bluuebunny/crossref_metadata_2025 huggingface dataset:
Effect of Drilling Muds Wall Slip on Reliable Frictional Pressure Loss Estimations in Offshore Drilling
Authors: Numkam Gilles , Akbari Babak
Published: November 2018

The large variations in temperature and pressure conditions that prevail in deepwater operations have drastic effects on the rheology of drilling fluids used. Under such conditions, rheological properties of oil-based drilling fluids could be detrimentally affected. The main reasons of the aforementioned include; the high sensitivity of its organic phase thermal expansion (compression) coefficient and its large viscosity buildup observed with decreasing temperatures. The consequences on drilling hydraulics may include high surge/swab pressures, poor hole cleaning, and the potential of substantial errors in estimated static and equivalent circulation densities; thereby compromising well integrity.

Rheological models used to fit flow curve data of drilling fluids from commonly used field instruments such as the Fann viscometer, do not capture wall slip phenomenon prevalent in highly concentrated suspensions and emulsions as a result of the no-slip boundary condition in their constitutive equations. This could mean significant errors in the derived drilling hydraulic parameters for fluids displaying wall slip.

In this study, water-based (WBM) and oil-based mud (OBM) samples were prepared using different surfactants and their rheology was characterized using a Fann 35 viscometer and MCR 52 rheometer at temperatures ranging from 10 – 75 °C. This was done to highlight differences in frictional pressure loss estimations between a commonly used field instrument and a higher precision rheometer for muds displaying wall slip behavior. The shearing gaps used in the investigation were 1.17 mm for the Fann 35 viscometer and 0.5 – 2.0 mm for the MCR 52.

Wall slip behavior of the mud samples, as well as discontinuous shear thickening due to jamming of dispersed particles, was found to affect agreement in flow curve measurements between both instruments. For set well depth and environmental conditions, lower frictional pressure losses and cuttings transport efficiency were determined for samples showing high levels of wall slip, particularly at high temperatures. The importance of the outcome is underscored by its importance to the successful and timely completion of the wells, as well as total equipment cost.
Heavily Compartmentalized Reservoir: From Structural Synthesis to Optimum Development Plan
Authors: Salahuddin Andi A. , Al Naqbi Sheikha , Syofyan Syofvas , Yousef Alklih Mohamad , Al Hammadi Khaled E
Published: November 2018

Reservoir compartmentalization, either structural, stratigraphic, or combination, is one of key parameters for accurately characterizing the hydrocarbons distribution in the subsurface and it is an important component for optimizing hydrocarbon recovery. In order to accurately characterize its compartmentalization, structural synthesis has been applied for generating a representative structural configuration of the complex and highly faulted reservoirs of the studied field. This paper demonstrates detail structural synthesis of a Cretaceous Middle-Eastern carbonate reservoir. The studied field exhibits multiple fault blocks with different fluid composition and contacts variation. Log analysis and test results from a number of wells suggested oil rim with significant gas cap and water leg. Exploiting the oil and gas in highly faulted reservoir possesses a major challenge hence the optimum strategy of development plan was created.

Multi-tectonics history of the Arabia in the region is demonstrated by both folding and brittle deformation represented by fault system comprising en echelon faults and joint sets. The most dominant faults are N75W and N45W trending strike slip fault systems. Kinematic analysis, outcrop analogue, and nearby field analogue revealed that the two fault systems have been developed by different tectonic events. The N75W trending faults have been developed as tensile fracture shortly prior to folding when SHmax azimuth was approximately oriented 120o azimuth. The N45W trending faults have been developed at a later stage possible as splay faults by branching from the pre-existing N75W when the SHmax trend was oriented approximately 90°.

The N45W fault arrays show partitioning of displacement between the various splays, with relatively abrupt changes in the displacement at branchlines. Long ‘single faults’ are frequently shown to be segmented into en-echelon arrays. This expression defines a model of fault growth by radial propagation and linkage from a single seed fault as indicated from geometrical and kinematic evidence. Antithetic N45W fault exhibit a downward decrease in displacement towards a tip line near the N75W master fault. This suggests that the N45W faults were initially developed as Riedel shears which then propagated and linked to the pre-existing N75W system as splay faults. This has occurred by a continuous counterclockwise rotation of the causative SHmax stress from Cretaceous to present.

Quantification of the orientations, segmentation, and offset magnitudes provided a foundation for defining their implications for fluid charging, fluid flow, and pressure development within the reservoir. Thus several development scenarios were constructed in order to maintain the pressure and production rate, considering various combinations of horizontal producers and injectors, number of wells, well orientation, horizontal length, and depletion schemes.
Downhole Fluids Characterization in Middle East Unconventional Reservoirs Using NMR 2D Maps
Authors: Vican Kresimir , Jambunathan Venkat , Negm Ehab , Makarychev Gennady , Van Laer Pierre , Zeeshan Baig Muhammad
Published: November 2018

Unconventional and conventional reservoirs do not have much in common. They exhibit different reservoir characteristics; therefore, using conventional reservoir interpretation techniques and workflows in unconventional reservoirs could lead to incorrect conclusions.

