bluuebunny/crossref_metadata_2025 huggingface dataset:
Smart Magnetic Drilling Fluid With In-Situ Rheological Controllability Using Fe3O4 Nanoparticles
Authors: Vryzas Zisis , Kelessidis Vassilios C. , Bowman Michael B. , Nalbantian Lori , Zaspalis Vassilis , Mahmoud Omar , Nasr-El-Din Hisham A.
Published: February 2017

Engineering a drilling fluid tailored to meet specific downhole and environmental demands with tunable rheological properties can revolutionize the drilling industry. This study investigates magnetically controllable, water-based drilling fluid systems containing custom-made (CM) iron oxide (Fe3O4) magnetic nanoparticles (NP). These could potentially offer in-situ control of the drilling fluid viscosity and yield stress, under the application of an external magnetic field.

CM Fe3O4 NP were synthesized by the co-precipitation method. NP were added to the base fluid at two different concentrations (0.5 and 1.0 wt%). The magnetorheological properties were analyzed via a strain- controlled rheometer equipped with a magnetic field source in parallel-plate geometry giving a range of magnetic flux densities of up to 1 Tesla (T). The rheological behavior of the produced fluids was examined at room temperature of 25°C as a function of volume fraction, shear rate and magnetic field strength.

Transmission electron microscopy (TEM) analysis revealed that the NP was spherical with mean diameter of 6-8 nm, while the X-ray diffraction (XRD) pattern revealed peaks corresponding to pure crystallites of magnetite (Fe3O4) with no impurities. Superconducting quantum interference device (SQUID) analysis proved that the prepared NP displayed superparamagnetic behavior. Magneto- rheological measurements of the nanofluids indicated increase in the yield stress of up to +75% upon exposure to a magnetic field of 0.1 T, while larger changes of up to +609% were observed for higher concentrations of NP with intensities up to 0.7 T. The viscosity of the nanofluids monotonically increased under the presence of a magnetic field at all shear rates. The original rheological profile of the developed fluids was recovered upon removal of the magnetic field with an average deviation of +20% from the initial value, reflecting the disintegration of particle chains because of random movements due to Brownian forces.

Results highlight the potential for the development of multifunctional smart fluids that are greener and economical with tailor-made properties that can reversibly modify their rheological characteristics. Their unique ability to withstand a rapid increase in the viscosity and yield stress in the presence of an external magnetic field could enable drillers to formulate drilling fluid systems with instantaneous responses to continuously changing drilling environment, leading to enhanced well control and contributing to decreased non-productive time and costs.
Implementing Hips System in High Pressure Offshore Gas Producing Facilities
Authors: Alfaraj Ali H.
Published: February 2017

The objective of this paper is to demonstrate the design ingenuity and methodology used to complete a unique HIPS system, which was approved and chosen over the conventional and expensive Full Flare System solution for offshore unmanned high pressure gas production facilities.

Some special design features were implemented to fulfill the Safety Integrity Level (SIL-3) requirements and ensure high level of protection for personnel and facilities. Additionally, this paper will illustrate the challenges for facility operators to preserve the HIPS integrity level throughout the lifetime of the facilities.
Improved Resources and Reserves Estimation with the Combined Use of Scenario-Based Geological Models and Flow-Based Connectivity
Authors: Macé L. , Bogush A.
Published: February 2017

Adequate estimation of resources and reserves is critical for any prospect or field in the oil and gas industry. We propose improving the reliability of this estimation, first, by exploring the range of uncertainties through the use of scenario-based geological models; second, by ranking all generated models based on both static and dynamic responses; and, finally, by selecting few models representative of the uncertainty affecting the reservoir.

In any field, the unknowns largely outnumber the known data, and, typically, some of these known data are biased due to preferential sampling. The classical approach controls the range of uncertainties based on multiple equiprobable realizations generated by using different random paths and by randomly sampling the data range. Our method improves that approach by considering additional realistic geological scenarios, which allows expanding the uncertainty space to sample from. A large number of models is generated as a result.

Performing flow simulation on a large range of models would be computationally expensive. The common industry practice is to select models based on static volumetric measurements only. Our approach not only accounts for static volumes, but also adds computation of the flow-based connectivity using streamline simulation to account for the dynamic behavior of the models. A sensitivity analysis allows preserving only the most influential variables and discarding the negligible ones.

Finally, static and dynamic responses from the remaining models are analyzed to identify scenarios with consistent low, mid, and high values for both responses. This results in the selection of few representative models that provide a greater assurance of recovering the probability distribution than would have been achieved by following common industry practices.

