bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mitigating Hydrates in Subsea Oil Flowlines: Consider Production Flow Monitoring & Control.
Authors: Kanu Akachidike , Al-Hajiri Nayef , Messaoud Younes , Ono Norihito 
Published: May 2016

Abstract
Risk of gas hydrates occurring in subsea flowlines presents serious problems to offshore oil and gas production operations. Hydrate incidents can occur in oil and gas production systems provided that the favourable compositional mix and thermodynamic conditions exist. The principal method used to mitigate hydrates in subsea flowlines is the injection of hydrate inhibitor chemicals. Thermodynamic hydrate inhibitors (THIs) have traditionally been used but these have disadvantages, namely high OPEX with increasing chemical volume demand, space constraints, high CAPEX, and safety and toxicity concerns. Recently, low dosage hydrate inhibitors (LDHIs) such as kinetic hydrate inhibitors (KHIs) and antiagglomerants (AAs) which offer advantages of minimal volume and space requirements have received considerable attention. However, widespread application of these new classes of inhibitors has been limited by yet a number of concerns including water-cut and/or subcooling temperature range limits, lack of predictive models, toxicity, biodegradability, compatibility, and produced water quality and disposal issues.
This paper presents a case study of an alternative "do-nothing" operational technique involving the comingle flow of well streams from different reservoirs at a pre-determined volume flow ratio, with temperature monitoring. Effective well-stream volume flow ratio was determined by predictive model studies of fliud systems hydrate equilibrium and pipeline operating envelops, followed by field trials. Results show that risk of hydrates in flowlines with multi reservoir fluids can be minimised by the control of the in-line fluid compositional mix by conventional flow control operation. Conceptual assessment studies suggest that this method of hydrate control could provide a cost-effective alternative to the use of chemical inhibitors, on a short-medium term basis, particularly in cases of seasonal hydrates and minimum-facility marginal oil production. Further study of effect of salinity of the produced crude on hydrate formation, given anticipated water-cut breakthrough with time, would further confirm the economics of this strategy on a field lifecycle basis.
Sub Sea Compression at Ormen Lange
Authors: Rijnbeek Roald 
Published: May 2016

Abstract
One of the most technically demanding developments on the Norwegian Continental Shelf, the Ormen Lange field is located 120 km offshore in 1000 meters water depth in the Møre Basin in the Southern part of the Norwegian Sea. It is a complete subsea development comprising four wellhead templates that tie back to an onshore gas processing facility at Nyhamna, where gas is dried and compressed before export to the Langeled pipelinevia the Sleipner platform to the UK.
The deep water and the seabed conditions have made the development very challenging and have necessitated novel technologies for the base project. The need for depletion compression was recognized from the initial development stages of the field and the Permit to Develop and Operate required the license partners (Shell, Statoil, Petoro, ExxonMobil, and DONG Energy) to develop subsea compression technology. This has resulted in the development of a full scale operational pilot plant to prove that subsea compression technology is viable. This paper explores the challenges that the license and Shell as operator as well as the subsea industry have overcome in developing this novel technology and outlines the future plans for the eventual selection of subsea compression as the development concept for depletion compression on Ormen Lange and elsewhere.
Mechanical Pipe Cutting in ERD Wells with Pipe Under Compression
Authors: Macfarlane Robert , Schwanitz Brian , Aguirre Marco , Greenlee James 
Published: May 2016

Abstract
In order to reduce rig time during workover operations, a new electric line (e-line) mechanical pipe cutting tool was deployed rigless in four ERD wells in the Middle East.
The 4-1/2" production tubing of several high deviation wells needed to be cut and pulled prior to a tubing change-out campaign, commencing February 2013. This particular mechanical cutter was chosen for its non-explosive design, where a rotating crown removes pipe wall by grinding, creating a smooth bevelled surface without shavings. This eliminates the need for a polishing trip, allows the pipe to be severed even when under compression, and leaves a cut profile in the well which is ideal for subsequently fishing. Also, this type of cutter incorporates a 'fail-safe' mechanism that prevents the tool from becoming stuck following the cut process, and the cutting crown design precludes the tendency for sticking, which is a major concern with other mechanical cutters.
In January, 2013, a system integration test was conducted to determine whether a grinding face cutter could actually cut a pipe in compression. A jig was set up to provide 20,000 lbs of compressive force on a 4-1/2", 12.6 lbs/ft pipe. The cut was made in 36 minutes. The subsequent rigless operations on four wells resulted in six successful cuts, without the requirement for the pipe to be put in neutral weight or tension. The amount of compression at the cutting depth was unknown, but at least 10,000lbs, as per the packer setting procedures.
A key benefit of mechanical pipe cutters is that they eliminate the use of explosives and chemicals which can pose HSE and operational risks, especially when simultaneous operations are being conducted. The transfer and handling of explosives may also cause additional logistical requirements and significant delays, as safety procedures are employed. In addition, this mechanical solution eliminates the need for dress runs, and tubing recovery is optimized from a rig time perspective.
This paper will discuss the operational steps taken to make the pipe cuts, a description of the new pipe cutting tool and lessons learned to improve future operations.
Implementation Of Interval Velocity Data In The Analysis Of Vertical Fluid Migration Routes And Charging Offshore Qatar
Authors: Andresen K. J. , Uldall A. , Hertle M. , Madsen L. , Perrin C. , Rameil N. , Durance G. , Tirsgaard H. , Emang M. , Gagigi T. 
Published: May 2016