In addition to fundamental challenges in evaluating reservoir properties, such as porosity and permeability, it is extremely important to understand reservoir fluid distribution. Downhole fluid typing and calculated volumes, together with porosity and permeability, provide more insight into reservoir potential and sweet spot zones.

Nuclear magnetic resonance (NMR) technology can be used to provide answers to some of the unknowns mentioned previously. Standard NMR measurements provide the lithology-independent porosity and permeability, and then further processing provides more details about partial porosities, volumes, and fluid types occupying the pores. Using two-dimensional maps (2D NMR) helps differentiate the reservoir fluids, especially when distinguishing hydrocarbons (HC) from water. In conventional reservoirs, it is expected to observe faster relaxation for fluid trapped in the smaller pores and longer relaxation for free fluids in the bigger pores. Industry-accepted cutoffs for T1 and T2 measurements help estimate micro, meso, and macro pores. However, for unconventional reservoirs, fluid identification using 2D maps would be different. Fluids in the small pores, such as bitumen, heavy oils, or HCs in source rock reservoir, would have a similar signature on 2D maps.

This paper presents two case studies showing how 2D NMR application was used in an unconventional reservoir for fluid typing processes and HC volumes calculation. It also shows the importance of using this method for more precise planning of further downhole activities. Core data analysis and downhole collected fluid laboratory analysis confirmed the high confidence in NMR fluid typing applications for unconventional reservoirs.
A Novel Holistic Workflow for Field Development Planning in Green Field Environment: A Case Study
Authors: Alkhatib Mohamad , Al Ali Abdulla Ali , Mukhtar Muhammad , Park Sangseok , Ghorayeb Kassem , Nasiri Amir , Shah Abdur Rahman , Ojha Aditya
Published: November 2018

A novel workflow was developed to select the optimal field development plan (FDP) accounting for the associated uncertainties in a green onshore oil field with a limited number of wells and no production data. The FDP was then revisited in view of the performance of wells drilled during the execution phase and updated as needed based on the acquired data .

Comprehensive uncertainty analysis was performed resulting in multiple subsurface realizations. A broad set of development scenarios and options were screened under uncertainty. The viable scenarios were then economically evaluated, resulting in an optimal FDP that is robust to uncertainty and the least risk prone from an economical point of view.

The used workflow was specifically suitable to test many development concepts and explore various options including horizontal well orientation, well pattern concept, pattern acreage and spacing, length of the horizontal sections, and landing of the horizontal sections.

Following an extensive techno-economic analysis of all possible combinations (900 in total), the most robust development concept was selected and analyzed considering the viable development strategies pertaining to plateau rate, drilling schedule, phasing, water injection timing and artificial lift timings.

A phased development approach was adopted enabling acquiring necessary data to mitigate the remaining uncertainty and avoid costly consequences of significant over- or under-capacity. Data acquired in one development phase were assessed and used to update the following planned phases, if necessary.

The study demonstrated that the field development could accommodate a delay in either water injection or artificial lift implementation. Although it was not recommended at this stage to delay either of them, it is noteworthy that the long lead time that may be incurred in the implementation of artificial lift or the risk of lower injectivity would not impact the field performance or ultimate recovery if contained to a few years during initial production. These results further reinforced the robustness of the proposed development plan.

Large subsurface uncertainty combined with an extensive set of possible development scenarios and options required cutting-edge uncertainty analysis and screening workflows to select the optimal FDP. These unique workflows can be readily used in similar green fields to help arrive at the final FDP.
Integrated Petrophysics for Improved Whole-Rock Characterization: A Case Study in Vaca Muerta Formation, Argentina
Authors: Hao Zhang , Nora Alarcon , Julio Arro , Guillermo Crespo , Diego Licitra , Carlos Hernandez
Published: November 2018

The estimation of fluid properties and rock composition is an integral part of formation evaluation. Unconventional resources such as organic-rich shales are geologically complex, due to great variability in rock composition and post-depositional diagenetic processes. In addition, low porosities, such as those usually encountered in unconventional reservoirs, are not well defined from conventional logs due to the large influence of the rock lithological components and high uncertainties of the log measurements. The errors in estimated porosity not only relate to measurement errors, but also to the incomplete knowledge of matrix parameters. Consequently, a reliable method that integrates mineral and fluid petrophysical models is needed to determine the key formation properties in whole-rock characterization.

