bluuebunny/crossref_metadata_2025 huggingface dataset:
Temperature Transients Affect Reservoir Pressure Estimation During Well Tests - Case Study and Model
Authors: Maizeret Pierre-David , Sidorova Maria , Lipovetsky Tatiana
Published: September 2016

This paper discusses how the pressure measured by the downhole gauges during a drillstem test (DST) is affected not only by hydrostatic, friction or kinetic energy pressure losses, but also by changes in temperature. In oil wells, the bottomhole temperature is decreasing when the pressure is building up after a flow period. The change in temperature is inducing a change in the wellbore fluid density, itself affecting the bottomhole pressure. Most numerical simulators modeling flow in pipes do not take into account this effect, as it is not significant for low to moderate productivity wells. In high productivity wells however, the temperature change can affect drastically the bottomhole pressure measured above the reservoir and the pressure can even decrease at the end of a static period. A mathematical model is presented to compute the pressure drop caused by the nonisothermal effects and can be used to correct the measurements. Field examples are discussed to illustrate this effect and recommendations are made on how new technology can improve pressure measurements during well tests.

In order to measure the effects on the pressure measurements due to the position of the gauges in the DST string, two gauge carriers were run in some well tests in deepwater wells offshore Brazil, one at the level of the tester valve, and one below packer, as deep as possible in the test string. The gauges could transmit data with a wireless telemetry system that allowed the operator to monitor in real-time the pressure changes and the difference between the two sets of gauges.

In high permeability wells, using the uncorrected pressure measured with a gauge 50 to 100 m above the reservoir as is typically the case, can result in a wrong productivity index and at times, in uninterpretable results. Locating pressure gauges as close to the reservoir as possible is crucial in highpermeability reservoirs, to minimize the measurement errors, but also to avoid misinterpretations when an obstruction forms below the tester valve. With the new wireless telemetry systems, it is possible to monitor in realtime gauges mounted below the packer, much closer to the perforations than the standard gauges placed at the level of the tester valve, thus avoiding taking wrong decisions during the test.

A long pressure transient test could be uninterpretable because the gauges are located at the wrong depth. Ideally, the pressure gauges should be placed in front of the perforations but it is not always possible. Therefore, non-isothermal effects on pressure measurements during a well test needs to be clearly understood and taken into account when designing and interpreting well tests, particularly in high productivity reservoirs.
Nanocapsules for Controlled Release of Waterflood Agents for Improved Conformance
Authors: Johnson Leah M. , Norton Chasity A. , Huffman Nicolas D. , Mecham Jeffrey B. , Rothrock Ginger D.
Published: September 2016

The use of polymer gels for water shutoff is a valuable approach to control water production and improve conformance. One polymer gel system, partially hydrolyzed polyacrylamide in combination with Cr(III), shows utility for water shutoff within the near wellbore region. Deeper placement of this polymer gel system within the reservoir is challenging, owing to rapid reaction rates of the gel precursors that prohibits propagation and in-depth placement. The use of a nano-delivery vehicle (i.e., nanocapsule) to contain and shield Cr(III) from the reservoir for a defined time could enable deeper placement and effectiveness of the polymer gel treatment. By protecting the Cr(III) from the polyacrylamide, the gelation is postponed until programmed release of the Cr(III) deeper within the reservoir. Herein, we present feasibility studies that demonstrate the capacity to encapsulate Cr(III) into sub-micron nanocapsules using an inverse miniemulsion technique. Nanocapsules exhibit distinct core-shell morphology, measuring between approximately 200 nm to 500 nm in diameter, depending on the formulation. Laboratory studies successfully demonstrate the encapsulation of Cr(III) within the particles and suggest the potential for delayed release of the Cr(III) cargo. The nanocapsules tolerate simulated reservoir conditions, including high temperatures (50°C) and concentrated salinity. A stable core-shell nanocapsule designed to encapsulate Cr(III) crosslinker via a technically feasible and scalable encapsulation method addresses the requirement for improved waterflood applications and the ability to reach deeper into high permeability zones deep in the reservoir. The technological advancements presented in this paper support a novel approach and hold great potential for controlled delivery of chemistries targeted for the oilfield.
Inferring Interwell Connectivity Using Production Data
Authors: Tian Chuan , Horne Roland N.
Published: September 2016

A key issue of waterflooding is to locate the injectors so as to optimize the production from producers. To resolve the issue in the face of geologically variation, we need to understand how the production is influenced by the injection, in other words, the connectivity between the producers and injectors. It would be very useful for us to build a reservoir scale network based on the connectivity and perform reservoir analysis using such a network representation, without reference to a reservoir simulation model that is obliged to make assumptions about the geology.

