bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advancement of Drilling Hazard Prevention Practices in HPHT Exploration Well – A Case Study in South China Sea
Authors: Guo Shusheng , Gao Yongde , Chen Ming , Shim Yen Han , Wang Chao , Liu Peng , Ding Sai Jung 
Published: October 2020

Abstract
Ledong HPHT gas field in Yinggehai basin of South China Sea. The pore pressure ramp above the over-pressured target sand with narrow safe mud weight window lead to high drilling risk. To improve drilling safety, multiple steps and approaches were taken in real-time monitoring of pore pressure and target zone depth prediction. This paper will describe the different techniques applied in this field to optimize mud weight and accurate prediction of casing shoe position.
Using real-time LWD and mud logging data, pore pressure was calculated and geomechanics model was updated while drilling. The geomechanics model was built and calibrated against drilling and surface data. Intermediate vertical seismic profile (VSP) data was used to correlate with surface seismic profile to predict top of over-pressured reservoir and pore pressure below the bit. Last year, the latest look-ahead technology based on LWD deep electromagnetic measurement was also used to improve the depth prediction accuracy and thin bed detection for high-pressured sands below seismic resolution.
The real-time pore pressure monitoring keeps the mud weight and equivalent circulating density (ECD) within a safe margin to avoid kick and mud loss. The estimated pore pressure coefficient calculated in real-time was within 0.01 SG from actual measurement taken in permeable sandstone intervals. VSP data provides formation top prediction between 50 to 200m ahead of the bit in this area. Predicted depth accuracy varies but generally stay below 10m for the depth range mentioned above. The integration of LWD and intermediate VSP logging has helped to reduce the high depth uncertainty in the predrill model. However, the above technique could not resolve for thin beds or low acoustic impedance contrast formation. This advocate to the use of real-time high-resolution inversion bed boundary detection ranging from 3 to 20m below the bit. Clear prediction of resistivity profile ahead of bit enable proactive decision making while drilling. This additional information helped to improve depth prediction accuracy for casing shoe position and ensure well integrity.
Staged Development of a Marginal Oil Field Under Technical and Market Uncertainty: The Olympus Case
Authors: Fedorov Semyon , Hagspiel Verena , Lerdahl Thomas , Idris Abdulrahman , Ghahfarokhi Ashkan Jahanbani 
Published: October 2020

Abstract
Along with the maturation of main oil exploration and production (E&P) areas in the world, the industry has started to seek for new investment opportunities that have been considered unattractive so far. Among such opportunities might be small oil fields, whose low resource base makes the development marginal in terms of value. Such discoveries remain risky due to lower benefit–cost ratios and geological uncertainty that cannot be reduced so that the downside risk is eliminated. Nevertheless, they still can be attractive investment opportunities if the decision making process captures available operational flexibilities and opportunities to gather additional information allowing to tune the development plan during the course of a project. This can allow to mitigate downside risks associated with the reservoir uncertainty. In order to capture additional flexibilities and account for a possibility to change the course of the project within the investment valuation, the decision maker demands more advanced tools than a static discounted cash flow (DCF) approach, traditionally used in the industry.
In this study, we analyze an opportunity to phase the drilling strategy into two stages as a tool that allows to optimize the field development under technical, cost and market uncertainties. We demonstrate how the decision maker can use additional information generated during the initial stage of the project in order to improve the future development plan by optimizing the decision to drill optional production wells. Using an algorithm based on the least-squares Monte Carlo (LSM) approach, we consider the waiting option to expand the production. We identify additional value created by the staged development strategy for a small offshore oil field, applying the methodology developed in Fedorov et al. (2020) to the synthetic benchmark model Olympus. We also extend the modelling approach of Fedorov et al. (2020) by accounting for cost uncertainty within the LSM algorithm.
The underlying reservoir model allows us to realistically account for the effect of the decision to postpone drilling of the optional wells, on the field production. Our findings in this paper confirm the results of Fedorov et al. (2020), where an analytical modelling approach was used to account for reservoir uncertainty and forecast oil field production. Based on the Olympus case, we show that in case of staged development, the decision maker is able to increase the investment value due to the flexibility to avoid drilling additional wells in case of unfavourable oil price and/or production scenarios. Our conclusion, therefore, is that the staged development has a potential to be applied when the technical uncertainty represents high risk for the project economy.
Operational Efficiency Gains in the Removal of Calcium Sulfate Scale from Electric Submersible Pumps in Offshore Wells
Authors: Reyes-Garcia Enrique , Henkel-Holan Kristina , Campos Katya , Santos Sarai , Villaseñor Omar , Hernandez del Angel Everardo , Barrera David , Avalos David , Manuel Perera Perez Luis , Salazar Munive Angel , Galicia Oscar 
Published: October 2020