It is well known that the most important petrophysical parameter obtained from nuclear magnetic resonance (NMR) logging data is a lithology independent porosity. The ill-defined problem in NMR inversion requires proper regularization methods to stabilize the inversion results. The incorporation of conventional logs as penalty constraints in the NMR inversion process can lead to an improved quantification of fluid typing and formation porosity. However, the accuracy of the fluid model is also influenced by the quality of the estimated matrix properties. Geochemical logs based on pulsed neutron technology have been successfully applied to determine elements for identifying lithology and mineralogy. A probabilistic method incorporating geochemical and conventional log measurements can reliably estimate the matrix mineral composition and porosity. However, a good understanding of the fluid properties is also important for accurate results from the mineral model. The fluid and the mineral model complement each other. Consequently the integration of the two models using NMR, geochemical, and conventional logs can provide an improved whole-rock characterization.

In this work, a unified workflow that includes petrophysical relations and rock physics models is proposed. Probabilistic mineralogy inversion using geochemical and conventional logs solves for matrix properties that are used as inputs for the fluid inversion model. Simultaneous inversion using NMR echo trains and conventional logs determines pore fluid composition and formation porosity that are used as fluid parameters to improve the results in the mineral model. By using both inversion models jointly, a set of petrophysical properties that account for all available log measurements can be determined for the whole rock, and the integrated workflow can potentially reduce the uncertainty in the well log interpretation that usually applies a limited set of logs. A field example from an Argentina well in the Vaca Muerta unconventional play is presented and discussed to show the superior interpretation proficiency of the proposed methodology.
Protecting Offshore Pipelines from External Interference: Dropped and Dragged Anchors.
Authors: Bruschi Roberto , Bartolini Lorenzo
Published: November 2018

In congested districts of offshore Oil & Gas Industry, merchant ship traffic, offshore operations or fishing activity may interfere with pipelines in service, which rest exposed on the seabed. Despite the shortcomings of existing technology and knowledge, operators' concerns still emerge after yearly surveys that show new pipe damages from external mechanical interference, not to mention a few ruptures occurred in the last decade due to anchor hooking! Therefore, a question arises: do we know enough about the potential threats to offshore pipelines from external, particularly anchor, interference? The scope of this paper is to outline the rationale of pipeline protection works, both at design stage and in service, with focus on open issues influencing decisions on how and due time to intervene across busy offshore districts. In shallow waters and brown fields, e.g. in the Arabian Gulf and Gulf of Mexico, the consequences, not only economic but also safety wise, of a severe interference, might be relevant. The shallower the water depth and busier the area, the more stringent the safety targets. Sometimes, even having met acceptance criteria, backed by competent engineering modelling and use of state-of-the-art tools, field evidences from early operation may lead to rethink of purpose protection works, to be implemented with minimum impact on field operations. Marine pipeline damage prevention and awareness, from both vessel and field operators, is often a unique way to limit risks and unplanned interruptions.
Acid-Soluble Thixotropic Cement System for Lost Circulation Challenges
Authors: Jadhav Rahul , Patil Sandip
Published: November 2018

Lost circulation is a recurring and costly challenge for the oil and gas industry. Losses range from seepage to total and financial effects, including nonproductive time and remedial operational expenses, which can increase potential risks to the operator. To address this issue, a tunable cement-based lost circulation treatment solution has been developed that is most suitable for partial to total losses, particularly when particulate-based solutions are not effective; the solution is primarily intended to cure losses while drilling. Unlike conventional lost circulation materials (LCMs) that cure losses by mechanical bridging of particles, the thixotropic cement solution's effectiveness arises from its unique chemical composition, which is ideal when flow paths are too large to be plugged by particles.

The new lost circulation treatment solution is thixotropic with a density range of 10 to 15 lbm/gal working in temperatures up to 250°F. The formulation can be mixed with fresh water, seawater, or seawater with up to 14% NaCl. It is designed and tested in accordance with API RP 10B2 (2013) procedures for thickening time (TT), compressive strength, static gel strength, fluid loss, and rheology. During the TT on-off-on test, the formulation builds gel strength when shear is reduced and regains fluidity when shear is reapplied.

The formulation developed rapid static gel strength and an early compressive strength up to 500 psi. The reversible gelation behavior is demonstrated through multiple shear on-off cycles. This solution is operationally convenient to apply because it can be pumped through the bottomhole assembly (BHA), thus reducing trip times. Because of its acid solubility, it can be used across production zones.