The work shown in this paper was organized into three parts. First, a modified Pearson's correlation coefficient was proposed as a new connectivity definition based on the correlation between injection and production histories. Next, machine learning based multiwell testing was applied to learn the correlation between producer rate features and injector pressures, which provided a validation to the connectivity estimated by modified Pearson's correlation coefficient. Last, a connectivity based network was proposed as an abstract reservoir representation. A series of network analyses can be performed on the established network, e.g. reservoir compartmentalization by detecting the strongly connected clusters in the network.

The proposed methodologies were applied on both synthetic and real data sets. The connectivity was shown to be able to capture the injectors' influence on producers, and was verified by comparing with the true reservoir model and results from tracer tests. The target injectors with high influence on production were identified easily as the ones connected to multiple producers, information that can be used to guide a better waterflooding operation.
Optimizing Well Patterns for Various Geologic Facies Models
Authors: Hollander Avi , Qi Kevin , Ershaghi Iraj
Published: September 2016

Control of wasteful water injection is an important objective in optimizing waterfloods. Inefficiencies related to vertical sweep efficiency and some plausible corrective measures have been adequately covered in the literature. The purpose of this paper is to focus on areal sweep efficiency for a single layer assuming that, if needed, sub-zoning steps to minimize thief zone effects from other layers have been previously implemented.

In general, it is essential to minimize bypassing of otherwise recoverable oil and reduce channeling. The presence of geometrically complex connected and disconnected sand bodies creates challenges in maximizing areal sweep efficiency and in designing and managing efficient fluid injection projects. Traditionally, the practice in the industry has been to use simplified well spacing patterns. Many poor waterfloods started this way, using classical geometries without recognizing or honoring the inherent complexities of sand bodies in terms of competitive units with different hydraulic transmissivities.

We present a study highlighting the impact of improper well pattern selections that place injection wells in very high permeability channels. It can result in early elevated water-oil ratios and associated recovery losses because of a limited sweep of low permeability areas. This study is primarily focused on inappropriate placement of uniform well patterns in the presence of reservoir scale channel sands.

For a single layer, our study shows that the early rise in WOR and the deviation from linearity on the semi-log plot of WOR vs. cumulative oil is often indicative of early channeling and successive breakthroughs from tighter intervals. These scenarios can serve as monitoring tools to realign and relocate injectors that may have been unknowingly placed in high permeability channels.
A Fully 3-D, Multi-Phase, Poro-Elasto-Plastic Model for Sand Production
Authors: Wang Haotian , Sharma Mukul M.
Published: September 2016

This paper presents a coupled reservoir-geomechanics model with multi-phase fluid flow for sand production prediction in a weakly consolidated formation. Sanding criteria are based on a combination of tensile and shear failure from Mohr-Coulomb theory and strain-hardening/softening. Once the failure criteria are met, an algorithm for entrainment of the sand based on the calculation of hydrodynamic and other forces is implemented to predict sand erosion. The flow of two immiscible slightly compressible fluids coupled with geomechanics has also been modeled. This allows us to account for relative permeabilities and capillary pressure dependent cohesion and rock residual strength.

The onset of sanding and the sand production rate have both been simulated for open-hole and cased-hole completions under different flow conditions. The model utilizes a dynamic mesh which removes the grid blocks of sand that have failed and meet the erosion criteria. This allows the proper boundary condition to be applied to the sand face as sand is continuously produced. Good agreement with experimental observations is obtained for both the onset of sand production and the rate of sand production when simulations are conducted for open-hole completions. The post-failure elasto-plastic properties of the sand are seen to play an important role in determining the extent of sand production and the shape of the cavity created. In addition, the effect of wellbore pressure drop rate, controlled by choke adjustment, has been studied on the sanding risk. Multi-phase fluid flow effects, including relative permeability and capillary cohesion, are also shown to significantly impact the sand production.
Data Management Requirements for Supporting Digital Energy Initiatives
Authors: Kozman Jess B.
Published: September 2016

As the concepts of "Big Data" and "Predictive Analytics" have made their way along the hype curve (Gartner, 2015), digital energy initiatives have seen many attempts to practically employ these methologies for business gain. In many cases these initiatives have generated less than the expected benefit, or in some cases, failed to answer the business question being addressed. A review of case studies shows that in many cases, the failure was not due to a lack of data, but rather due to fundamental problems with how the data was curated before being applied to the analytic solution. In this paper, we describe and apply industry best practices from the broader data management community which can improve the quality and value of data and information in support of digital energy initiatives
Unconventional Cyclone Gas Lift Completion for Offshore Wells of Cambay Basin: A Smart Completion to Optimize Production and Well Intervention
Authors: Singh Kumar Abhishek , Sarkar Prakhar , Praleya Pranshu , Sai Gogineni Sudarsan
Published: September 2016

