bluuebunny/crossref_metadata_2025 huggingface dataset:
Integrated Reservoir-Network Simulation Improves Modeling and Selection of Subsea Boosting Systems for a Deepwater Development
Authors: Seth Gaurav , Valbuena Ernesto , Tam Soong , Da Sie Will , Kumar Hemant , Arias Brian , Price Troy
Published: October 2017

This manuscript presents the results and analyses from an integrated simulation study focused on evaluating and selecting subsea boosting systems. The integrated model uses field management strategies incorporating flow-line routing, field and gathering network constraints and rate allocation. Novel techniques to model subsea networks enable the selection of the boosting system and provide an improved understanding of dynamic conditions encountered in deep water assets. The selected boosting system ensures safe and reliable operations while improving the project's net present value.

Combining responses from reservoir and network systems into an integrated model to evaluate the subsea design requirements is a unique aspect of this study, as this involves novel modeling techniques for boosting systems (pumps). The robust approach ensures consistency of phase behavior across the system components, identification of pump requirements, production optimization and cost reduction. Analysis of these outputs leads to an improved understanding of field operation strategies, equipment selection and sizing, and production forecasts.

The integrated model uses Inflow Performance Relationships (IPR) from reservoir simulation and vertical lift tables to generate Performance Curves (PC), representing well deliverability as a function of Tubing Head Pressure. Comprehensive field management logic uses the PCs to determine optimal well operating rates that satisfy all subsurface and surface constraints. This approach reduces a complex set of constraints into a single operating rate. Well operating rate, is also a function of pump power, pump suction pressure and the fluid phase behavior across the pumps. The integrated model delivers pump performance within its operating envelope and ensures equipment integrity.

Two components of the subsea boosting system, single- and multi-phase pumps, drove performance optimization and selection of system operating conditions. The study incorporated a comprehensive analysis of system constraints through implementation of complex field management rules that accounted for well integrity (completions), performance of network equipment (valves, boosters, pump power requirements), facility capacities, and reservoir deliverability. The integrated study identified the different limiting system constraints throughout the life of the field and improved the overall efficiency of the gathering system. Use of PCs to reduce the constraints into a single operating rate provides tremendous computational performance improvement. Moreover, unlike typical optimization problems, adding more constraints to the system did not affect computational performance significantly.
A New Well Positioning Technique: Access-Independent Ranging Solution for Providing Accurate Well Completion
Authors: Wu Hsu-Hsiang , Hinke Sean , Fan Yijing
Published: October 2017

Magnetic ranging has been used in heavy oil drilling environments, primarily in steam-assisted gravity drainage (SAGD) applications, to eliminate accumulated directional survey errors. SAGD applications require drilling several pairs of horizontal, parallel wells separated by a few meters. More than 2,000 well pairs have been drilled using a ranging technique in which a device generating a magnetic field is deployed in one of the SAGD wells, and a device to measure the magnetic field is deployed in the adjacent SAGD well. This ranging technique has succeeded in accurately controlling the desired separations and directions relatively between the well pairs. However, the cost for access to both wellbores of the well pair has created a high demand for new ranging techniques that require access to only drilling wellbore.

This paper presents a new well positioning method that provides innovative magnetic ranging without access to the wellbore of a target well through the use of surface excitation. The surface excitation is connected to the wellhead of the target well to transmit a current signal along the cased-hole target well; the array gradiometer in the nearby drilling well receives the corresponding magnetic fields and calculates the relative distance and direction between the two wells. The active magnetic, wellbore access-independent, magnetic ranging system provides several advantages over currently available systems, including reduced cost and risk to the operator, improved equipment logistics, elimination of the wireline ranging tool deployment, and reduced personnel to deliver the service, relative to current commercial systems.

Various laboratory tests and field trials based on a discovery tool were conducted exclusively in SAGD wells to validate the proposed concept and to demonstrate the capabilities of providing reliable and accurate ranging data for relative well positioning and well placement applications. The results show excellent agreement on ranging distance and direction measurements between the discovery tool and the industry standard tool. The described logging while drilling (LWD) technique presents an alternative ranging method to existing wireline techniques in SAGD applications. It is also applicable in wellbore intersection and well positioning applications without a target wellbore access.
The Role of Pore Pressure Depletion in Propagation of New Hydraulic Fractures during Refracturing of Horizontal Wells
Authors: Rezaei Ali , Rafiee Mehdi , Siddiqui Fahd , Soliman Mohamed , Bornia Giorgio
Published: October 2017

Refracturing of a horizontal well is a method to restore the productivity of the well in unconventional reservoirs after the expected production decline. Placement of new fractures in a system that has been already depleted poses new challenges for operators. These challenges are due to the altered stress zones resulting from the expected pore volume depletion and corresponding pressure decline. In this study, refracturing propagation issues in a horizontal well are studied.