The unique properties of gaining rapid gel strength reversibly and a good compressive strength render this solution effective for treating a wide range of lost circulation events during drilling. A wider density window might minimize the potential risk of inflow when treating losses.
Can We Trust the Diversion Pressure as a Decision-Making Tool: Novel Technique Reveals the Truth
Authors: Kabannik Artem , Parkhonyuk Sergey , Korkin Roman , Litvinets Fedor , Dunaeva Anna , Nikolaev Max , Usoltsev Dmitry
Published: November 2018

Traditionally, surface pressure is the primary tool for onsite decision making during well stimulation treatments. In multi-stage wells with multiple injection points (perforation clusters) there are several available methods for diversion efficiency evaluation: differences in pumping pressure caused by pill pumping (also referred to as diversion pressure), instantaneous shut-in pressures (ISIPs) difference, and friction pressure difference. However, these techniques rely on interpretation of friction pressure or net pressure with uncertainties related to indirect measurements of the respective parameters.

A high-frequency pressure monitoring (HFPM) service uses specially designed hardware and proprietary signal processing algorithms to determine the true location of downhole events. Bayesian algorithms are used to calculate probabilities of the interval’s stimulation. Effectiveness and applicability of the method were tested on several wells across major US shale plays. It was demonstrated that the industry standard surface pressure techniques are not always the best approach for the on-site decision making. Even when diversion is not clearly visible, it still may occur downhole. Conversely, a significant diversion pressure response does not necessarily mean adequate diversion. The effective application of the HFPM technique makes engineered decisions more confident during stimulation and diversion operations.
A Novel Hybrid Artificial Intelligence Predictive Multi-Stages Model for Gas Compressors Based on Multi-Factors
Authors: Almadhoun Wael , Alashqar Ameed
Published: November 2018

The objective of this paper is to build a hybrid predictive model for a gas compressor to overcome the operational challenges, optimize maintenance demand and reduce failures risks. This can be achieved by combining a multi layers multi models artificial intelligent techniques to capture all the historical events and improves the model overall accuracy. The time series statistical analytics is commonly used to early predict the potential machine failures or dip in performance in the process industry, by predicting events that occurred in the past and by monitoring the signal trend over time. Recently, other techniques are being used to perform predictive analytics. This includes the use of artificial neural network, the Naïve Bayesian and logistic regressions methods. Statistical time series forecasting methods are categorized in: exponential smoothing methods, autoregressive integrated moving average (ARIMA) methods, regression methods, or recurrent neural network (RNN) methods. Currently, a time series events are typically predicted by statistical methods or by artificial intelligent technique such as artificial neural network (ANN). A Hybrid approach combining more than one technique is applied to overcome the gaps on each method.

The Hybrid model consists of two stages and three models, model 1 and 2 are generalized, and model 3 is detailed. In the first stage, "Model 1" is nonlinear classification model using support vector machine with a Gaussian kernel, it functions as anomaly detection and a machine status classifier. The objective is to build a robust model that can be predictive, deterministic and diagnostic. Therefore, the RNN multivariate signal prediction using long-short term memory (LSTM) is added in parallel as "Model 2". Model 1 and 2 formed the first stage as overall detector. If anomalies are detected, so the algorithm will move to the second stage which consist of individual time series sensor signals. A model for each signal is added as "Model 3" in the second stage as deterministic.

The results of each model show different accuracies that varied from 70% to 96%. But the model overall confidence range is increased. The new hybrid approach provided a better understanding for each event prediction and has minimized the number of misleading alarms.
Real-Time Hydrocarbon Mapping by Time-Lapse Borehole Electric Tomography
Authors: Dell’Aversana Paolo , Servodio Raffaele , Rizzo Enzo , Cappuccio Pasquale , Carniani Carlo
Published: November 2018

Real-time mapping reservoir fluids distribution during hydrocarbon production, or during injection operation, represents a crucial issue and a big challenge at the same time. In this article, we present a new approach based on single-well and cross-well electric measurements. We use electrodes permanently installed on the well casing and electrically insulated from it. We tested our approach through a two-steps workflow. In the first step, we performed forward and inverse modelling on realistic production scenarios. In the second step, we acquired, processed and inverted real data acquired in laboratory, where we tested small-scale scenarios of hydrocarbon production. We acquired and inverted DC (Direct Current) data. Our objective was to reconstruct the variations of the 3D distribution of electric resistivity during the various phases of oil production. The retrieved models reproduced properly the experimental movements of fluids observed in our lab measurements. Finally, modelling and inversion of both synthetic and real data confirm that cross-hole DC method allows mapping reservoir fluid variations even in case of predominant metallic components of the well completion.
Synthesis of Adsorbent Materials by Emulsion Polymerization for Efficient Oil/Water Separation and Hydrocarbons Recovery from Produced Water
Authors: AlGhunaimi Fahd , Alsaeed Duaa , Harith Abdullah , Saleh Tawfik
Published: November 2018