Our methodology involves first enriching the uncertainty space by adding a dimension of geological scenarios. Then, it uses both static and dynamic responses to select a handful of representative models while still allowing adequate estimation of resources and reserves.
Fast Plane-Wave Reverse Time Migration
Authors: Wang Xiongwen , Ji Xu , Liu Hongwei , Luo Yi
Published: February 2017

Plane-wave RTM could provide quick subsurface images by migrating fewer number of plane-wave responses than the number of shot gathers. However, the long delaying time, which is the ignition time difference between the first and last shots, hinders the practical utilization of plane-wave RTM. In one-way wave equation migration, the long delay-time problem is solved easily by phase shifting in frequency domain. However, in RTM, we can only use imaging condition of time domain since wave modeling is usually accomplished by finite difference method in time domain. In this paper, we proposed a novel method to overcome this long delay-time problem of plane-wave RTM algorithm by wrapping plane-wave source function and its corresponding responses periodically, which makes them periodic. According to the linearity of wave equation, the periodic source function and its responses will, respectively, generate periodic source wave field and receiver wave field. Then we use zero-lag cross correlation of the periodic source wave field and receiver wave field as the imaging condition of RTM algorithm to obtain the migration result. Since the source wave field and receiver wave field are both periodic, the imaging condition of time domain gives the same result as that obtained from imaging condition of frequency domain. The key idea of this proposed method can be captured as periodic plane-wave RTM, which extends the source wave fields and receiver wave fields periodically and uses the cross correlation of periodic wave fields to replace the imaging condition of frequency domain. The computation cost for a plane-wave RTM is no more than two times compared to a shot profile RTM, so we name the new method as Fast Plane-wave RTM (FP-RTM). In some application, the number of plane waves to be migrated could be dramatically less than the number of shots and FP-RTM can help us to save significant computational costs. Therefore, FP-RTM can be applied in practice for any-angle of plane waves in any size of velocity models. In addition, FP-RTM provides us plane-wave domain CIGs (PD-CIGs) without any extra computation cost, which makes FP-RTM a practical velocity model building tools. Numerical examples on both synthetic and field data validate the efficiency and correctness of the proposed PP-RTM method.
Uncertainty Assessment in Production Forecast with an Optimal Artificial Neural Network
Authors: Guérillot D. R. , Bruyelle J.
Published: February 2017

Decisions for field development of oil and gas reservoirs are often based on uncertainties assessment on forecast productions and other variables which are highly impacted by the uncertainties on the reservoir characteristics. Using geostatistical models, it would require thousands of flow simulations of several hours each to consider the geological uncertainties. Each of these simulations would require several hours even with current high power computers. To bypass this restriction due to the computation time, one approach consists to replace the simulator by an approximation of it, also called proxy. This paper focuses on the use of Artificial Neural Networks (ANN) proposing an innovative method to build an optimal ANN.
Reservoir Fluids Saturation Diagnostic and Hydrocarbon Targets Identification Workflow
Authors: Faqehy M. , Katamish H. , Al-Towijri A. , Al-Ismael M.
Published: February 2017

Though there are various methods to assess reservoir performance, historical methods seem to focus the assessment on a single or couple of parameters. These include traditional methods to evaluate the reservoir sweep through average oil saturation-thickness maps, remaining oil volume maps, etc. Optimum reservoir management is a challenging and time consuming process since it usually involves analyzing many reservoir properties such as porosity, permeability, thickness, hydrocarbon saturation, fluid properties, relative permeability, net-to-gross ratio and pressures. In this work, we incorporate all these parameters into an automated workflow for reservoir diagnostics; and identification and ranking of optimum hydrocarbon (HC) targets.

The proposed workflow extracts static and dynamic information from reservoir simulation outputs and performs additional post-processing calculations on each grid cell for all time steps. The methodology involves classification of the reservoir simulation grid cells based on fluid saturation, relative permeability, pressure changes and displacing phase fluxes. After that, Produced, Mobile and Immobile oil volumes are calculated for each cell. These volumes are then grouped into six categories, namely, Produced, Highly Contacted, Moderately Contacted, Minimally Contacted, Uncontacted and Immobile Oil. In addition, the workflow incorporates different indicators for determining grid cell quality. These indicators are Reservoir Opportunity Index (ROI) and Simulation Opportunity Index (SOI); and we proposed a new reservoir quality indicator that incorporate changes in pressure over time. Finally, the workflow identifies connected cells with high quality indices and ranks these regions based on size and/or grid cell quality as potential targets for infill drilling.

The presented automated workflow is introduced as an integral part of well placement optimization workflow. It has been tested on several simulation models and successfully identified and ranked un-swept reservoir regions which proved through dynamic simulations to be credible future drilling targets.
CFD Simulation of Pressure Losses in Eccentric Horizontal Wells
Authors: Rushd S. , Shazed A. R. , Faiz T. , Kelessidis V. , Hassan I. G. , Rahman A.
Published: February 2017