A fully coupled poroelastic displacement discontinuity model has been developed to study refrac propagation in horizontal wells. Displacement discontinuity is a powerful numerical method for studying hydraulic fracture problems. The model has been verified using available analytical solutions for undrained and drained fracture behaviors. Maximum horizontal stress criterion is used to account for the fracture propagation. Several cases are analyzed using the model. For each set, scenarios that increase the chance of successful refracturing are suggested.

Results of this study show that pore pressure depletion is the key factor in defining extent and severity of stress redistribution zones in the reservoir. The effect of pore pressure is shown to be asymmetric in horizontal wells between two parallel fractures. It is observed that the stress anisotropy between two parallel fractures decreases and it increases between the tips of two fractures. After a certain time, stress anisotropy in the area between two fractures becomes negative which means that the horizontal stresses orientation is reversed in that area. Placing any new fracture in the stress-reversed area causes an unwanted change in direction of fracture propagation and eventually an intersection between new and old fractures. In addition, because of the stress redistribution, new fracture tends to propagate toward the nearest old fracture in a single well. This tendency increases as pore pressure depletion becomes greater, increasing risk of refracturing failure. A sensitivity analysis is performed on spacing and length of the old fractures to investigate the best possible treatment plan in terms of these variables.

Results that are obtained by this study give better understanding about propagation of new fractures as well as old fractures in refracturing process. Moreover, it introduces a very efficient method that aids in the design of refracturing processes in depleted horizontal wells.
Effect of Poroelasticity, Pore Confinement, Molecular-to-Inertial Transport, and Threshold Pressure on Flow of Gas through Hydraulically-Fractured Shale-Gas Reservoirs
Authors: Civan Faruk
Published: October 2017

Transport of gas in nano-permeability shale-gas reservoirs involves complex processes of absorption, adsorption, poroelasticity, alterations of gas properties by pore-confinement, and significant deviations from Darcy-type flow. While recent modifications of Darcy’s law can account for molecular transport in shale depending on the Knudsen conditions, they nevertheless omit the corrections due to convective acceleration and inertial flow occurring through natural fractures and induced fractures formed by hydraulic fracturing and the threshold pressure gradient below which reservoir fluids cannot flow. This paper presents a physically rigorous modeling of shale-gas transport by considering the relevant effects in nanopores and fractures to derive a proper gas storage and transport model. This provides an improved model accounting for complex transport processes in organic and inorganic materials intersected by natural and induced fractures. A non-Darcy equation, comprehensive gas storage model, and quantification of relevant parameters are developed. The model is used to simulate gas transport in laboratory shale-core tests conducted under near-real shale-gas reservoir conditions.
Effect of Confinement on Bubble Point Temperature Shift of Hydrocarbon Mixtures: Experimental Investigation Using Nanofluidic Devices
Authors: Alfi Mehrdad , Nasrabadi Hadi , Banerjee Debjyoti
Published: October 2017

A great amount of hydrocarbon pore volume in unconventional petroleum reservoirs is distributed in pores of very small sizes, ranging from a nanometer to 100 nm pores. In such a small pore size, fluid-rock interactions play a dominant role in determining the phase behavior of hydrocarbons, which can lead to significant deviations in phase behavior, and significant errors in reserves estimation and reservoir simulations regularly performed by commercial simulators. In our research, we investigated the fluid phase behavior of hydrocarbon liquids when confined in nano-sized pores. For this end, we employed state of the art technology called lab-on-a-chip technology to mimic shale rock media in a nanofluidic chip. This novel method gives us the ability to directly visualize hydrocarbon liquid inside nano-sized pores and measure fluid properties. Using nanofluidic chips as a nano-scale PVT cell, we have been able to measure the bubble point temperature and its changes under confinement effect in pore sizes of 10 nm, 50 nm and 100 nm. We have performed experiments for binary mixtures of hydrocarbons (pentane/hexane, pentane/heptane) and a ternary hydrocarbon mixture (pentane/hexane/heptane).