Abstract
Removal of wellbore scale from downhole equipment continues to impact well economics due to productivity losses and asset maintenance. The use of first-of-its-class calcium sulfate (CaSO4) scale dissolver in high producing offshore wells equipped with electric submersible pumps (ESP) is presented. The efficiency of the new fluid surpasses the performance of established dissolvers since it does not require long shut-in periods. Anhydrite (CaSO4) scale dissolution and removal can be accomplished with a simple treatment fluid employing a formulation that has been field-proven to restore production and protect downhole equipment in a time-efficient manner.
Mineral anhydrite and wellbore scale samples were tested with the dissolver formulation at 200°F (93.3°C), under static conditions for one hour. Dissolution efficiencies greater than 94% were a requirement. Fluid compatibility with metallic and non-metallic components in the wellbore were assessed at bottom hole static temperature (BHST) conditions for a period of 24 hours. The fluid was deployed from a stimulation vessel at a pumping rate from 1 to 5 bpm. A small volume pill of 5 m3 on average was pumped in at least 20 wells, through the production tubing to the ESP and was allowed to soak for 1 hour. Wells were immediately opened to production after a 1-h soak period.
Minimizing the non-productive time incurred when long soak periods are required has been attained with the use of the new dissolver fluid, leading to greater efficiencies associated with CaSO4-type scale removal. ESP temperature was monitored and reduced by 13°F (7.2°C) after treatment, similar to temperatures before scale build up. After the treatment, the results show a 1.125-fold increase in oil production. The fast-acting formulation exceeds 90% dissolution efficiency within one hour and improves operations by using a fluid that is non-corrosive to downhole materials in a one-stage removal package.
The dissolver formulation provides dissolution of anhydrite at 200°F in ESPs. The fast acting dissolver is delivered as a single fluid package and eliminates the need for separate fluid stages as well as the use of incompatible fluids. Anhydrite scale dissolution and removal can be accomplished with a simple treatment fluid and extend the life of the ESP.
Combined Experimental and Well Log Evaluation of Anisotropic Mechanical Properties of Shales: An Application to Wellbore Stability in Bakken Formation
Authors: Rafieepour Saeed , Zheng Danzhu , Miska Stefan , Ozbayoglu Evren , Takach Nicholas , Yu Mengjiao , Zhang Jianguo 
Published: October 2020

Abstract
Frequently, shales are treated as isotropic formations. However, organic rich shales are anisotropic due to their laminated structure and chemical properties. In this study, shale mechanical properties with respect to different bedding plane orientations was studied. The goal of this study is to evaluate anisotropic mechanical properties of shale by triaxial tests and to predict these properties by well logging data along with a 3-D transversely-isotropic wellbore stability analysis (WBS) in Bakken formation. Shale samples were prepared with bedding plane angles equal to 0, 45, and 90 degrees. Young's modulus, shear modulus, and Poisson's ratio in different directions were measured. Parameters of stiffness tensor were calculated by mechanical properties. The compressive strength of shale samples was measured under different confining pressures: 0, 500, 1000, and 1500 psi. Simple Plane of Weakness was applied to describe shear failure mechanism. Well logging data was used to connect experimental and field data. Next, a three-dimensional numerical wellbore stability model based on finite difference method was used to evaluate stress and deformation alterations due to drilling of vertical to extended reach wellbores in Bakken formation, Williston Basin, North Dakota. Both anisotropic and isotropic conditions were considered and the Mohr- constitutive relations were implemented in the numerical model. Vertical Young's modulus (perpendicular to the bedding plane) found to be smaller than horizontal Young's modulus (parallel to the bedding plane). Shale is a transversely isotropic rock; which isotropy plane is generally the bedding plane. The result of tests for stiffness tensor showed that the shale can be characterized by only five independent stiffness constants. The Simple Plane of Weakness model is suitable to estimate shale anisotropic compressive strength. The P-wave velocity calculated from the stiffness tensor is a used to connect the experimental data and field data. P-wave velocity is increasing as the bedding inclination angle increases. The predicted compressional wave velocity for a 45-degree inclination angle showed a perfect fit with the field logging data. Steps of inverse sonic log data to stiffness parameters were shown by a flow chart. From the WBS model, the effects of anisptropy on stress distribution and wellbore convergence was investigated for two different constitutive models: isotropic model (IM) and transversely isotropic model (TIM). It was found that neglecting shale anisotropy will lead to erroneous prediction of wellbore deformation.
Real-Time Flow Stability Advisor
Authors: Burgos S. R. Andreas , Wollebaek Lars , Elverhaug Vegard , Yang Zongchang , Khaledi Hatef 
Published: October 2020