In the oil and gas industry, various methods involving Computation Fluid Dynamics (CFD) are used to predict pressure losses while cleaning/operating horizontal drilling facilities with non-Newtonian fluids. Studies on the factors which influence such predictions are important to the successful design, development and operation of wellbores. The effects of hydrodynamic roughness along with eccentricity and rotational speed of a drill pipe are evaluated in the present study. Simulations are conducted using the commercial CFD code, ANSYS CFX 16.2 and the results are validated using experimental data. The current research shows that the pressure losses are strongly dependent on the equivalent roughness of a drilling annulus and, eccentricity and rotational speed of the drill pipe. The knowledge gained from this project is beneficial for designing, operating and troubleshooting drilling facilities.
Hybrid Drill Bit Technology Achieves Breakthrough Performance in Challenging 16-in. Section - Gas Wells in Saudi Arabia
Authors: Ortiz William , Nawaz Khalid , Mukherjee Tushar S. , Mubarak Sami , Shuwiayah Mohammed T , AlHomoad Hussainn , Rojas Pablo , Valbuena Franklin
Published: February 2017

Use of 16-in. vertical sections in onshore deep gas drilling operations in Saudi Arabia presents challenges with a high risk of total drilling fluid loss in interbedded formations. The formations comprise carbonates, limestones, shales, anhydrites, and abrasive sandstone with pyrite inclusions, where the rock hardness is 10 to 15 kpsi unconfined compressive strength (UCS). To minimize the risk of loss, the high bentonite mud system is implemented. The bit consumption averages two tungsten carbide insert (TCI) bits per section, and high average dull grading conditions are observed (IADC 3-4-WT), coupled with low rate of penetration (ROP) performance across the whole section.

Though an in-depth offset well study, including bottom-hole assembly (BHA) analysis, bit dull condition review, evaluating the high bentonite mud effect, and the UCS formation trend, the potential to drill the 16-in. section in a pilot well in a satellite field (using hybrid bit technology) was determined. This paper outlines the development of the best drill bit technical solution, optimizing the use of crushing (TCI inserts) and shearing effect (polycrystalline diamond compact – PDC) cutting structure configuration to drill the section in the minimal time and cost possible.

The results observed in the pilot well confirmed that one hybrid bit had the ability to drill the total section. A 138-percent increase in the rate of penetration (ROP) versus relevant offsets, and a decrease 2.3 operational days and 50% cost per foot reduction. The hybrid bit reached the total depth (TD) section without any operational issues, where the risk of losses was minimized, and a proportionate normal dull condition in the cutting structure was observed. The technical compatibility of the hybrid technology was demonstrated with outstanding performance for the operator.
Experimental Investigation of Effects of Asphaltene Stability on Interfacial Behavior of Live Reservoir Fluid Systems
Authors: Ratnakar Ram R. , Mantilla Cesar A. , Dindoruk Birol
Published: February 2017

Wettability alteration due to asphaltene precipitation in a reservoir affects rock-fluid interactions that have potential impacts on oil production, recovery and flow in the production network. The current predictive wettability models do not consider asphaltene stability and are inherently inaccurate. This study investigates the impact of pressure-depletion induced asphaltene precipitation on interfacial tension (IFT) and contact angle for live-oil systems at reservoir conditions (high-pressure high- temperature); and presents a graphical (quantitative) method for determining asphaltene onset pressure based on interfacial behavior.

Water/oil IFT was measured at reservoir temperature using pendant drop-shape method for a system of live-oils over a range of pressure above and below the asphaltene onset pressure (that was already independently determined via particle size distribution and solid detection system techniques). Contact angle with quartz was also measured in presence of de-ionized water as surrounding medium at the same pressure and temperature conditions. The temperature was controlled with an accuracy of ±0.1°C. Each set of measurements were performed twice to assure the reproducibility of the experiments and methodology.

This work presents the experimental study to quantify the change in interfacial behavior due to asphaltene deposition. The IFT/Contact Angle measurements above and below asphaltene onset pressure show that the interfacial behavior follows the normal trends above asphaltene onset pressure as observed in other water/hydrocarbon systems. However, when pressure was reduced below the asphaltene onset pressure, an evident relatively sharp change in the trend is observed in both IFT and contact angle caused by asphaltene migration to the interface, in a way acting as natural surfactant. As asphaltenes precipitate and deposit in the mineral substrate, the surface turns less water-wet and the contact angle naturally increases to balance the equilibrium forces.

This study sets a non-visual quantitative method to determine asphaltene onset pressure and presents new experimental data on IFT/contact angle of live-oil systems at reservoir conditions. The effects of asphaltene precipitation on interfacial properties are more meaningful than the size of aggregates (visual methods), and can be utilized to assess the potential impacts of wettability alteration due to asphaltene precipitation. For example, only when change in contact angle is large, wettability alteration should be considered in reservoir simulation of depletion processes and waterflooding performace, especially in the context of relative permeability changes.
Operations Efficiency: Improved Well Planning Methodology Based on Invisible Lost Time Smart KPIs
Authors: Al-Ghunaim Sulaiman Marzoug , Sadiq Bashayer Mohammad , Siam Mahmoud , Nassar Islam , Aissa Reda Kaci
Published: February 2017

To optimize drilling operations efficiency and improve well planning methodology, Kuwait Oil Company (KOC) has capitalized on the existence of the real-time drilling decision center (RTDDC) to scrutinize the breakdown of rig operations, detect invisible lost time, and explore measures to address the root causes of this lost time. Advanced data analytics were applied to real-time data to investigate the impact of invisible lost time on drilling operations and use it to benchmark rig performance. This information will now be used for better well planning and improved performance tracking, which would traditionally be hard to achieve using legacy methods such as daily drilling reports and spreadsheet reporting.