The results of our study shows that at 10 nm pores, the confinement has a significate effect on alteration of hydrocarbon phase behavior by increasing the bubble point temperature. On the other hand, the quantity of such effects on bubble point temperature is almost negligible at pore sizes of 50 nm and 100 nm. As a conclusion, confinement effect is significant in form of molecule-pore interactions, which leads to a significant effect on bubble point temperature. Furthermore, molecule–wall interactions that lead to alteration of phase behavior of hydrocarbons do not have a significant influence on the common molecule–molecule interactions at pore size of 50 nm and 100 nm, leading to bubble point temperatures close to those of bulk media.
Modeling of the Interaction Between Asphaltene and Water for Multiphase Reservoir Fluids by Use of Cubic-Plus-Association Equation of State
Authors: Jia Wenlong , Okuno Ryosuke
Published: October 2017

Asphaltene is a group of complex compounds commonly present in reservoir fluids, especially in viscous oils. It is conceivable that asphaltene strongly interacts with water through hydrogen bonding, affecting phase behavior of water/oil mixtures with/without forming an asphaltene-rich phase. Modeling of these polar components in reservoir fluids is challenging with cubic equations of state (EOS) due to the size-symmetricity and self- and cross-associations of asphaltene and water.

In this research, the cubic-plus-association (CPA) EOS is applied to represent complex multiphase behavior associated with water and asphaltene. Asphaltene-containing heavy oils are characterized by the CPA EOS with four pseudo components (asphaltene and the other three pseudo components) based on their experimental data. Asphaltene is the only associating component in the oil models. Then, multiphase behavior data for mixtures of water with each of these oils are represented by the CPA EOS. Calculated phase behavior by the CPA EOS models is compared with experimental data and also with the Peng-Robinson EOS for several cases. This paper also presents a new correlation for binary interaction parameters (BIPs) for water with n-alkanes for the CPA EOS on the basis of experimental data for three-phase coexistence for water/n-alkane binaries (Brunner 1990).

In case studies, the CPA EOS is shown to be able to represent multiphase behavior for water/oil mixtures with up to four equilibrium phases: asphaltene-rich, solvent-rich, aqueous, and vapor phases. In particular, the CPA EOS is successfully applied to bitumen/water mixtures, involving asphaltene-water emulsion, water solubility in bitumen, and their continuous transition with varying temperature. Furthermore, results show that the CPA EOS can reasonably represent the multiphase data measured for a n-butane/bitumen/water mixture that were not accurately correlated with the PR EOS in the literature. Modeling an asphaltene-rich phase in several cases is possible only with consideration of the water-asphaltene interaction, which is worth the additional complexities of the CPA EOS in comparison with the PR EOS.
Estimating Ultra Low Permeability at Multiple Locations Using Simultaneous Impulse Tests: A Fit for Purpose Pressure Transient Solution and Its Field Application
Authors: Zhan Lang , Fair Phil S. , Dombrowski Robert J. , Quint Edwin N. , Cao Richard
Published: October 2017

One of the major challenges in efficiently developing ultra-tight or shale reservoirs is to obtain reliable permeability distribution. Ultra low permeability and very strong stratification or heterogeneity in the formations require conducting long duration tests at multiple locations in a well to attain a complete reservoir characterization. Because of these characteristics, existing tools or methods that work well for conventional reservoirs are usually not applicable for ultra-low permeability formations. An innovative reservoir monitoring/testing tool system was developed and successfully applied to fields in both USA and Canada (Zhan et al. 2016). The tool created multiple pressure pulses at targeted locations simultaneously along monitoring wells for zonal in-situ permeability estimations as well as long term formation pressure monitoring. Existing pressure transient solutions are incapable of handling the measured data when potential zonal pressure interferences appear. A fit-for-purpose pressure solution, the associated optimization algorithm and suitable data interpretation workflow, was developed to analyze the data whenever commercial software tools are inadequate. The new solution fully considers all impulses as well as potential interferences among them through suitable superposition. In-situ permeability values at all involved zones can be obtained through a combination of individual impulse analyses and systematic multiple impulse inversions.