This paper presents a novel/cost-effective hydrophobic material based 9-octadecenoic acid grafted graphene (POG) for oil/water separation. Graphene derived from graphite was modified with 9-octadecenoic acid to obtain 9-octadecenoic acid grafted graphene (OG). Then, emulsion polymerization of styrene was performed on OG to produce polystyrene branches on 9-octadecenoic acid grafted graphene (POG). Three different composites were prepared by varying the amount of 9-octadecenoic acid grafted graphene used as follows: POG25, POG50, and POG75. The three materials were characterized by using N2-physisorption and Fourier transform Infra-red (FTIR). The BET surface area of POG75 was 288 m2/g while POG50 was 225 m2/g and POG25 was 79 m2/g. These materials were evaluated for their oil/water separation efficiency using model mixture. The results showed that the higher the ratio of the 9-octadecenoic acid grafted graphene, the higher the oil removal efficiency of the material and the faster the rate of the adsorption. The materials showed not only high efficiency but also fast uptake of the certain quantity of the oil just within 1 minute. This can be explained by the high hydrophobicity nature of the materials which repel the water as confirmed by the contact angle of approximately 150°. POG75 showed promising results to be a good candidate adsorbent materials for oil removal from produced water where it displays the highest adsorption capability to organic compounds and the highest BET surface area. POG75 was regenerated and its performance was tested again. This material showed a slightly reduced adsorption rate in the first cycle compared to the fresh material. However, the adsorption rate was constant for the next several cycles. POG75 has the potential to be utilized to remove oil contaminants from produced water.
Analysis of Casing Fatigue Failure During Multistage Fracturing Operations
Authors: Liu Zhengchun , Samuel Robello , Gonzales Adolfo , Kang Yongfeng
Published: November 2018

Tubular fatigue failures have been commonly reported in geothermal and heavy oil wells with cyclic steam injection operations. Recently, possible fatigue failures in casing connections during multistage fracturing operations have also been reported in the literature. These occurrences raised the question of whether casing fatigue is a real problem, even for shale plays. This paper describes fatigue modeling and analysis of the casing connections during fracturing operations to provide additional information about this issue.

The varying casing temperature and temperature-dependent casing loads were obtained using numerical simulations of cyclic hydraulic fracturing operations, such as end of cementing → shut-in → plug and perforation → stimulation (stage 1) → shut-in → plug and perforation → stimulation (stage 2) etc. These simulations were accomplished using commercial software, including a thermal flow simulator and stress analyzer. The previously simulated casing loads were then used to calculate localized stress amplitude, strain amplitude, and maximum stress. Finally, the localized strain and stress values were used as input parameters of fatigue models to estimate the lifetime (cycles) of selected casing sections.

The fatigue model was implemented in a computer program and integrated with the thermal flow and stress analysis commercial software, and a field case (shale oil/gas well) was studied with the integrated fatigue simulation. The predicted casing connection fatigue behavior closely correlates with failure field data, and the casing failure location was analyzed and explained in terms of environmental and cyclic stress/strain conditions. The corrosion fatigue appears important for the acidic environment during hydraulic fracturing. The field case study indicates that the fatigue analysis, coupled with numerical thermal-flow analysis and multistring stress analysis, can provide more insight into the failure of casing connections during fracturing operations. Consequently, it is valuable to include fatigue analysis during the wellbore tubular design when multistage fracturing and/or refracturing operations are involved.
Successful Well Test Operations in Complex Reservoir Fluids: Lessons Learned and Best Practices Over 40 Years of Worldwide Operations
Authors: Shumakov Yakov , Hollaender Florian , Theuveny Bertrand
Published: November 2018

Today many exploration, appraisal and development welltest operations are performed in new frontiers. These include extreme environmental conditions and reservoirs bearing complex reservoir fluids, such as heavy oil, or fluids with a high concentration of H2S, CO2, high wax and asphaltenes content, which have rarely been tested in the past. Many failures and operational issues have hindered the interpretability of data, significantly increased the total costs of such well tests or led to severe HSE incidents.

Currently, such operations are often designed and executed on a case-by-case basis, and there are no practical recommendations available that would summarise the well testing experience in such environments to guide the operating companies through the process of efficiently planning welltest operations. Consequently, operations are often planned on a "copy-paste" basis, with potentially disastrous consequences.

This paper describes in detail the challenges associated with safety, flow assurance, safe handling and disposal of produced fluids, and data quality during current welltest operations with complex reservoir fluids or challenging environmental conditions. Complex reservoir fluids, including highly corrosive fluids, introduce unique challenges that need to be addressed at the design stage of the test, each requiring an appropriate design of surface well test spread and DST string, as well as the overall job operation and equipment planning to incorporate "what-if" scenarios. To address these issues, we summarize the best well-testing practices, and for each of the cases outlined illustrate proven welltesting techniques. Examples show that it is nearly impossible to perform the well test and handle complex reservoir fluids at surface using a traditional approach and standard well test equipment. Novel well testing equipment such as new generation welltest separators equipped with Coriolis mass flow meters, new generation burners and others, in combination with recently developed well testing techniques, allowed us to overcome these challenges.