The downtime of oil and gas industry dictates the review of Vortex Technology that has been used oil and gas industry for many intentions. An innovative application of this technology is in conjunction with gas lifts that not only organise the three phase flow of oil, gas and water but also optimize production. We can rather say that this technology has the potential to produce unconventional completions. The application of downhole cyclone boosted production many folds. The application of downhole cyclone presented an interesting idea for production optimization in gas lifts and well intervention schemes. The versatile nature of tool dictates its application in CTU and horizontal wells as flow control devices. The downhole cyclone will certainly provide a way forward to cut risks in offshore projects. Therefore, this innovation is certainly a permanent solution to all problems.
Graduate Employability: Key Challenges and Possible Solutions
Authors: Afolayan Tunbosun
Published: September 2016

This paper seeks to identify key challenges in student employability, propose possible and sustainable solutions, introduce and reinforce the importance of ‘knowing self’ and developing ‘transferable skills’ that can help with sustaining their various phases of life

Formal and Informal education are designed to prepare students for life skills, or so we think? Life skills are those skills that are inherent in ensuring that we become responsible, successful and happy individuals. In becoming successful, desirable employability skills are imperative either as a potential employee or entrepreneur, as they help individuals to accomplish their ambitions and live to their full potential.

This paper utilizes a range of information from over 500 respondents in surveys comprising undergraduates, graduates and employed individuals, addressing specific aspects of education and employability, importance of vision and aspiration and others. Experts' opinions are included on survey results and guidance towards proposing suitable solutions and go forward plan while exploring applicable industry recruiting policies.

Incoming results already challenge the concept of employability versus education. It suggests effective integration and highlights dependencies on a range of attributes and developed abilities. Also student awareness of this concept needs to be developed. Hence, it is crucial to bring to the formal education curriculum a strategy that influences these skills development.

This is a culmination of my volunteer experiences as pioneer AAPG AR Young Professional Lead and currently Student Chapter coordinator, and as I step into a role with NAPE as the University Assistance Program chairperson.

It is evident that employability supersedes academic excellence. This project provides valuable information regarding this life skill and attempts to change the mindset and preparedness level of current and future employees/employers while creating more values for industrialization.
Improving the Foamer Selection Procedure for Gas Well Deliquification Application
Authors: Omrani P. Shoeibi , Shukla R. K. , Vercauteren F. , Nennie E.
Published: September 2016

Liquid loading is a common problem in mature gas wells which due to low pressures in the reservoir, liquid phase cannot be lifted to the well head. In gas wells, foamer injection is one of the method to mitigate liquid loading and increase the stable gas production. In this study a modified version of the Bikerman gas sparging setup was designed to evaluate the foamers performance at conditions which are more representative to the ones in fields, such as higher pressures and temperatures. The effect of different parameters on foam performance is studied. The study covers the effect of pressure, temperature, hydrocarbon fraction and foamer agitation velocity on the foam performance. Three tests were performed to quantify the foamer performance; foam buildup, collapse and liquid carryover tests. It is shown that performing evaluation tests at temperatures and hydrocarbon fractions close to the field conditions is inevitable. These results could be used as a basis to improve the current foamer testing methods. The same procedure could be used for surfactants evaluation for Enhanced-oil recovery (EOR) application.
Accelerating the Learning Curve of Next Generation Exploration and Production Workforce through Smart Data and Knowledge Environment
Authors: David Richard Mohan
Published: September 2016

Exploration and Production operating envelop is increasingly getting complex due to sub-surface and production challenges. This requires companies to work in a new operating environment that requires better understanding of the fields, apply new techniques, more agility in business decision, workforce development while improving operations excellence. This requires efficient transformation of the existing practices and workforces into the new operating environment while developing young nationals efficiently and integrating them into the main stream to enable them to lead future operations.

Knowledge Management (KM) is a key component that facilitates this transformation. Though knowledge management is practiced at varied levels in different organizations, the real value can be achieved when knowledge management is seamlessly integrated as part of the routine operations than as a standalone practice.

In this paper, the author discusses the strategy, methodology and use cases in establishing a Collaborative Knowledge Management Foundation that comprise of integrated knowledgebase, KM workflows, Virtual Community of Practices (VCoP), data analytics, collaboration tools, practice to embed knowledge as part of routine operational workflows. VCoPs are the practitioners and expert's hub for key business lines such as Geology, Geophysics, Reservoir, Drilling, Production, Engineering, HSE etc. that facilitates asking questions, share best practices and ideas, support each other efficiently while taking operations decisions in a virtual environment.