Abstract
An Aker BP operated oil field in the North Sea has occasionally experienced production flow instabilities in the production lines and risers. The oscillations in multiphase rates are kept within the process capacity limitation at the host installation typically by increasing backpressure (planned flaring is not allowed for on the Norwegian Continental Shelf). The heightened backpressure impacts the production potential of the field. The objective of the project described in this paper has been to develop and implement a new method for real-time production optimization providing an online assessment of slugging severity and suggested actions in order to mitigate slugging and increase production. The developed software tool has been validated using field data.
A statistical approach based on the physical characteristics of the separator has been developed. A combination of transient multiphase flow simulations and data analysis has been employed in order to formulate the risk of exceeding separator constraints as a multidimensional function of the operational conditions. In order to generate a three-dimensional heat map of the risk related to the current state, operational data is continuously gathered from production sensors and transformed into pseudo-steady state values. A heat map is defined by a function where four relevant operational values can be selected. These values are: oil production rate, topside choke setting, gas lift rates and water cut. The software solution is run on a cloud infrastructure with an interactive web user interface.
In a pilot program we have evaluated the ability of the stability advisor to continuously assess the severity of flow instabilities, identify measures to reduce the risk level and minimize associated production losses. The operator has identified valuable operational insights from the tool in a pilot program. The flow instabilities predicted by the model correlate well with observed data from the field. The tool is scalable to other fields with similar flow problems.
Previous papers on slug flow prediction are in general conducted as offline study projects. There has been little success in making real-time scalable solutions available to continuous operations. This paper explains a method on how physical modelling of the flow system combined with statistical methods and access to real-time sensor data can provide a new approach for real-time slug flow prediction. The result demonstrates a scalable solution where output is presented in a format that can be applied by daily operations to act on and provide new and valuable production insights.
Understanding Pitfalls of Non-Reservoir Effects on Pressure Transient-Test Data to Avoid Misleading Interpretation
Authors: Rahman N M , Sarac Sukru , Theuveny Bertrand C 
Published: October 2020

Abstract
The determination of well and reservoir parameters is paramount during exploration, appraisal of new reservoirs, and equally important during the development and production phases of a field. The interpretation of pressure transient-test data is one of the tools to obtain such parameters under dynamic conditions. Often this data is substantially influenced by non-reservoir factors such as gauge drift, adjacent noise due to natural or operational reasons, insufficient gauge resolution and dominant tidal effects. Any of these non-reservoir factors can significantly lead to a misleading interpretation of the formation. Rigorous vigilance against such occurrences is particularly important in designing deep transient well tests. The paper quantifies these effects.
Obtaining strong, unequivocal reservoir responses in the pressure data are imperative in extracting the reservoir and well characteristics. Individual and convoluted effects of noise, drift, resolution, periodic tides have been looked into quantitatively to demonstrate the situations when the reservoir signal is too weak to make any meaningful characterization. Reservoir models have been utilized to develop quantitative criteria to describe the dominance and subsidence of the effects of noise, resolution, drift and periodic tides under different operating conditions. These criteria should guide test design so that the subsequent test can produce meaningful data.
Depending on the amount of disruption caused in the measurements, there are situations when the test objective may not be achieved at all. Failure to create dominant reservoir responses results from insufficient signal-to-noise ratio due to the rate of production and the pressure drawdown. It is a function of formation, fluid properties or mechanical environment. A minimum rate of production for creating the required magnitude of signal-to-noise ratio must be achieved to interpret correctly the reservoir response. The paper provides guidelines to determine the minimum rate and drawdown needed to obtain the presence of deep heterogeneities or boundaries with a reasonable level of certainty. If a test is run with a rate lower than the minimum value, for example, the data will be biased by other hardware or natural factors, unrelated to the reservoir response. Examples are also presented with artifacts of non-reservoir effects to show how misleading characteristics of the reservoir and the well can be deduced with such distorted data.
This study establishes cause-effect relationships due to certain non-reservoir factors so that engineers can select their hardware, choose the methods and timings to mitigate the associated undesirable effects. Such a practical guide to select the most suitable transient test will rightfully fill in its place in the literature. The methodology applies equally to wireline testing operations, deep transient testing, drill-stem testing and production testing.
Sensitivity of Dielectric Properties to Varying Reservoir Properties
Authors: Morte Matthew , Alhafidh Hasan , Hascakir Berna 
Published: October 2020