The paper provides practical recommendations, supported by case studies, highlighting the results and lessons learned from successful operations around the worlds in the following well test areas: –Heavy oil testing–Well test operations in high H2S and CO2 environment–Well test operations in reservoir fluids with high wax or Asphaltene content–Deepwater welltest operations with a high risk of hydrate formation–Well test operations with production of foamy oil–Heat management–Viscous fluid management–Contingency planning

Recipes for success are provided to ensure that safe operation can be performed in the challenging environment while keeping the cost in line with the AFEs.
The Impact of Digital Transformation on Cutting Drilling Costs - A Case Study from Oman
Authors: Al-Aufi Yousuf , Malik Al Sulti Al Salt , Arnaout Arghad , Bakhti Sara , Thonhauser Gerhard
Published: November 2018

Digital transformation is a process of applying all digital technologies on current workflows to be able to deliver high quality information at the right time. Improving well delivery time is one of the goals for applying digital transformation inside the company. The drilling performance should be reported on daily basis and all the drifting from predefined targets should be spotted and reported directly. Hence, the drilling crews require more detailed information of their performance, to proactively develop best practices and improve efficiency. Drilling process digitalization is one of the tools that has significant impact to achieve this goal.

This was initially started inside the operating company to implement advanced digitalization technologies to monitoring and improvement drilling operations and to follow up drilling contractors through their digital footprints on the operational performance. The advances in digital technologies and tools provide enable measuring rig activities through real-time rig sensor data and merge it with other information sources. Therefore, a setup of a real-time digitalization tool based on automated rig activities detection technology is established and a measurement and monitoring process was started.

The results of the digitalization process, after an initial evaluation period of approximately 1 month, exposed the savings potential by identifying Invisible Lost Time (ILT). As an example, the result of applying this agile and collaborative process, an improvement of "Weight to Weight" times between 45% and respectively 25% was achieved for two rigs, which reflects an actual saving up to 7% of the total well delivery time. The drilling team achieved measurable savings equal to one average total well duration in the one year of operation.
The Barriers to Smooth Implementation of Diversity as a Workforce Strategy by the Worldwide Oil and Gas Industry
Authors: Emmanuel Joseph Itodo , Emmanuel Gloria Ileigo , Shaapere Timothy Terver , Okomgboeso Samuel Mohammed
Published: November 2018

Advances in technology, business mix, globalization, sluggish oil price and high staff turnover combined with the benefits of diverse workforce has provided the solid basis for the worldwide oil and gas industry to recruit and retain a multicultural workforce made up of the best and most qualified talents to remain competitive and increase their overall effectiveness irrespective of the size of their organizations.

To achieve their bottom line, oil and gas industry need to embrace diversity as a workforce strategy and promote social inclusion and equal opportunities amongst all their workers. Organizations that adopt diversity as a workforce strategy are committed to fair treatment of all regardless of their ethnic origin, race, marital status, disability, colour, social class, trade union membership, nationality, sexual identity, religious beliefs, age and any other discriminatory factors.

In spite of the direct effect of workforce diversity on company performance based on plethora of research, there is a gap in knowledge on the barriers to smooth implementation of diversity as a workforce strategy by the worldwide Oil and Gas Industry.

It is also worrisome that only limited research exist that have evaluated the barriers to effective implementation of diversity as a workforce strategy by the worldwide Oil and Gas Industry. The need to do this constitutes the focus of this study and the findings of this research work will be useful to all stakeholders in the worldwide oil and gas Industry.

This give rise to the purpose of this research work which is to examine the barriers to smooth Implementation of diversity as a workforce strategy by the worldwide oil and gas Industry.

This paper presents the findings on the barriers to smooth implementation of diversity as a workforce strategy by the worldwide oil and gas Industry. This study will be underpinned by relevant literatures and views of some practitioners in the Industry.
New Developement of Cationic Surfactant Formulations for Foam Assisted CO2-EOR in Carbonates Formations
Authors: Gland Nicolas , Chevallier Eloïse , Cuenca Amandine , Batot Guillaume
Published: November 2018

While the global oil demand is set to increase, reducing CO2 emissions is one of the great challenges to be tackled in the coming decades. CO2-EOR has a lot of potential within a CCUS strategy, but the low gas viscosity induces limited sweep efficiency, resulting in poor storage capacity, especially in heterogeneous carbonates formations. CO2-Foams are used to alleviate such drawbacks but special care must be taken with carbonates due to water/surfactants-rock interactions.