The analysis started with combining real-time data with rig daily drilling report data to perform quality control and validate the operational phases. The combined data output was used to calculate rig states within the different operational intervals throughout the lifetime of the well. Consequently, smart key performance indicators (KPIs) were calculated to map previously identified invisible lost time within the different operation phases. Such KPIs were then normalized with respect to a single frame of reference to establish the basis for comparison within a drilling campaign or across a rig fleet. Finally, the normalized KPIs were analyzed to produce a best composite matrix indicating the best performance achieved in the different operation phases to enable more accurate well planning.

This methodology was applied to two wells. From the results, a best performance analysis was conducted based on a fair comparison between the rigs/wells. Operational inefficiencies were accurately captured, and root-cause analysis was effectively categorized in terms of crew performance, flat-time operations, and tool performance. All the results were translated into a framework that enables an enhanced well planning process and an improved performance tracking methodology.

This study exemplifies how to apply advanced data analytics on high-frequency and low-frequency drilling data within a drilling project or across different rigs to identify best potential performance and how to set a benchmark, translate it into goals, and thereby improve the operational efficiency of the project/business and deliver cost savings.
Systematic Approach to Develop a Colloidal Silica Based Gel System for Water Shut-Off
Authors: Huang Jin , Al-Mohsin Ayman , Bataweel Mohammed , Karadkar Prasad , Li Wengang , Shaikh Abrar
Published: February 2017

Undesirable water production can significantly affect the economic life of producing wells. Excess water production results in loss of productivity, corrosion, and scaling. Also, the need for water handling facilities and reinjection of unwanted water can further add to the total cost of the project, which consequently increases the cost of production. In offshore operations, produced water can have an adverse impact on the environment.

The use of a colloidal silica based fluid system was developed for water shutoff application. A systematic experimental study was conducted to evaluate the effect of key parameters on the gelation properties of this system; that is: particle size, pH, temperature, and silica concentration. Also, the effect of different salts, as an activator agent, were tested to initiate in-situ gelation of colloidal silica. The performance of this system was evaluated by conducting static gelation tests as well as high pressure and high temperature viscosity measurements up to 150°C.

Colloidal silica solutions exhibit low viscosity. Proper selection of suitable activators can lead to in-situ gelation and formation of a high viscous gel to block the pore space. The permanent sealing of formation porosity can be achieved by building the viscosity of colloidal silica. The colloidal silica gelation time can be tailored by varying the activator type and concentration to match the field operation requirements. Kinetics of colloidal silica gelation at elevated temperatures showed quicker viscosity buildup. The gelation time can be varied by controlling the initial pH of the system. A stable system and good dispersion was achieved for the colloidal silica solution without using an activator, as confirmed from the Zeta potential results. Increasing the salt concentration and temperature or lowering the pH of the system results in unstable system that triggers the gelation process. The existence of more than one of the above factors (i.e., salt, temperature, and lower pH) results in further reduction in gelation time.

Colloidal silica has a low viscosity and can penetrate deeper into the formation matrix before transforming into a gel. The fluid system presented in this paper was developed to address the needs of water shutoff applications. The environmentally friendly system is comprised of two components; colloidal silica and an activator.
Studying the Cooling Effect of Nitrified Drilling Fluid on Bottom-Hole Assembly While Drilling High-Pressure, High-Temperature Wells
Authors: Alrumaidh Abdulrahman , Abushaqra Ahmed , Elghoneimy Mahmoud , Nabhan Mohamed
Published: February 2017

High-Pressure, High-Temperature is a crucial technical challenge when it comes to drilling very deep wells to find and produce new hydrocarbon reservoirs. This paper studies the cooling effect of using nitrified mud as drilling fluid and compares the results to using conventional mud. This is to prevent the measuring-while-drilling & logging-while-drilling tools from failure due to High-Temperature.

The study is about taking the advantage of the huge reduction in pressure, when nitrogen gets out of the drill bit nozzles, leading to a corresponding significant drop in temperature while drilling. The analysis starts by calculating the pressure losses within the well using fluid mechanics approaches. Since the paper includes different cases, a MATLAB® code is developed to run all cases. Additionally, Autodesk® Inventor® Professional is used to build the model at the last portion of the bottom-hole assembly. Pressure data and thermal boundary conditions are used by COMSOL Multiphysics® to get temperature profile in last portion of the model. Likewise, a cost analysis is done to support that the proposed solution is economically feasible, besides being efficient, and effective.