Abstract
Oil production from the Al Shaheen Field in Block 5 and Block 5 Extension, offshore Qatar, relies on horizontal drilling and careful stimulation of the very thin and low-permeable Cretaceous carbonate reservoirs. Although the field has been in production since 1994 some uncertainties remain, particularly concerning fluid migration routes and charging of the field. The field appears to be effected by vertical anomalies which have the potential to act as vertical migration paths for fluid migration possibly impacting fluid distribution and characteristics at present day reservoir levels.
This study uses 3D seismic data combined with a calculated interval velocity volume to analyse the vertical anomalies in more detail. The anomalies are vertically extensive and typically characterized by lower velocities than the surrounding strata. They have been mapped according to their vertical extent, average velocity, any associated lateral effects, initiation and termination levels and their relation to other features in the area.
The results of the mapping suggest that the majority of the velocity anomalies are related to fluid migration with gas causing the anomalous low velocities. The present day gas cap in the Kharaib reservoir may have formed due to vertical migration of gas along the velocity anomalies, which in the area of the gas cap are associated with very low velocities and all terminate at the level of the reservoir. In the areas north of the gas cap, the velocity anomalies generally terminate shallower suggesting that fluid venting probably continued to the seafloor thereby preventing gas accumulation in the reservoirs.
The study successfully implements velocity data in the analysis of fluid migration routes and supplements the current understanding of some of the uncertainties related to the Al Shaheen Field. The results represent new inputs to the characterisation of fluid migration within the reservoirs and the existing production and may furthermore provide new input in the assessment of the future development of the field.

Introduction
Maersk Oil Qatar has since 1994 successfully produced oil from Cretaceous carbonate reservoirs in the Al Shaheen Field, offshore Qatar. The production relies on horizontal drilling in the very thin and low-permeable reservoirs. Despite the maturity of the field, several uncertainties remain for the area particularly concerning charging history and oil migration into the field.
Diagnosis of Multiple Fracture Stimulation in Horizontal Wells by Downhole Temperature Measurements
Authors: Cui Jingyuan , Zhu Ding 
Published: May 2016

Abstract
Diagnosis fractured well performance for a multiple-stage fractured horizontal well is critical to understand and improve fracture stimulation design. Production logging tools (PLT) can be used in this problem, and temperature distribution data (by PLT or fiber-optic sensors) is one of the valuable information for performance diagnosis. However, until today quantitative interpretation of dynamic temperature data is still challenging and requires in-depth mathematical modeling of heat and mass transfer during production in a complex flow system.
In this study we developed a semi-analytical model to predict temperature and pressure behavior in a multiple-fractured horizontal well during production. The tri-linear model is used to simulate flow in a fracture system for horizontal wells. The model can be applied for single phase oil or gas wells. For gas well, the non-Darcy effects are considered by permeability alteration using minimum permeability plateau. Flow in the wellbore is modeled under unsteady state condition modified from a steady state horizontal wellbore model presented before. This coupled model for fracture flow and wellbore flow can predict the pressure gradient along fracture and also the pressure and flow rate distribution in the wellbore. The thermal model calculates the heat transfer in the fracture/reservoir/wellbore system considering subtle temperature changes caused by the Joule-Thomson cooling and frictional heating effects. The fluid properties are set as functions of in-situ pressure and temperature.
The result shows that transient temperature behavior can be used to estimate the fracture initiation points and length, number of created fractures and distribution of fluid along the wellbore. The temperature is sensitive to the flow rate distribution along the wellbore, the fracture geometry, and also the fracture conductivity. With the developed method, we can evaluate the fracture treatment by comparing the designed fracture half-length with the generated fracture-length. When applied in history match of production data, it also can predict conductivity decline as a function of production time.