Abstract
Heterogeneity to some extent is realized in every reservoir. Variable properties, namely fluid saturations and lithology, make it very difficult to accurately estimate the bulk dielectric response of the reservoir. This study isolates and identifies the dependencies of the bulk dielectric response to changing water content, quartz content, limestone content, oil content, and clay content.
A multitude of experiments were run where the identified parameters were systematically isolated and varied to capture both the contribution from the rock matrix and the pore space. Reservoir rock was simulated by mixing the rock matrix components with the fluids to form unconsolidated core samples. The bulk dielectric properties, both the real and imaginary components, were measured for each of the seventy five different samples using a vector network analyzer (VNA) in conjunction with a dielectric probe. Individual experiments were analyzed comparatively and the dielectric responses are presented as a function of each isolated parameter.
Understanding the general dependencies and sensitivity of the dielectric behavior of the reservoir is vital for various aspects of petroleum including electromagnetic heating and well logging. The complex and dynamic downhole environment creates coupled and mutual interactions making estimation of the bulk response very difficult. Isolation of each variable allows for the identification of the governing relationship of each parameter with the dielectric response. In this study, linearity is established for the dielectric response of all investigated parameters. The sensitivity of the complex permittivity is represented as the magnitude of change as a function of variable fluid saturation or lithology. This enables the drivers of dielectric heating to be quantified, namely the increase in complex permittivity with increasing water saturation. The established relationships allow for the estimation of the dielectric response of the reservoir as a result of heterogeneity present. Variable properties that change with position and time are accounted for by understanding the corresponding change in the complex permittivity of the reservoir.
By illuminating the complex permittivity relationship as a function of rock minerology and fluid saturations, a more holistic understanding of absorption mechanics can be achieved. The study offers the unique ability to express the intrinsic relationship experienced under the influence of reservoir properties. The presented relationships also enable the estimation of dielectric properties as a function of reservoir heterogeneity.
Enhancing Resolution of Anisotropic Resistivity Using a Pixel Inversion with Data-Driven Regularization
Authors: Wang Gong Li , Ito Koji , Hong Xiaobo , Salehi Mohammad Taghi , Shi ZhanGuo , Allen David , Rabinovich Michael , Meyer Jeffrey 
Published: October 2020

Abstract
Triaxial induction is a powerful tool to identify thin-bed reservoirs that would be missed with conventional techniques and to improve the accuracy of net pay estimation. On the other hand, it has been noticed that with the standard processing, the resolution of horizontal and vertical resistivities cannot match that of the 2-foot array induction resistivity. Sometimes large apparent anisotropy can be seen in high-resistivity clean sands, which has caused confusion in data interpretation and reserve evaluation.
Researchers have long known that triaxial induction data contains high-frequency information from the formation through the abrupt change and spikes of transverse coupling logs near bed boundaries. In this paper, we present a novel pixel inversion equipped with a revamped cost function and a data-driven regularization scheme to better resolve thin beds by using the high-frequency information that had not been used to its full potential.
The pixel inversion is a variant of the maximum entropy inversion that has proved to be superior for conventional induction data. However, the direct use of the method for triaxial induction data tends to give a slowly varying vertical resistivity log that fails to resolve thin beds as desired. This issue is resolved by means of two adaptive relaxation terms for the smoothness regularization determined by utilizing the data sensitivity to horizontal and vertical resistivities that evolve continuously with the iteration.
In favorable conditions, results on a variety of synthetic models show that a thin bed of less than 1 ft can be detected with deep arrays. In contrast, a bed less than 2 ft can hardly be seen with previous inversions. Results also show that apparent anisotropy ratio is reduced significantly in high-resistivity isotropic cases emulating clean sands. Moreover, the horizontal and vertical resistivities compare favorably with array induction logs in terms of accuracy in the clean sand cases.
Field cases confirm that the pixel inversion is clearly superior to the standard triaxial 1D inversion as far as the vertical (or along-hole) resolution is concerned. The thin beds that can now been seen on horizontal and vertical resistivity logs of the pixel inversion are in good agreement with nuclear logs. In the cases of high-resistivity clean sands, the large apparent anisotropy is largely eliminated with the pixel inversion.