The simulation outputs are outstanding in terms of reduction in temperature, injection pressure capacity, and cost. The maximum temperature of the pipe outer wall is reduced efficiently when the nitrified mud was used compared to conventional drilling mud. The pressure losses are larger in conventional mud which led to higher power requirements. The drilling operation costs are cheaper than drilling with conventional mud in many comparisons in this paper.

Reaching to an economical, practical, and environmentally friendly suggested solution is an evolutionary approach in facing the HPHT technical challenge. This, indeed, is not only introducing HPHT drilling technology to a whole new level, but also to do it with an integration of technology, reliability, & efficiency.
Open Hole Sand Control Optimization Using Shape Memory Polymer Conformable Screen With Inflow Control Application
Authors: Osunjaye Gbenga , Abdelfattah Tarik
Published: February 2017

This paper covers the novel application of combining shape memory polymer (SMP) conformable screen with inflow control devices (ICD) to provide operational efficiency, wellbore stability and production enhancement in unconsolidated reservoirs openhole completion.

It is not uncommon to have unconsolidated reservoirs with permeability heterogeneity. It becomes more challenging when the formation sands are non-uniform and poorly sorted. The Conventional solution for these type of reservoirs encompasses the use of gravel pack techniques in combination with sand control screens that are equipped with inflow control devices (ICD). However, operational execution is complex and risky especially when openhole isolation packers are added to isolate and compartmentalize the multiple zones. An alternative solution to this challenge is the simplified combination of SMP conformable screen with ICD.

An SMP conformable screen with ICD replaces the burdensome gravel pack operation, provides conformable sand control and maximizes the benefits of the already proven inflow control technology. This integrated application brings efficiency to well site operation by reducing the quantity of downhole accessories, reducing rig site operating hours, and saving overall capital expenditures (CAPEX) or operating expenditures (OPEX). The shape memory polymer provides improved wellbore stability and efficient sand control regardless of the uniformity of formation sands in the different reservoir layers. The combination with ICDs will ensure that production longevity and recovery are optimized by efficiently equalizing inflow profiles.

Technical contributions which include filtration performances, inflow control modeling and completion fluid management are provided to expatiate on the performance analysis of this innovative approach in resolving a critical challenge in horizontal sand control completions.
Optimization of the Curve and Horizontal Sections of ERD Multi-Lateral Wells
Authors: Verma Chandresh , ElKawass Amir A. , Mehrdad Nadem , ElDeeb Tarek , Qazi Muhammad Q. , Galaby Amir , Salaheldin Ahmed , Fakih Abdulqawi Al , Osman Ahmed , Hammoutene Cherif
Published: February 2017

While ERD multi-lateral wells in a large Middle East field are typically drilled in six to seven well bore sections, drilling the 8.5-in curve and the 6.125-in lateral sections represents more than 50 % of the total time spent drilling the well. Challenges while drilling the curve section with a motor include difficulty transferring weight to the bit while sliding and differential sticking in the highly poros zones of gas cap. The laterals, which can extend up to 12,500 ft of reservoir contact, are characterized by medium to hard compacted carbonate formations with high stick and slip tendency. This represents several challenges for drill-bit design engineers given that aggressive cutting structures are preferred to generate good rate of penetration even though this often leads to high bottom-hole assembly vibration. Trajectory control, hole cleaning and long circulating hours also represent significant challenges.

This paper will present details of the engineering analysis performed to optimize both 8.5-in and 6.125-in wellbore sections.

For the curve section, the first step was to change the drill string from 5 in to 4 in which considerably reduced the time taken to change the string prior to drilling the laterals. This change of drill string was accompanied by the use of a rotary steerable system and a PDC bit. This was a combination that had never been implemented since the field discovery in 1968. These changes resulted in performance improvements in excess of 50 %.

For the laterals, the engineering analysis resulted in the need of a completely new bit design. The cutting structure was modified to provide a more aggressive bit to formation interaction, and the gauge contact with the formation was enhanced to maintain the bit and BHA stability. The resulting design broke the field rotary steerable ROP record by 28 %. The bit drilled the highest single run footage in the field (12,698 ft) at the highest ROP (96.93 ft/hr) with a rotary steerable system. This was further complemented by optimizing the drilling practices and well bore cleaning practices allowing the elimination of several conditioning trips within the long laterals which resulted in three days of savings in a three lateral well.

The paper will conclude with a discussion regarding the reduced injury exposure that resulted from changing the drill string earlier within the well and a review of further improvement opportunities.
Determination of True Formation Resistivity from LWD Conventional Resistivity Measurements in a Horizontal Well
Authors: Fang S. , Boesing D. , Wessling S.
Published: February 2017

In a horizontal well, apparent resistivity curves often show varied separations and increased values due to the polarization horn effects near a boundary and other effects such as adjacent beds or anisotropy. The true formation resistivity (Rt) is uncertain and can be mis-interpreted. As a consequence, saturation estimates are uncertain so that the reserves cannot be accurately predicted. A full inversion can be used to derive the true Rt. However, the instability of an inversion due to the lack of measurement variation along the measured depth makes the Rt derivation very challenging.