Integrated knowledgebase comprises of technical information, decisions and lessons learnt, FAQs, best practices, root-cause, after action reviews across different disciplines are vital to carryout quality planning, design and operations. The KM workflow systematically harvests the knowledge generated, data analytics tool derives insights out of vast volume of data smartly, collaboration tools facilitates smart interactions amongst the business community, the integrated process disseminates knowledge in real time.

The smart knowledge Management Framework facilitates accelerate the learning curves of the emerging talents, transform existing employees to adapt to the changing E&P operating environment towards strategically manage human capital and business transformation. The CoP enables the employees to leverage the collective knowledge and experience of experts in addressing operational challenges and decisions.
Defining Sand Control in an Uncharted Frontier: A Case Study on the Zawtika Field Development in Myanmar
Authors: Grant Graham , Soon Lee Boo , Moses Nicholas , Syifaa'i Arfi , Wallace Cal , Ling Chin Pui , Kikuchi Masato
Published: September 2016

This paper covers the design, execution, and evaluation of the development of the Zawtika field operated by PTTEPI in Myanmar. This includes the study of the reservoir, the selection of completion methodology, the operational challenges, and the performance of the wells.

The Zawtika field development focused on the laminated Plio-Pleistocene reservoirs. The formation comprises a thick sequence of mixed deltaic and shallow marine clastic sediments. A conservative geomechanics study indicated that any reservoirs shallower than 1,700 m true vertical depth (TVD) have high sanding risks and would require an active sand control method.

A batch completion campaign was planned and deployed as a mix of single-zone and stacked dual-zone cased-hole gravel packs (CHGP). A pre-gravel pack acid treatment was tailored for formations with high chlorite content and fines stabilization. A fracture- and gravel-pack service was the primary gravel pack option followed by high-rate water pack (HRWP) depending on water zone proximity or a lack of stress barrier. The sanction that was placed on the country at the startup of this campaign and the limited infrastructure in place led to various challenges during different stages of the campaign.

Over 15 months, 17 wells were completed on three platforms with eight single-zone wells and nine stacked dual-zone wells. This totaled 26 zones where 10 zones were completed with the fracture- and gravel-pack service and 16 zones with HRWP. These jobs were executed on a tender assist for the first platform and on a hydraulic workover unit for the following two platforms. These were among the notable points for the campaign: First CHGP completion in MyanmarAchieved production objective with zero sand productionIntroduced the technique of pumping HRWP in sweep stages for longer intervals in MyanmarIntroduced several fluid systems in Myanmar, including a polymer-free carrier fluid, acid system with diverting agent, fluid loss pill, and clay stabilizerCompleted all wells without downtime related to delivery of products despite the remote location and logistics between multiple countriesCompleted the campaign without any HSE incident and with high operating efficiency
Enhancing the Understanding of Hydraulically Fractured Well Performance in Gas Fields Using Production-History Matching-Case Studies
Authors: Waheed Arshad , Brohi Imad , Rahim Zillur , Omair Ahmed , Pacheco Eduardo
Published: September 2016

In most cases several folds of increase in production after a fracturing treatment is sufficient testimony to the success of the technology and its application in the particular well or field. A cursory look at a post-frac, pressure transient analysis (PTA) will show a stimulated well condition and validate the achievement. For a proper assessment of well potential this approach may be inadequate. The fracture geometry, conductivity, phase flow through the reservoir, reservoir quality, completion practices and pressure behavior under the boundary conditions all contribute to a well's performance. With all these factors considered, the post frac production results may be significantly different from expectations. To encompass this, the preferred methodology would be to benchmark the production from different fractured wells to have a valid comparison and then optimize the methods.

Production-history matching through reservoir simulation is a very effective tool in meeting this challenge. Many subtle features of the reservoir get highlighted in relation to hydraulic fracturing with the dominant component being the fracture itself. This paper examines several successful wells, which unexpectedly fell below the benchmark. The study investigates whether the hydraulic fracture underperformed or the post-frac activities contributed to low well deliverability. Conventional hydraulic fracturing and the newer technique of channel fracturing were part of this analysis.

The post-frac flowback procedures had a significant impact on the productivity of the wells. The presence of condensate brought its own set of challenges. In the long term, it was also interesting to note how the wells recovered after these damages. This paper will provide an insight into this investigation.
Efficient Calculation of Proppant Transport in a Wellbore-Fracture System
Authors: Filippov Andrey , Lu Jianxin , Popa Florentina
Published: September 2016