Introduction
Due to the improved accuracy and continuity of downhole temperature measurement, downhole sensors attract a lot of interest in petroleum industry. Besides the pressure/temperature gauges, distributed temperature sensors (DTS) and production logging tools are the common methods to assess well production and formation information. With the development of hydraulic fracture technology and its successful application in tight gas and shale reservoirs, the downhole temperature measurement also used during the stimulation treatment to monitor the fracturing process and later in production period to evaluate the fractures' effectiveness.
Multi Strategy Approach to Manage Waxy Oil Wells in Malaysia's Marginal Fields - A Unique Experience Offshore Peninsular Malaysia
Authors: Cheong Ing Keith , Saidu Anwarudin 
Published: May 2016

Abstract
Wax formation continuously proves itself to be a major problem in PETRONAS Carigali's marginal fields as it clogs up the well, damages the near wellbore formation hence severely impairing production. A clogged up well also makes well intervention impossible as toolstrings are restricted by the wax plug and in worse cases get stuck hence leaving a fish in hole. Some of the marginal fields in West Malaysia are notoriously known to produce very waxy crude and would harden in just a matter of a few minutes at surface conditions due to its relatively high pour point.
What adds to the challenge faced is that platforms located in these marginal fields are mostly smaller sized platforms fitted with small cranes that have small lifting capacity. Space on these platform facilities is quite limited, thus restricting larger size intervention equipment such as the coiled tubing unit while also limiting the platform's crane capacity. Furthermore such platforms are typically unmanned and located in remote areas. Complicated well intervention techniques will not only increase the safety risk but would also tremendously increase the intervention cost.
Due to the nature of such challenges, PETRONAS Carigali has resorted to develop an ingenious strategy to manage the wax plugging problems in its marginal field's wells. A multiple strategy approach has been undertaken to tackle the wax problem, depending on the severity of the wax buildup in the well. These approaches are divided into two types – with intervention and without intervention depending on the degree of wax buildup.
All these steps taken by PETRONAS Carigali have helped to control the wax problem in its highly waxy marginal fields of West Malaysia to a manageable level and the experience gained can serve as a good technical lesson on how to manage a waxy well in small and remote platforms.

Introduction
Field P which is situated within the marginal fields cluster offshore peninsular Malaysia is notoriously known to be very problematic in terms of wax deposition. The pour point of the crude oil from this field is 56 OC hence resulting in a lot of wax build up. Deposition of organic components can have adverse effect on the production, transportation and processing of crude oil. The economic concerns of organic deposition can be overwhelming. Heavy organic molecules such as asphaltenes, paraffin /wax, aromatics and resins exist in crude oils in various quantities, forms and are the main source of organic deposition. Due to several mechanisms, these compounds could separate out of the crude oil and be deposited. Asphaltene especially has a major effect on the toughness of the deposits; it acts as glue in toughening the deposit, therefore causing resistance to oil flow [1].
In a nutshell, organic deposition predominantly in the near well bore and in the production tubing can cause:Flow restrictionsNear wellbore damageReduced efficiency of crude transportation and processing units
Ascendancy of Continuous Profiles of Grain-Size Distribution for Depositional Environment Studies
Authors: Gaafar Gamal Ragab , Altunbay Mehmet , Bal Adriaan , Anuar Norfazlina B 
Published: May 2016

Abstract
Knowledge of structure, composition and texture, the three fundamental attributes of sedimentary deposits, is necessary for a robust analysis and interpretation of depositional environment. In the absence of core information; borehole images, "elemental-capture spectroscopy" and NMR logs all contribute to understanding the structure, composition and grain-size attributes. Grain-size is considered the most important textural parameter because it reflects the processes and energy levels active at the time of deposition. Early studies show that depositional processes and environment can be inferred from size distributions (Krumbein1934 and Sahu1964).These inferences are based on deductions and experimental data and deliver acceptable accuracy. Although Krumbein (1941) shows other textural (e.g. shape, roundness, roughness) and compositional information enhances certainty.).
Building on early work, we present a methodology and examples where NMR derived grain-size-distributions are used to infer depositional environment. In contrast to spot-core analysis, NMR provides a continuous along hole profile of grain-size-distributions. This study is the first to utilize a continuous grain-size-distribution profile. The study was conducted blindfolded, without initial reference to core studies, to test the robustness of the methodology.
By using statistical parameters from grain-size distributions that are characteristic of depositional environments, and applying Sahu (1964) linear-discrimination functions, depositional systems for two wells were inferred to be shallow marine-to-fluvial deltaic. Linear-discriminate analysis of geostatistical variables showed bimodal distributions of sediments dominated by fine-grain sands and silts. The studied sandstones were concluded to be mainly fine grained, moderately to poorly sorted, fine skewed, mesokurtic, leptokurtic occasionally platykurtic in nature.
Our conclusion was "shallow-marine deposition" and was compared and confirmed with core-driven studies as "shallow marine". In summary, profiles of grain-size-distributions from NMR logs provide important information about changes in depositional energy level from which we infer depositional setting and reservoir quality. A precise depositional environment interpretation is crucial for optimal/economical field development.
Geochemical Characteristics and Genetic analysis of Ordovician Dolostone reservoirs, in the Ordos Basin, China
Authors: Zhang YueQiao , Guo YanRu 
Published: May 2016