To determine a true Rt from the logging-while-drilling (LWD) resistivity measurements, a general full inversion is usually time-consuming and needs some inputs on formation model. This paper presents an alternative approach to derive the true Rt without input of any prior information. The alternative approach uses a simple two-layer model for the removal of horn effects and derives a solution at two steps: a) inverting resistivities of the two layers at each distance away from the boundary; b) selecting a solution with specific constraints such as using statistics in a moving window and internally consistent physical constraints to make the solution more reliable. In the first step, neural networks are developed to calculate tool responses and derivatives for the savings of computation time and memory needs.

Synthetic examples show that true Rt can be recovered when the relative dip between a borehole and a layered formation is greater than 85 degrees. The examples show that bed boundaries can be reproduced with sufficient accuracy by our approach, among others to define pay zone intervals. In addition, the resolution of the method was studied with models of different layer thicknesses and is discussed in details in the paper. As an outcome, the derived true Rt reads lower in a resistive thinner layer and reads slightly higher in a conductive thinner layer. A field example from a North Sea oil field demonstrates very promising and robust Rt results from the method.

The inversion is fully automatic and can be used in real time and downhole. Physical constraints that are special to a horizontal well and better strategies make our algorithm robust and very fast.
Why, When and How to Certify?
Authors: Noorloos Jan-Willem
Published: February 2017

The title of my presentation is "Why, when and how to certify?" it is about the sense and nonsense of IEC 61508 certification.

There are many examples in the business of certifications. These can be certifications of systems, devices or conformity of devices. This can have a huge impact on the safety of your process you are safeguarding. Hence it is very important to have an assessment of this certification by independent specialists.

What is the correct standard you should follow to be compliant. Do you follow a global standard or a company engineering standard? If you implement certified products or system, how can you be sure the certification of that system is sufficient enough for you? How can you make sure it will cover all your needs? This can be done by reading these certificates and reports of the systems.
Advanced Spotting Fluids for Remediation of Differentially Stuck Pipe
Authors: Hilfiger Matthew G. , Thaemlitz Carl J. , Moellendick Eric
Published: February 2017

Non-Productive Time (NPT) is one of the major operational and fiscal challenges of the drilling process, collectively responsible for billions of dollars in hidden cost. The greatest segment of NPT is often attributed to stuck pipe events, which may be mechanical or differential in nature. The differentially stuck pipe event is due to a differential pressure gradient, which creates a vacuum-effect upon the pipe, thereby sticking the pipe to the wall of the wellbore. Differentially stuck pipe may be alleviated at relatively low costs through application of a special fluid to help free the pipe. Such fluids useful in the release of drillpipes that are stuck due to differential pressures between the wellbore and the formation are known as spotting fluids. This paper investigates a new spotting fluid that exhibits the advantage of increased effectiveness at releasing stuck pipe in the presence of drilling fluids having high densities. In addition to this increased performance, the fluid can also be combined with a thermal activator to trigger a heat-generating fluid that is capable of exotherms from 100 to 300°F, thereby providing additional performance in treating stuck pipe.
High Performance Brine Viscosifiers for High Temperatures
Authors: Boul Peter J. , Abdulquddos Suhaib , Thaemlitz Carl J.
Published: February 2017

The development of oil and gas reservoirs at increasing depths has increased the demand for high density solids-free reservoir drilling fluids and completion fluids. Many viscosifiers currently used in these fluids are either incompatible with high density brines or require the use of prohibitively expensive brines such as cesium formate to achieve target densities. Therefore, there is substantial commercial benefit to developing a brine viscosifier with a higher temperature tolerance than is currently offered.

A supramolecular viscosifier package has been developed which utilizes non-covalent associations between additives to enhance the thermal resilience of divalent brine fluids. The product performance of a reservoir drilling fluid formulated with the supramolecular viscosifier package is compared with a standard starch-based reservoir drilling fluid. The enhanced performance is highlighted through static aging tests from 300 to 325°F. The fluids are analyzed before and after aging rheologically as well as for suspension stability.

It is clear from the static aging test data that the supramolecular viscosifier out performs the high performance, commercially available starch / xanthan brine viscosifier. The addition of this new polymer blend increases the brine suspendability both before and after aging at high temperature. The rheology of the new additive package also displays better rheological recovery after aging high temperature. This viscosifier package involves synergies of additives within the brine which greatly enhance the thermal stability of the polymers in the brine. The additive package presented retains its viscosity at temperatures up to 325°F and brine densities from 8.4 lb/gal to 19.2 lb/gal.
Well-Based Shale Resource Assessment Using High Resolution Basin and Petroleum Systems Modeling
Authors: Neumaier Martin , Vaslin Antoine , Jacolin Jean-Etienne , Kleine Adrian , Palci Francesco , Fraser Al , Parkin Kate , Wilson Thomas
Published: February 2017

We present a resource assessment from the Upper Bowland Shale, East Midlands, onshore UK, based on coupled petrophysical interpretation and high resolution basin and petroleum systems modeling (BPSM). In most past BPSM studies, the source rock was typically treated as a single formation with bulk properties, and intra-formational heterogeneities within the bulk rock were not taken into account. In the presented study, we have used a high resolution stratigraphy and geochemical data for the definition of intra-shale sweetspots and a quantitative volumetric assessment of oil and gas retained within the shale.