Analysis of particle-laden fluid flow near an individual perforation (and assuming the fracture is only being fed by this one perforation) showed that the efficiency of particle transport to the fracture (ratio of particle concentration in the fracture and in the wellbore) depends on two dimensionless parameters—the particle stokes number St and parameter Λ, which is the ratio of flow velocity in the wellbore and to the fracture. In a simplified geometry approach, the entrance to the fracture is modelled as a short segment of a circular pipe. Using a detailed 3D CFD model of fluid-particle flow to the fracture (built in a commercial software), the efficiency of particle transport to the fracture was calculated for various combinations of parameters, St and Λ, and tabulated. Using the obtained tables, the proppant delivery efficiency can be very efficiently and accurately calculated by linear interpolation of tabulated data. The calculations presented in the paper have been carried out using water as the fracturing fluid with low proppant concentrations.
Applying Data-Driven Method to Production Decline Analysis and Forecasting
Authors: Jia Xinli , Zhang Feifei
Published: September 2016

Based on historical production data, decline curve analysis (DCA) can be used to monitor production, identify potential problems, and predict well performance, life, and economics. Optimized production history matching is crucial to economic analysis on future operations and decision making. The widely used decline models such as Arps rate-time relations and their variations are based on fitting predefined equations and often times do not work for shale gas and oil wells since most of the production data from these wells exhibit fracture-dominated flow regimes and rarely reach late-time-flow regimes. This approach can mislead the trend of the decline curves and produce poor matches and unreliable production forecasts. A suitable data-driven model combining physical or operating parameters can be greatly beneficial and serve as the basis for decline analysis and prediction.

This paper discusses a method for automatic history matching and decline analysis for shale production data based on machine learning, which can be effectively applied to production surveillance and process automation. This approach is based on time series (TS) analysis and neural networks (NNs), which was then extended to applications with operational parameters available, such as bottom-hole pressure (BHP). The proposed TS and NN models were applied to production data from a Barnett gas well. The historical production data was divided into two parts. The first part of the data is used to train the NN model, and the second part of the data is used to verify the accuracy of the prediction results from each input parameter. The results were analyzed and compared with classic Arps decline models.
An NMR Experimental Study and Model Validation on Capillary Condensation of Hydrocarbons Confined in Shale Gas Condensate Reservoirs
Authors: Wang Haijing , Seltzer Scott J. , Sun Boqin , Wigand Marcus , Horch Carsten , Stallmach Frank , Li Baoyan , Thern Holger , Mezzatesta Alberto , Arro Roberto , Zhang Hao
Published: September 2016

Unlike conventional gas reservoirs, shale gas reservoirs contain organic mesopores that have pore sizes ranging from 2 to 50 nm. These organic pores may cause capillary condensation of confined hydrocarbons due to the non-negligible capillary pressure. A novel phase equilibrium model has been developed to quantify effects of pore size distribution on the phase behavior of confined hydrocarbons, including the occurrence of capillary condensation. However, it remains a challenge to assess the phase behavior of confined hydrocarbons by laboratory experiments. This is because the conventional pressure-volume-temperature (PVT) method measures the phase behavior of a bulk fluid. Here, we employ low- and high-field nuclear magnetic resonance (NMR) techniques to experimentally probe the capillary effect on phase behavior using retrograde condensates in synthetic porous media and shale rock samples.

In low-field NMR experiments, water-wet porous glass and oil-wet polymer-based spherical activated carbon (PBSAC) beads are used as porous media. NMR relaxation times are used to observe the occurrence of capillary condensation for pure and mixed hydrocarbons at room temperature under controlled pressure. High-field NMR is employed to gain further sensitivity and resolution for the phase behavior of a confined methane-butane mixture. NMR spectroscopic signatures of the dew point were identified, enabling the comparison of dew-point pressures of the bulk hydrocarbons and hydrocarbons confined in grinded shale rock. NMR-measured dew point of confined hydrocarbons is ~115 psi higher than that of bulk phase. This pressure shift agrees well with simulation results.

In summary, we present NMR experimental studies and model validation on the capillary condensation effect, showing a shift of dew-point pressures of confined hydrocarbons mixtures in porous media. The agreement between NMR and simulation results validates the novel phase equilibrium model implemented in the newly developed PVT simulation software. The lab measurements and model validation results show that a) oil-wet is one key condition for the occurrence of capillary condensation of confined hydrocarbons; b) the shift of an upper dew-point pressure of hydrocarbons confined in shale rock can be tens of psi to slightly over 100 psi for the retrograde condensate system being used; c) the phase equilibrium model is valid for modeling phase behavior of multi-component hydrocarbons confined in mesopores.
Quantifying and Mitigating the Impact of Asymmetric Induced Hydraulic Fracturing from Horizontal Development Wellbores
Authors: Walser Doug , Siddiqui Shameem
Published: September 2016

Sufficient production and fracture mapping evidence across North America is now available to clearly demonstrate that pairs of delineation and development wells often underperform when there is substantial production time (months or years) between the completions of the two wells. The relative degree of impact on hydrocarbon extraction per acre varies from one play or formation to another, but the phenomena is generally attributed to asymmetric induced fracturing from the development (child) well into the previously partially drained and lower static pressure delineation (parent) well reservoir volume. This paper briefly discusses two solutions that have been employed to minimize the negative fiscal ramifications and improve recovery.