The new pressure transient solution was verified through comprehensive synthetic cases using numerical simulations. The results show that the solution can handle either fully or partially open wellbore in each zone and properly considers cross-flow between formation layers. In addition, it allows any number of perforated intervals and formation layers where the number of the perforated intervals is less than that of the formation layers. Field examples demonstrates applicability of the new solution and the data interpretation workflow to formation permeability down to tens of Nano-Darcy. The detailed zonal permeability distribution in the formation enables a more representative reservoir model for better hydraulic fracturing design and field development optimization.
Experimental Verification of Changing Bubble Points of Oils in Shales: Effect of Preferential Absorption by Kerogen and Confinement of Fluids
Authors: Pathak Manas , Velasco Raul , Panja Palash , Deo Milind D.
Published: October 2017

The economic and increased production of oil and gas from shale plays in the United States plays a key role in the country's energy independence. There are many factors that govern increased production of oil and gas from shales. One such factor is the assessment of the correct in-situ oil bubble point in shales which is critical in the optimization of hydrocarbon production. Shales are nano porous organic-rich sedimentary rocks that act as both source and reservoir oil and gas systems. The effect of nano pore confinement on the bubble point of oil in shales has been widely studied and documented in the SPE papers. However, the effect of organic matter presence on the bubble point of oil in shales has not been explored. The researchers at the University of Utah has studied both the effects by performing molecular scale simulations, thermodynamic modeling and experiments using analytical tools. This paper discusses the experimental effect of the presence of nano pores and organic matter on the bubble points of oil in shales.

Experiments are performed on isolated type I kerogen with multiple pure component hydrocarbons and crude oil. Differential Scanning Calorimeter (DSC) was used to perform experiments on mixture of kerogen and hydrocarbons. The DSC data shows that the presence of kerogen and presence of nano pores changes the bubble point temperature. There is a suppression in the bubble point temperature of oil in presence of type I kerogen. This suppression is larger in the boiling point temperatures of pure polar and non-polar components (nitrobenzene, heptane) when in presence of kerogen. The paper discusses the possible reasons for the suppression seen due to the two effects and the reason behind the difference in the suppression seen with changing hydrocarbon liquid (polar vs non-polar vs H-bonding). Any multicomponent mixture of hydrocarbons such as oil will be split into an absorbed (in kerogen) phase and a free phase as a result of preferential absorption of preferred components by kerogen. Changes in the composition of oil in kerogen due to such a phase split will change the bubble point of oil in kerogen. This is known as effect of presence of kerogen. The free phase stays under the confinement in the nano poresof kerogen. The bubble points of confined oils are different than the bubble point of bulk oil due to dominant pore-wall and fluid interaction under nano-confinement.
Real Time Downhole Measurements During Deepwater Fracpack Completions in the Gulf of Mexico
Authors: Hawthorn Andy , Aguilar Sergio
Published: October 2017

As the industry looks to develop wells in more technically and operationally demanding environments, the potential challenges increase. The result is that the need to more fully understand what is happening downhole throughout the well construction process is critical. An effective telemetry system that can reliably provide valuable data from downhole to the surface is, therefore, an important tool during well construction activities. Current data telemetry platforms such as mud pulse, wired drillpipe (WDP) or electromagnetic (EM) systems are subject to significant limitations. These could be operating restrictions, relatively low bandwidth and complicated installation with associated high implementation costs, all of which lead to increased barriers to deployment. This paper discusses a novel acoustic technology that allows downhole data transmission to the surface real time in a wireless manner. The results of two field cases where this technology was deployed are presented. The paper also aims to quantify the advantages of downhole data and its positive impact on decision making in these well operations.
Characterizing Pores and Pore-Scale Flow Properties in Middle Bakken Cores
Authors: Karimi Somayeh , Kazemi Hossein
Published: October 2017

To understand the flow and transport mechanisms in shale reservoirs, in 2014 we needed reliable core-measured data that were not available to us. Thus, we conducted a series of diverse experiments to characterize pores and determine the flow properties of twelve Middle Bakken cores as representatives for Unconventional low-permeability reservoirs. The experiments included centrifuge, mercury intrusion capillary pressure (MICP), nitrogen adsorption, nuclear magnetic resonance (NMR), and resistivity. From the centrifuge measurements, we determined the mobile fluid saturation range for water-displacing-oil and gas- displacing-oil in addition to irreducible fluid saturations. From MICP, nitrogen adsorption, and NMR, we determined pore-size distribution. Finally, from resistivity measurements we determined tortuosity. In addition to flow characterization, these data provided key parameters that shed light on the mechanisms involved in primary production and enhanced oil recovery technique.