Since a large part of the assumed oil and gas kitchen is relatively flat-lying and the vertical heterogeneity is considered more important than the lateral variations in facies, 1D basin and petroleum systems modeling is performed at a representative well location (Scaftworth B2). Petrophysical logs are computed and calibrated to core and cuttings as applicable and used in the modeling. Integrating a 14 component source rock kinetic, processes such as hydrocarbon generation and adsorption, intra-formational migration and expulsion are simulated at a meter scale.

As a result of the modeling, prospective layers can be identified based on modeled free-phase oil and gas saturation and volume, adsorbed amounts, detailed composition as well as fluid properties (e.g., density, viscosity, and oil GOR and API). Such vertical "sweetspot units" can be used to define the intervals prospective for horizontal drilling and hydraulic fracturing.
The Gas Flow in Micro Fractures of Shale Gas Reservoirs
Authors: Li Yudan , Dong Pingchuan , Li Weiran , Mi Lidong , Yang Shu , Cao Nai , Yi Xiaoyan
Published: February 2017

The object of this paper is calculate the apparent permeability of micro fractures for shale gas reservoirs, and investigate the impacts of stress sensitivity and gas slippage on the permeability of micro fractures at different stage of development. An apparent permeability model of micro fractures has been established based on the fractal theory and microscopic gas flow mechanism. The calculated permeability shows a good agreement with current model results. The sensitivity parameters of the model were quantitatively analyzed. The research results show that: With the development of shale gas, the apparent permeability of micro fractures decreases as the pressure decreases. For stress sensitivity analysis, it shows the apparent permeability decreases by increasing the stress sensitivity factor. In addition, the apparent permeability increases as the slippage coefficient increases. By increasing the maximum aperture, the impact of the stress sensitivity on the apparent permeability increases. The gas slippage is obvious in rough micro fractures.
A Novel and Adaptive Mesh Method for Arbitrary Discrete Fracture Networks DFN Simulations
Authors: Mi Lidong , Jiang Hanqiao , Wang Yuhe , Yan Bicheng
Published: February 2017

The computation mesh is one of the important challenges for the simulation of the discrete fracture networks (DFN). In this work, an efficient mesh method is introduced to tackle this problem.

First, convert the map with complexity fracture network into a numerical image comprised Npix−x × Npix−y pixels. Then, calculate the distance of pixel j (j = 1, …, Npix−x × Npix−y) to all pixels on the ith fracture grid and select the shortest one as the effective distance of pixel j to the ith fracture grid. Next, calculate the effective distance of pixel j to all the fracture grids in the domain and assign the pixel j to the fracture grid with the shortest effective distance. Finally, the volume of coarse matrix block assigned to ith fracture grid is the summation of the volume of all pixels associated with the ith fracture grid. Each coarse matrix block is locally associated with a fracture grid, and it is equivalently discretized to logarithmically refined grid blocks. The orthogonal fractures model is used in our house reservoir simulator (EDFN) to benchmark with CMG, this method provides very consistent results and its accuracy is validated.

The results show that this method is appropriate to be applied in reservoirs with different geometry and arbitrary complex fracture networks.
Innovative PDC Cutter with Elongated Ridge Combines Shear and Crush Action to Improve PDC Bit Performance
Authors: Crane Davon , Zhang Youhe , Douglas Charles , Song Huimin , Gan Xiaoge , Lin Zhijun , Mueller Levi , Skoff Greg , Self Jordan , Krough Bradley
Published: February 2017

Most traditional polycrystalline diamond compact (PDC) cutting elements have a flat polycrystalline diamond table at the end of cylindrically shaped tungsten carbide body. During drilling, the flat diamond table engages the formation and shears the rock layer by layer. A new ridge-shaped diamond cutting element (RDE) has a similar cylindrical tungsten carbide base; however, the diamond table is shaped like a saddle with an elongated ridge running through the center of the diamond table and normal to the cutter axis. The intended cutting portion, the "ridge," engages the formation to fracture and shear the rock at the same time. The design intent was to create a unique cutting element that could combine the crush action of a traditional roller cone insert and the shearing action of a conventional PDC cutter. The new cutting elements were tested in the laboratory against standard flat PDC cutters in a rock-cutting evaluation, and later the new elements were applied to PDC bits and run under real drilling conditions.