Abstract
The Ordovician dolomites have been known as one of the largest gas producers in China and their mechanism of dolomitization has been a hot topic for many years. Core-based studies including slices observation, X-RAS identification, carbon and oxygen isotope, major and trace elements and Rare Earth Element (REE) analysis have been conducted to investigate the geochemical characteristics of dolomite and the mechanism of dolomitization in this reservoir. Petrography and diagenesis analysis of more than 1,000 meters of core from five wells near center of the Ordos Basin shows that these dolomites has the following geochemical characteristics:Dolomites mainly show red-brown and dark brown, the degree of order is high and the molar volume of CaCO3 is low.The content of Sr and Na is low, while Fe and Mn is high, which may have undergone a normal burial evolution.The δ18O and δ13C ranges from –4.57‰ to –9.16‰ Pee Dee Belemnite [PDB], and -2.53 to +1.63‰ PDB, which lower than those of the Ordovician seawater. The negative values of δ18O of dolomite result probably from temperature effect of the burial process.The high homogeneous temperature of fluid inclusions in dolomite (90o to 130oC) indicates deep burial circumstances.REEs must have experienced clear differentiation, since the values of LREE/HREE are all over 1, clearly indicating the characteristic of enrichment of LREE and decrement of HREE. Ce has no obvious anomaly and Eu has clear negative anomalies, which suggests a reducing environment.
This interpretation is also supported by the presence of large saddle-like dolomite and high temperature minerals at the deeper part of the reservoirs. All characteristics above reveal that those dolostone have been formed in a deep burial environment, while not in mixing zone as former studies showed.

Introduction
The dolomite problem has been the research focus of the geologists for more than 150 years. In the past few decades, petroleum geochemists have try to applied various analysis methods to address this question, including stable istopes, trace elements, and fluid inclusions etc. Those most common groups of tools in use help to study the ultimate origin of an ancient dolomite. An evolutionary history of dolomitization can be outlined only when all these methodologies are combined under the umbrella of detailed petrographic study, which allows a tie of the various geochemical values to appropriate crystal tratigraphy (e.g. Drivet and Mountjoy, 1997; Yoo et al., 2000).
Retrieving Information and Discovering Knowledge from Unstructured Data Using Big Data Mining Technique: Heavy Oil Fields Example
Authors: Wu Wenkuang , Lu Xiaoguang , Cox Ben , Li Guoqiang , Lin Lihua , Yang Qing 
Published: May 2016

Abstract
In recent years, big data and relevant analytics technologies have become increasingly popular in E&P industry. Numerous tools and techniques such as Hadoop, HBase, Hive and Mahout have been created to store, administrate and analyze big data with a variety of formats. By employing big data mining method on E&P data, information can be extracted and knowledge can be discovered from large volumes of unstructured raw data. Currently, the volume of unstructured data is estimated to be more than ~80% of the total big data volume.
The objective of this paper is to demonstrate how to extract information and discover knowledge from huge amount of unstructured text data with lower-density value by Hadoop technology. As an example to illustrate the whole procedure, more than 10,000 public SPE abstracts on the topic of heavy oil fields' development and production are collected, pre-processed and stored in Hadoop distributed file system, from which some key parameters like field name, country, EOR methods, permeability and porosity of heavy oil fields are retrieved by pattern match and statistical models. The extracted values from the Hadoop then cleaned and analyzed. Based on the extracted information, knowledge such as the top ten heavy oil fields according to their occurrences, geographical distribution of heavy oil fields, EOR methods applied in heavy oil fields, EOR history charts, porosity distribution and crossplot of permeability and porosity of heavy oil fields can be easily presented and visualized. In order to validate the effectiveness and accuracy of the knowledge discovering process, the extracted values are compared with those from manual constructed system, illustrating the information retrieving and knowledge mining processes based on Hadoop big data technology are capable of retrieving text and numeric values from unstructured raw data in E&P industry and providing similar statistical trends with the manual system.

Introduction
The oil and gas industry has accumulated huge amount of exploration and production data with various formats. Moreover, the data incremental speed is accelerating due to more data acquired from smart fields, real-time sensors, 2D, 3D and 4D time-lapsed seismic and complicated reservoir modeling and simulations, which have been widely used in E&P industry for a few years. It was reported that the Chevron's internal IT traffic alone exceeded 1.5 terabytes a day in 2011 (Feblowitz, 2012). In addition, the proportion of the unstructured format among the big data is increasing. How to store, analyze and retrieve values and knowledge from big data is a challenge that the oil industry has to confront. When the data volume increases to hundreds of terabytes, the conventional database and data analytics methods usually fail to deal with considering the time and cost they will take.