The cores were in three conditions: clean, preserved, and un-cleaned; the hydrocarbon included Bakken dead oil and decane; and the brine included Bakken produced water and synthetic brine. After saturating the cores with brine or oil, a set of drainage and imbibition experiments was performed. NMR measurements were conducted before and after each saturation-desaturation step. After cleaning, pore size distribution was determined for four cores using MICP and nitrogen adsorption tests. Finally, resistivity was measured for five of the brine-saturated cores.

The most significant results include: 1. Centrifuge capillary pressure in Bakken cores was on the order of hundreds of psi—both in positive and negative range. 2. Mobile oil saturation range for water-displacing-oil was very narrow (around12 % PV) and much wider (around 40 % PV) for gas-displacing-oil. 3. In Bakken cores, oil production by spontaneous imbibition of high-salinity brine was small unless low-salinity brine was used for spontaneous imbibition. 4. Resistivity measurements yielded unexpectedly large tortuosity values (12 to 19), indicating that molecules and bulk fluids have great difficulty to travel from one point to another in shale reservoirs.
Pressure Transient Analysis for a Unique Shale Gas Condensate Well, Actual Field Case
Authors: Ibrahim M. , Pieprzica C. , Vosburgh E. , Dabral A. , Olayinka O. , Larsen S.
Published: October 2017

Horizontal drilling accompanied with Hydraulic fracturing makes the unconventional reservoir a viable addition to worldwide production. Hydraulic fracturing of a well is the largest cost when evaluating total well expense. Therefore, understanding the fracture performance is fundamental to the success of a shale well. The two main factors controlling a shale horizontal wells performance is completion design and reservoir quality. The completion efficiency depends on factors such as well spacing, stage spacing, cluster spacing, fluid volume, proppant type and volume, injection rate, type of fracture fluid and gas price.

There are many techniques used to evaluate the hydraulic fracture performance. Some include post fracture analysis, tracer analysis, micro seismic analysis, rate transient analysis, production log analysis, fiber optics data and pressure transient analysis.

This paper presents the integration of completion data, petrophysical data, fluid sample analysis, mini-frac analysis, and flowback data in matching long term buildup data. More than 6 months of data was collected for one of the unique shale gas condensate wells during the appraisal stage of an area. The analysis showed the effect of liquid drop out and phase segregation in the flow regimes.

Also, this paper presents a different analytical model used to match the actual buildup data. The resulting model is used in building a reservoir model to forecast performance for the well.
Use of Experimental Design for Uncertainty Assessment in Deep Offshore Gulf of Mexico
Authors: Ait-Ettajer T. , Whiteley G. , Abrarova G. , Fontenla Alvarez S. , Dong Y. , Fajardo C. , Cendrowski R. , Giannangeli F.
Published: October 2017

The lower tertiary Wilcox trend, which extends from Alaminos Canyon(AC) to Keathley Canyon (KC), is attracting more attention from the oil&gas industry (Vassilellis, et al., 2013) and more production and final investment decision (FID) are expected in the near future according to WoodMac latest reports. The range of reserves of the lower tertiary Wilcox trend is between 3 and 15 billion barrels (Dusterhoft, Strobel, & Szatny, 2012). Buckskin field is among the fields located in this trend at approximately 290 miles south-east of Houston (Ait-Ettajer, 2017). The Buckskin discovery well (yacimiento_golfo_mexico.aspx, 2009) and the appraisal wells drilled afterwards, encountered more than 1,000 foot hydrocarbon column between 25,000 and 27,000 feet depth and 6000 feet of water, in sand bearing turbidite, located in different compartments bounded by a complex fault network. Despite, the subsurface studies performed following the drilling campaign, significant uncertainties remained. Several approaches were assessed in order to study the impact of those uncertainties on the hydrocarbon storage and mobility of this field. Probabilistic methods based on experimental design and Monte-Carlo simulations, were chosen in order to optimize the development plan and the reserves assessment, due to their robustness and their flexibility. Those probabilistic methods, combined with experimental design technique, allowed the identification of the key uncertainties and the definition of response model that predicts the range of oil in place and the optimization of the development plans, without the need to run hundreds of thousands realizations.
A New Comprehensive Numerical Model for Fracture Diagnosis with Distributed Temperature Sensing DTS
Authors: Sun He , Yu Wei , Sepehrnoori Kamy
Published: October 2017