The laboratory rock-scrape tests indicated that the new cutting element not only enables the cutter to efficiently shear formation in the same way as a conventional PDC cutter, but also delivers a crushing action similar to a roller cone insert. Preliminary results indicated a reduction of roughly 40% in both cutting force and vertical force on the new ridged diamond element cutters (RDE) over a conventional PDC cutter. Similar findings were also observed during the rock-shearing test on a vertical turret lathe (VTL). Subsequent field tests in multiple areas in North America have produced faster rates of penetration (ROP) in most of the cases. The trials indicate that the new cutting element is efficient at removing rock, and a bit equipped with these elements requires less mechanical specific energy (MSE) during drilling than does a bit with a conventional PDC cutter. In addition, the reduced cutting forces reduces bit torque and thus improves the drilling tools’ life and the bit directional performance. Field data has proven this technology improves drilling performance in terms of ROP and footage over the current PDC bits fitted with traditional flat PDC cutters.
High Density Fluids Customization and Field Application in Khursaniyah Challenging Wells
Authors: Gadalla Ahmed , Pino Rafael , Ezi Peter , Zayer Nadeer , Hudaithi Mohammad , Addagalla Ajay , Kosandar Balraj , Jadhav Prakash , Lawal Ishaq , Imran Aqeel , Hassan Omran
Published: February 2017

Drilling high pressure wells in the Khursaniyah field, Saudi Arabia, has become a challenge due to the high pressure flow from Base Jilh Dolomite formations coupled with loss circulation across the depleted Upper Jilh formations in the 8 3/8" section. The variations in formation pressure across these layers have led to issues like well flowing, losses, and stuck pipe causing considerable nonproductive time.

This paper analyzes the historical problems encountered in the offset wells to identify the critical fluids related issues during drilling of this section: Thermal and pressure stability of fluids additives.Downhole pressure management.Differential sticking or induced losses.Low contamination tolerance to formation fluids influx.Barite sagging.Rheology and free-water management.

This paper also discusses laboratory customization of optimized high-density fluid formulations and field handling guidelines to drill this critical 8 3/8" section and minimize fluid associated risks. The fluid was modeled to have as low a rheology and gelation profile as possible while suspending weight material by understanding the pressure envelope, bore-hole strength, torque, and drag constraints in combination with the fluid rheology and density relationship under the influence of anticipated drilling practices.

The field application on this customized formulation with engineering observance was successful to drill this critical section and the case study for such well is presented in the paper.
Integrating Horizontal Wells in Property Modeling with Kernel Declustering
Authors: Márquez David , Daly Colin , Psaila David , Slettemeas Tormod
Published: February 2017

Horizontal and highly deviated well data that target pay intervals are generally clustered, both in a vertical sense, as they target specific stratigraphic levels, and spatially, as they target reservoir facies or fracture corridors. This means that the well data misrepresent the volume of interest, and the estimated facies and petrophysical property distributions are most likely biased. Nonetheless, to build reliable facies and petrophysical property models for petroleum exploration and production, geostatistical simulation methods require debiased input property distributions that are representative of the entire reservoir of interest. In this paper, we propose a new 3D kernel density based declustering algorithm to mitigate the inherent sampling bias in the input spatial distribution model and efficiently integrate horizontal and highly deviated well data as conditioning data in facies and petrophysical modeling workflows.
Well Integrity Improvement: CCA Preventive Actions in HPHT Offshore Gas Wells in the Arabian Gulf
Authors: Alsubhi A. M. , Abduljabbar A. M. , Agazade K. , Alyami A. S.
Published: February 2017

Well integrity is critical in the petroleum industry, and needs to be maintained throughout the entire well's life cycle. Cement is the main element that provides isolation and protection for the well. To provide an additional protection beside the cement, mechanical isolation packers can be utilized to mitigate the chance of having fluid communication to the surface. Pressure buildup prevention in the casing/casing annulus remains a challenge in High pressure, high temperature (HPHT) offshore gas wells in the Arabian Gulf due to the presence of shallow gas, abnormal pressure formations, and highly fractured loss zones, which makes all cement jobs critical to isolate the well properly.

This paper will discuss the preventive methods put in place to avoid casing-casing annulus (CCA) pressure buildup and sustain well integrity. Cementing strategies and mechanical isolation packers were considered to ensure the presence of competent barriers to prevent fluid bypass to surface. With regard to cement strategies, some methods will be discusses such as use of resin-based cement, which enhance the shear bond and mechanical properties to prevent cement cracking. For the mechanical barriers, conventional staging tools in the 9-5/8-in. production casing will be replaced with high differential pressure liner hanger packers and will be tied and cemented to surface to ensure maximum sustainability. In the future, they will be replaced with HPHT cement staging tools with a packer that is gas-tight to decrease the operating time while having the same reliability. In addition, a lab tested casing joint with elastomers that can swell in any fluid medium are considered to provide isolation in case the casing-cement bond failed at a later stage.

Having a locked potential well due to CCA will increase the operation cost by early workover, in addition to losing the production. Enhancing cement strategies and utilizing mechanical isolation packers will help with preventing pressure build-up in the CCA and maintaining well integrity for the entire well life cycle.