Rigorous 3D unstructured grid reservoir modeling can assist in the quantification of the phenomena; however, options for mitigating the problem for cases where the impact is extreme are typically limited. Synthetic history matching and forward modeling were performed with a grid-based numerical simulator that mimicked a series of asymmetric oblique fractures interacting with a drained reservoir volume, comparing acceleration of reserve recovery and total recovered reserves with a similar case involving symmetric fracturing. Two scenarios for preventing extreme asymmetric fracturing are discussed. These included dramatic shortening of the time between completions, and performing pressure sink mitigation (PSM) via refracturing of the delineation wellbore.

It is shown that the asymmetric fracturing into drained volumes can materially impact reserves and rate of recovery if the acreage position of a given project is substantial. It is demonstrated that the overall stimulated reservoir system permeability, the degree of permeability contrast between reservoir layers, and the degree of asymmetry are all factors that have an impact on the degree to which the long-term time between completions affects recovery of hydrocarbons over and above simple volumetric depletion.

Integration of rigorous 3D reservoir modeling and far-field fracture mapping have established that the negative ramifications of extreme induced fracture asymmetry can be overcome with careful application of drilling and completion (D&C) timing and offset drainage pressure management process.
Providing Accurate ESP Flow Rate Measurement in the Absence of a Test Separator
Authors: Camilleri L. , El Gindy M. , Rusakov A.
Published: September 2016

Where well rates are outside the range of the test separator, operators usually have no choice but to estimate well production using back allocation techniques, which rarely capture the variance in flow rate over time. This was the case of a well in the Thistle field in the UK sector of the North Sea, where high-frequency flow rate was accurately calculated using ESP real-time data, which was instrumental in measuring inflow properties.

The liquid flow-rate calculation was based on the principle that the power absorbed by the pump is equal to that generated by the motor, which provides a linear equation that can be resolved for rate. Water cut (WC) was calculated by measuring the production tubing differential pressure (DP), which provides the average fluid density, which is subsequently converted to a WC. Analytical equations are used throughout the process, ensuring that the physics are respected at all times. This yields greater repeatability and confidence than analogous methods, which are based on correlations and artificial intelligence.

The calculations provided continuous liquid flow-rate and WC trends over the 6-month life of the ESP with a frequency of one calculation per minute with excellent repeatability and resolution. This enabled us to calculate inflow properties such as productivity index (PI) and skin, as well as history matching a reservoir simulation of the drainage area. This was essential to explaining why production dropped from 1500 to 500 B/D over a period of 8 months, which was found to be a lack of pressure support. The fall in production also caused production instability because of severe slugging, which could be remediated by concurrently increasing the tubing head pressure and ESP frequency without changing the drawdown.

In addition to demonstrating the superiority of an analytical virtual flowmeter over correlations or artificial intelligence, the method also shows how the model can be calibrated accurately using an alternative pump reference curve, which is independent of flow rate, as opposed to traditional centrifugal pump curves. Flow-rate independence was indispensable because of the inability to physically measure rates with the existing test separator and was key to delivering accurate results.
New Hybrid Bit Technology Provides Improved Performance in Conventional Intervals
Authors: Wong Alex , denOuden Bruce , Herman J. J. , Isnor Sid , James Phil , Marley Ryan
Published: September 2016

The increasing emergence of hybrid drill bit technologies in recent years is pushing drilling performance to new levels that were previously unattainable by conventional designs. One example of a hybrid bit technology uses a combination of gouging inserts and shearing PDC cutters to increase the overall effectiveness of rock removal. In two and a half years of development, this hybrid gouging / shearing cutting structure has consistently demonstrated a superior average ROP over rollercone bits, as well as improved PDC cutter durability and lower reactive torque compared to traditional PDC bits.

Until recently, the majority of gouging / shearing hybrid bit applications were in surface intervals drilled by six-bladed, 16mm cutter designs. This configuration is adept in enhancing ROP and durability in challenging formations such as gravel and boulders, which normally cause severe impact damage to PDC cutters. However, to push the benefits of the hybrid technology into new territory, significant design changes were made to optimize its performance in the newly targeted applications.