The growing acceptance of Distributed Temperature Sensing (DTS) has been contributed by its accurate real-time estimation of the staged fracturing effectiveness. The objective of this study is to develop a new model to simulate fluid flow and temperature profiling of horizontal wellbores with complex fracture geometries. This study offers an enhanced estimation of key reservoir and fracture properties with DTS, which may throw light on the further optimization of the fracturing projects. Specifically, we developed a comprehensive numerical model to simulate flow and temperature field in unconventional reservoir with DTS. In our robust wellbore model, multiphase flow with slippage is simulated accurately. Flow and thermal models are fully coupled between wellbore and reservoir model. The new model was validated with exiting simulator of OLGA and CMG. After validation, we applied our model to simulate single fracture and five fractures cases with varying parameters. The impacts of several parameters, including reservoir matrix permeability, fracture conductivity, reservoir rock thermal conductivity, heat exchange coefficient, fracture spacing, and fracture geometry, on temperature profile along the wellbore were analyzed. Several practical conclusions have been drawn from the sensitivity analysis. Although numerous simulators have been developed to simulate the DTS data, relatively few existing models can handle the multiphase flow with slippage, heterogenous reservoir properties and fracture with complex geometries due to the complexity of the calculations and computational cost. Our model is more rigorous than the prior models to simulate the DTS data through the advanced wellbore and reservoir models.
Evaluation of Pressure-Transient Behavior of Unfractured Vertical, Vertically Fractured, and Horizontal Wells in a Composite Reservoir with an Active Aquifer and Moving Fluid Interfaces
Authors: Poe Bobby D. , Hender Donald G.
Published: October 2017

Pressure-transient models are presented for evaluation of the behavior of vertical, vertically fractured, and horizontal wells in radial and linear (three-region) composite reservoirs with moving fluid fronts. The Laplace Transform Finite Difference (LTFD) numerical solution methodology combined with the well- known Buckley-Leverett (BL) frontal-advance equation have been used to develop solutions for the moving boundary problem. Hybrid semi-analytic and numerical solutions have been constructed for finite-conductivity vertical fractures and infinite-conductivity horizontal wellbores. Complete descriptions of the mathematical models are presented; the pressure-transient solutions, frontal position and velocity, and saturation distributions. Indications are that monitoring of the transient behavior permits detection of water encroachment to the producing well, prior to breakthrough. This enables modifications in the production operations to be taken proactively to delay breakthrough.

The results of the pressure-transient models reported in this paper have been compared with the available moving boundary radial composite solutions in the literature and the results of the vertically fractured and horizontal well solutions have been validated using analytic and numerical reservoir simulation. Six well and reservoir model combinations have been considered in this investigation for which oilfield applications exist for each composite system considered. These include solutions of the pressure-transient behavior of an unfractured vertical well in a radial composite reservoir, a vertically fractured well in linear and radial composite systems, a horizontal well in radial and linear composite systems, and a vertical fracture intersected by a horizontal well in a linear composite system. Extension of the solution methodology used in this study for evaluating the pressure-transient behavior of a selectively completed horizontal wellbore in a cylindrical composite reservoir has also been considered in this study. Each of these solutions include moving fluid fronts, whose position and velocity are determined from the frontal advance model and fractional flow theory. General fractional flow solutions have been implemented that utilize conventional laboratory relative permeability measurements.
Deployment of a Remotely Activated Liner Hanger System to Improve Drilling and Well Construction Efficiencies
Authors: Munshi Ammar A. , O'Connor K. , McMahon S. , Carmody M.
Published: October 2017

Operators for deepwater and extended-reach wells, where daily rig costs can exceed $500k per day, are continuously exploring methods to reduce nonproductive time (NPT) and increase operational efficiency. For example, a common point of focus is liner string deployments in deepwater and highly deviated applications that predominantly employ hydraulic liner hangers.