A new cationic surfactant formulation is designed through a high throughput screening procedure accounting for solubility at high temperature (80°C), high salinity (160g/L TDS) and high hardness (R+=0.3), increased foam half-life time (at 120bar), reduced adsorption on carbonate powder and finally Ottawa sandpack flood tests (non-reactive transport). Core flooding experiments are performed on Indiana Limestone cores at 130bar and 40°C, prior targeting higher temperature. Dense supercritical CO2 is co-injected along with the surfactant formulation at the core inlet to ensure foam generation inside the rock and apparent CO2 viscosity is measured to assess the foam performance of each formulation.

In this work several surfactant families are tested, among which: (1) anionic surfactants formulation optimized for their performances in sandstones, (2) switchable cationic surfactant (tertiary amine ethoxylate), (3) cationic surfactant, and (4) optimized cationic surfactant formulation. Solubility of the optimized formulation is found to be excellent in all considered brine (up to high salinity and hardness) and at high temperature; low static is obtained on the carbonate minerals (99% calcite) and bulk foam half-life time with supercritical CO2 (40°C/120bar) exceeds 24h. As a first demonstration step, foaming performance of each surfactant formulation is assessed through coreflood tests using intermediate salinity level water. The foam shear-thinning rheological behavior is obtained for velocities representative of near wellbore to in-depth reservoir conditions (from 5ft/day up to 50ft/day). Apparent viscosities are found to be very good, about dozens of centipoises for the lowest velocities. A technical challenges with carbonates lies in fluid/rock reactivity. The increase of divalent ions concentration in brine generally impairs both solubility and foaming ability of surfactant formulations. Here the use of the selected cationic surfactants less sensitive to divalent cations and allows both low adsorption on carbonate rocks and good foaming performance.

A highly promising foaming cationic formulation, compliant with dense CO2 and carbonates, has been designed and thoroughly tested. Results obtained bring new opportunities for the CO2-foam process applied to carbonate formations within an EOR+/CCUS strategy.
Complex Geological Modeling and Quality Assurance Using Unstructured Grids
Authors: Harris Simon , Santoshini Samita , Kashem Sheleem , Viard Thomas , Levannier Arnaud , Benabbou Azeddine
Published: November 2018

Conceptual limitations of existing gridding technologies often lead to undesirable simplifications to the modeling of structurally complex areas, and consequently poor predictions. We present a structural modeling and gridding workflow that limits these modeling compromises.

A volume-based 3D structural model based on fault and horizon surfaces is constructed from input data that has undergone basic quality checking using a variety of techniques. The critical step in the grid creation is the definition of a flattened (‘depositional’) space that deforms the structural model mesh under mechanical constraints. A 3D ‘unstructured’ grid is created in the depositional space, based on ‘cutting’ a property-populated, regular cuboidal grid by the geological discontinuities. The tectonic consistency and better preservation of geodetic distance make the flattened space ideal for a range of property modeling approaches. The forward-deformation of the grid into true geological space tends to preserve the layer-orthogonality of the grid columns and makes the grid more suited to numerical simulation approximations. The final grid is unstructured, high quality and an accurate representation of the input structural model.

The 3D structural model, depositional space transform and grid geometries all provide valuable information on the structural quality of the input data. The stretching and deforming of the orthogonal local axes in the transformation from depositional space to geological space are used to focus further effort on structural model quality assurance (QA). The key step in generating accurate property population and simulation models is the application of QA metrics on the grid geometry; the transformation from depositional space to geological space is used to generate a set of grid properties that highlight potential structural inconsistencies or data quality issues back in the structural model. We present several examples based on a range of structurally complex models, and demonstrate the downstream impact of applying this QA workflow throughout the stages of input data validation, structural model creation and grid creation.
Nanoparticle Stabilized Foam in Harsh Conditions for CO2 EOR
Authors: Eide Øyvind , Føyen Tore , Skjelsvik Eldri , Rognmo Arthur , Fernø Martin
Published: November 2018

This paper investigates CO2-foam stabilized with nanoparticles (NP) as an enhanced oil recovery (EOR) agent in carbonate reservoirs with high temperature and salt content. Under these conditions surfactants, widely used to stabilize foams, becomes unstable and will not generate strong foam. Our objective is to use NP as a stabilizing agent for surfactant based foam through an integrated process where the surfactants generate foam and the NP stabilizes the foam. Aqueous NP solutions (1500 ppm) were injected through porous media at high temperature (120 °C) to evaluate solution stability for a range of brine salinities, pH and resident times. Stable solutions were subsequently co-injected with supercritical CO2 to create foam and increase the apparent viscosity of CO2.