In high ROP intervals, lowering the blade count of the bit has been shown to provide two key benefits: firstly, reduced cutter density increases the depth of cut and work rate for each PDC cutter, thereby increasing the aggressiveness and ROP potential of the design. Secondly, it enables more geometrical freedom for a hydraulic configuration that better suits high ROP and thermal demands. Unlike the six- bladed designs, the hydraulic layout of the reduced blade count designs incorporates separate nozzles dedicated to both the gouging inserts and PDC cutters on each blade. The ability to direct high velocity drilling fluid to both cutting structures promotes more effective cooling and removal of cuttings.

The first instance of the updated hybrid technology was realized with a four-bladed, 12.25 in. diameter design used in a series of runs in Western Canada, drilling competent formations consisting primarily of shale with interbedded sandstones. The hybrid runs in these areas have exceeded the ROP typically achieved by six-bladed PDC bits in offset wells, and in certain cases, recorded average ROPs of over 310 ft/hr while still maintaining superior torque management throughout the entire run. Additionally, the dull conditions of the bits have repeatedly demonstrated reduced PDC cutter impact damage and thermal wear compared to conventional PDC designs. More development is currently underway to further expand lighter-set hybrid designs into more diverse applications.
Multi-Phase Well Control Analysis During Managed Pressure Drilling Operations
Authors: Ma Z. , Vajargah A. Karimi , Ambrus A. , Ashok P. , Chen D. , van Oort E. , May R. , Macpherson J. D. , Becker G. , Curry D. A.
Published: September 2016

The shift towards drilling more complex and challenging wells is continuing in the oil & gas industry. Designing such complex wells with narrow error margins requires advanced well planning tools that account for transient phenomena such as the influx of gas during drilling operations. However, most of the available drilling hydraulics software packages currently do not account for advanced well control modeling options when deploying new drilling techniques such as Managed Pressure Drilling (MPD).

In this paper, we present a novel multi-phase modeling tool that can be deployed in combination with suitable hydraulic models for MPD well control. Its underlying model preserves the transient multi-phase flow behavior of liquid and gas in the well without overly complicating calculation requirements. It is based on coupled conservation equations of mass, momentum, and energy in association with appropriate closure relationships. Several numerical schemes have been utilized to optimize the accuracy and computational efficiency of the software. Furthermore, a user-friendly graphical user interface has been developed for ease of building the simulation cases.

The proposed approach can handle many complexities which occur during a MPD well control incident such as handling multiple influxes from one or several formations, dynamic well control, automated choke control, sudden pump start-up/shut-down, non-Newtonian drilling fluids, arbitrary wellbore path (including directional and horizontal wells), area discontinuity, etc. In addition, this tool can be used to develop and can be used in conjunction with advanced choke control algorithms for MPD. The validity of the software was verified against experimental data from a test well in which a gas kick was induced in a non-Newtonian drilling fluid. The kick was circulated out using the dynamic well control method, which is usually applied during the constant bottom-hole pressure technique of MPD. Parameters such as casing pressure, flow rate in / out of the well, and pit gain were recorded and compared to the simulation results. Excellent agreement was observed between the experimental and simulation results justifying the application of this tool to real-world drilling scenarios.

It will be shown that the new tool can accurately estimate parameters such as maximum casing pressure, annular pressure profile, kick tolerance, flow out, pit gain, gas rising velocity, etc. during MPD operations. Applying advanced numerical schemes makes this tool fast, robust, and efficient. As such, it has the potential to improve well control in general and during MPD operations, thereby enhancing rig safety and reducing non-productive time associated with well control-related trouble events.
Impact of Hydraulic Fracturing Fluid Damage on Shale Gas Well Production Performance
Authors: Eveline Vena F. , Akkutlu I. Yucel , Moridis George J.
Published: September 2016

Much work has been done to accurately simulate shale gas production using horizontal well with hydraulic fractures. In general, these numerical studies have considered single-phase gas transport. However, following the fracturing, fluid-wall interactions can form a damaged zone nearby the fracture characterized by strong capillarity and osmosis effects. To understand the impact of fracturing fluid damage to well production performance, we present a new reservoir multi-phase flow model which includes these mechanisms of formation damage.

In the simulation model, the shale matrix by the fracture is treated as a multi-scale porosity medium including interconnected organic, inorganic slit-shaped, and interlayer clay porosity fields. Prior to fracturing, the matrix holds the gas in the organic and the inorganic pore network, the water in the inorganic and the clay. Imbibition and osmosis mechanisms are included into an existing multi-scale advective-diffusive flow model to describe water-shale interactions following the fracturing. The reservoir flow simulator is fully implicit and based on the integral finite difference method.

The simulation results show that, although fracturing is a rapid process, fluid-wall interactions continuing after fracturing could lead to important imbibition effect during the flowback and production, which allows water to penetrate into the inorganic pore network and displace the gas in-place near the fracture. Osmosis, on the other hand, takes part in the clay interlayer pores due to salt concentration difference between the fracturing fluid and the clay water, because clay in shale matrix acts as a semi-permeable membrane. This leads to pressure build-up in the clay interlayer pores. The pressure build-up, known as clay swelling pressure, exerts additional pressure into the shale matrix which can lead to significant permeability damage during the flowback and production. We measured the propagation speeds of the pressure waves associated with the capillarity and the osmosis.

