark for individual quantitative tubular corrosion evaluation in multi-annular well systems (multiple concentric tubulars) in recent years. Time-domain electromagnetic tools widely used in the industry are currently capable of quantifying the individual metal thickness/loss in up to three barriers. The new tool employs three highly sensitive sensors to provide high-resolution analysis of the inner barrier, while providing sufficient radial depth of investigation for up to five barriers.
The above features and advantages of the new tool are supported by modeling and fixture test results. Additional modeling is shown to compare and contrast the resolution and radial depth of investigation of the three sensors. Case studies from actual wells are also presented that illustrate how three sensors enhance the performance of this technology. Corrosion evaluation of multi-barrier systems is a major component of well integrity management because it can provide timely and cost-effective information for planning well repairs if needed. The ability of the new tool to inspect more barriers is important because it gives the operator better information for more proactive well integrity management.
The novelty of the tool is in its ability to exploit the information-rich wideband pulsed excitation using three sensors that enhance the sensitivity to multiple barriers.