High temperature and salinity are challenging for most surfactants; however it is a common reservoir condition in many carbonate fields. The nanoparticles had a high degree of stability with little precipitation or gelation in the presence of salt content as high as 23 wt.% NaCl as long as the pH was sufficiently low. The stability of the nanoparticles decreased with increased temperature, leading to gelation and injectivity problems in limestone core samples when the injection water had native pH. The problem was less pronounced in sandstone core samples. Nanoparticle stability increased with decreasing pH, and it was possible to achieve steady-state conditions at 120 °C for longer periods of time. CO2 was shown to be a viable stabilizing agent by decreasing the pH of the injection brine and had the added benefit of creating stable foam for enhanced oil recovery. This is particularly important in limestones and carbonates where the pH of the injection water tends to increase as it interacts with the rock. The nanoparticles can be used alone or in combination with surfactants to increase the stability the surfactant generated foam. Surfactant based foam is generally more effective at generating foam, but is less stable at harsh conditions than nanoparticles.
A Novel Multi-Density Dynamic Well Killing Method for Ultra-Deep Wells and the Simulation System
Authors: Zhou Haobo , Sun Mingguang , Niu Xinming , Zhang Jinshuang , Huang Qingfeng
Published: November 2018

Tremendous amounts of oil and gas reservoir are located in ultra-deep formations, such as Shunbei and Shuntuo block in Tarim basin of China, some reservoirs buried deeper than 8000m and which are major exploration areas of SINOPEC. The reservoirs in these areas are full of fractures and cavities which resulting in a series of drilling problems, especially well control safety problems. Therefore, the novel well killing method for ultra-deep wells is very important.

Firstly, in order to reduce the well head pressure (WHP) and balance the formation pressure of ultra-deep well quickly in the killing well process, a novel multi-density dynamic well killing method was established, through which we can use two different killing fluids to kill well and one of them is high density fluid. A comprehensive multi-density killing fluids design method was proposed based on the theoretical analysis, through which the optimal density and volume of different fluids can be obtained easily. And based on the optimal killing fluid parameters, we can not only balance formation pressure quickly but also avoid fracturing formation. Secondly, according to the density contrast of operating fluids, a vacuum (U-Tube effect) will appear at the inlet in the well killing process without dynamic controlling of killing parameters, an integrated U-Tube effect analytical model was established based on the Euler equation. For preventing result into a vacuum phenomenon, a real-time calculation model for killing parameters dynamic adjusting was proposed, in which the multiphase flow model was take into account. Based on this model the real-time stand pipe pressure (SPP), WHP and pump flow rate in different stages of well killing can be obtained easily. Moreover, a series of system software for parameters calculating and simulating of multi-density dynamic killing well was developed, through which we can accurate calculating dynamic parameters and hydraulics.

The proposed model has been applied in ultra-deep well kick control in SINOPEC Northwest oil filed, the simulating result show that the proposed method and software system can give precisely killing parameters design and simulation. Based on the proposed killing well method, we can quickly reduce operating risk and improve the success rate of killing well.

This paper established a novel multi-density dynamic well killing method and the corresponding software, which has been verified with field data and applied in ultra-deep well killing simulating. Through the application, the results show that it can provide technical support to reduce operating risk, and the novel method can improve the success rate of killing well and reduce the drilling cost.
Interpretation Guided Seismic Data Processing of a Large 3D OBC Survey With Simultaneous Shooting: A Case Study from Offshore Abu Dhabi
Authors: Paul Subhrankar , Barajas Carlos Manuel , Gawron Konrad Piotr , Khakimov Oleg , Chatterjee Shraddha , Van Kleef Franciscus , Lecoq Thierry Francis
Published: November 2018

The 3D ocean bottom cable technique allows for acquiring long offset and wide azimuth seismic data. The use of simultaneous sources reduces the acquisition turn-around and HSE exposure. In shallow water environments, simultaneous source data are highly contaminated by surface waves and interference noise. Poor signal to noise ratio (S/N) affects velocity estimation, wavelet stability and overall image quality. This paper demonstrates the successful implementation of different processing and interpretation tools to deal with these challenges.

The initial velocity model was built by extrapolating checkshot corrected sonic velocities along the interpreted key horizons and was subsequently updated to achieve final PSTM velocity. Several passes of noise attenuation were applied. Volumetric curvature analysis was used to monitor and protect fault planes from smearing during the denoising process. Seismic to well ties were continuously monitored to quantify the improvement after each key process was applied and to QC the seismic wavelet through different processing steps.

A key factor to achieve a stable wavelet, at the end of the processing in the shallow water environment offshore Abu Dhabi, was the well driven horizon consistent velocity modeling. High seismic to well synthetic cross-correlation was observed on the final processed data due to the high S/N achieved by several passes of denoising, plus attenuation of strong multiple energy by velocity discrimination. High S/N, pickable geological events, and high resolution fault images are some of the key features of the final stacked image. In pre-stack data, long offset information is available to facilitate AVO and AVAz studies.

Incorporating geological knowledge in the interpretation of horizons and faults and using well data during the course of seismic processing proved to be effective in obtaining a high quality seismic dataset.