The new model is used to demonstrate the damage zone formation characteristics and its effect on the flowback dynamics. We also investigated effects of varying salinity contrast between the fracturing fluid and structural water, of varying clay content/type on the shale gas well production performance. Finally, the stress-dependence of the inorganic matrix permeability in the damaged zone is investigated.

The new shale gas reservoir flow simulation model includes additional mechanisms that will allow the practicing engineer to gain insight into a particular case of production in the presence of water-shale interactions. The model can also be implemented into a simulation-based optimization process to design hydraulic-fracturing and flowback procedures for optimal gas production.
A Continued Assessment of the Risk of Migration of Hydrocarbons or Fracturing Fluids into Fresh Water Aquifers in the Piceance, Raton, and San Juan Basins of Colorado
Authors: Stone C. H. , Eustes A. W. , Fleckenstein W. W.
Published: September 2016

The United States National Science Foundation has funded a Sustainability Research Network (SRN) focused on natural gas development in the Rocky Mountain region of the United States. The mission of this SRN is to provide a logical, science- based framework for evaluating the environmental, economic, and social trade-offs between development of natural gas resources and protection of water and air resources and to convey the results of these evaluations to the public in a way that improves the development of policies and regulations governing natural gas and oil development. In a previous paper (Fleckenstein et al 2015), the risk of shallow aquifer contamination was examined for the Denver-Julesburg Basin in Colorado, specifically for the largest field in the basin, the Wattenberg Field. Similar methods were used to assess the risk of wellbore failure leading to fresh water aquafer contamination for the Piceance, Raton, and San Juan Basins in Colorado.

Wellbore construction methods, especially casing and cementing practices for the protection of fresh water aquifers, have been reviewed in these three basins. The wells in the three basins were classified based on coverage of water and hydrocarbon zones as well as age. The assessment confirms that natural gas migration occurs infrequently, but can happen from poorly constructed wellbores. There has been no occurrence of hydraulic fracturing fluid contamination, which was confirmed by our analysis. The significance of these results is to help quantify the risks associated with natural gas development, as related to the contamination of surface aquifers. These results are helping to shape the discussion of the risks of natural gas development and will assist in identifying areas of improved well construction and hydraulic fracturing practices to minimize risk.
The Impact of Geomechanics and Perforations on Hydraulic Fracture Initiation and Complexity in Horizontal Well Completions
Authors: Waters George , Weng Xiaowei
Published: September 2016

As is well known, hydraulically fractured horizontal wells have been extremely successful in the development of low permeability reservoirs throughout the world. The vast majority of these completions employ cased and cemented wellbores drilled approximately in the direction of minimum horizontal stress. Multiple, relatively short perforation clusters are included within each frac stage along the lateral. This efficiently creates many hydraulic fractures propagating orthogonal to the well, but it does not insure that each perf cluster is effectively stimulated.

Many efforts have been made to improve the effectiveness of horizontal completions. This has mainly focused on using lateral measurements to place perforation clusters in rock of similar stress so they are more likely to be successfully stimulated. But this ignores the impact of formation initiation pressure and tectonics on fracture initiation. In addition, the number, dimensions and orientation of the perforations in each cluster can greatly influence the effectiveness of the stimulation at each initiation point.

To address these issues a near-wellbore fracture initiation calculator has been developed that predicts whether a fracture will initiate at a perforation, the minimum initiation pressure, the fracture initiation location and orientation at each perforation, and the injection rate into each perforation. These parameters are a function of the casing size and orientation, the mechanical properties of the rock and cement, the principle effective stresses, and properties of the perforations.

A series of sensitivities have been performed to quantify the impact of injection rate, tectonic setting, stress variation between clusters, and perforation properties on hydraulic fracture creation, orientation and complexity at each perf cluster. The sensitivities demonstrate that fractures may not initiate at many clusters and that within an active cluster some perforations may not be accepting fluid. Incorporating the results from this model enables engineers to design completions that insure all perforation clusters are effectively stimulated and near-well fracture complexity is minimized.

This methodology does not just look at a single perforation, or cluster. Instead, it accounts for the stress variation between multiple perforation clusters within a frac stage, in addition to perforation orientation, dimensions and eccentricity, to predict the likelihood that each perforation cluster will be stimulated. By employing this methodology one can better design a perforating system and optimize perforation placement within a lateral to insure hydraulic fractures are created at all perforation clusters.