This paper presents a new liner hanger system that uses simple mud flow signals to remotely communicate with a downhole controller on the work string. The controller receives the specific activation signal from the surface and then relays that signal to the liner hanger or running tool via an acoustic signal. The results of the first test trial of the remote liner hanger system controller will be discussed.

The traditional method for setting a hydraulic liner hanger includes the use of single or multiple activation balls being dropped from the surface so that pressure can be applied to the work string to function the hydraulic liner hanger and running tool. However, in deepwater and extended-reach applications, many operational issues experienced with running hydraulic liner hangers are related to not landing the ball on seat, which can lead to days of NPT. Developing a liner hanger system that does not rely on dropping activation balls from the surface nor rely on pipe manipulation can reduce the time required to run the liner hanger and minimize issues that lead to higher NPT.

This new system does not require dropping activation balls from the surface, reducing the amount of running tools in the work string and the amount of time required to set the liner hanger. The system also allows the use of a solid liner hanger body, eliminating the potential leak paths inherent to hydraulic liner hangers. The results will demonstrate the first deployment of the remote system controller in a well, confirming that it detects various remote commands from the surface. The results will also demonstrate how the system enables operators to choose the activation method depending on the well and rig conditions, for example, varying the flow rate activation signals. This system and method can improve well construction efficiencies and is a step in the direction of a smarter and safer oilfield through more automated operations.
A Novel Approach to Developing and Conditioning Part Field Models for a Complex Fluvio-Deltaic Reservoir: An Example from the Wara Formation in the Greater Burgan Field
Authors: Dashti L. , Filak J. M. , Bond D. J. , Banagale M. R. , Al-Houti R. A. , Luneau B. A. , Molinari D.
Published: October 2017

The Wara reservoir is one of the main producing formations of the giant Greater Burgan field. It has been on production under natural depletion for many years. A massive water-flood of this formation has recently commenced. This was preceded by a large-scale pilot water flood the aims of which included enhancing reservoir understanding. This paper describes how historical data, including data from the large-scale pilot, were used to construct representative part filed models.

The area of the pilot water flood has significant volumes of data, including core and log data and dynamic data such as pressure transient data, interference tests, tracer tests and cased-hole logs. These provide valuable information for reservoir characterization.

The Wara formation was deposited in a tidally influenced fluvio-deltaic environment where sand continuity is complex. There was a desire to develop realistic geological and simulation models that accounted for our understanding of Wara geology and were consistent with the large volumes of surveillance data.

A major challenge was the choice of an appropriate area for the part field model. This was chosen so as to allow water influx into the area of interest over the life of the field to be accounted for and to allow relatively simple boundary conditions to be applied.

Geological models were constructed using object based techniques. These models used reservoir rock types that were developed to broadly match permeability-height estimates from pressure transient data.

The geological models were not guaranteed to account for the sand connectivity inferred form the surveillance data. A streamline based screening technique was used to exclude models that did not broadly capture the interpreted connectivity.

Dynamic simulation models were then developed and conditioned to data using conventional assisted history matching techniques. At this stage, some sensitivities related to boundary conditions were explored. Sand connectivity was not varied at this stage.

Some examples are given as to how the resulting conditioned models have been used to address questions about expected future reservoir performance. Specifically questions related to proposed well spacing and pattern type are discussed.

This paper describes a novel approach to developing models that are geologically realistic and are consistent with the interpretation of reservoir connectivity from a range of surveillance data. This involves using a streamline based screening tool before using assisted history matching techniques. Such an approach can be applied to both part and full field models.

The challenges of using such an approach with part field models are described. Some guidance is given to know when it would be appropriate to try to develop and condition part field models.
New Multisensor Inversion Technology for Imaging Near-Wellbore Petrophysical Properties from Resistivity, Sonic, and Density Data
Authors: Shetty Sushil , Liang Lin , Simoes Vanessa , Canesin Fabio , Boyd Austin , Zeroug Smaine , Sinha Bikash , Habashy Tarek , Domingues Ana Beatriz , Amorim Claudia , Abbots Frances
Published: October 2017

We present an automatic inversion method for data acquired in a vertical well by the sonic, induction, and density borehole logging tools. The method is designed for oil-bearing or gas-bearing formations drilled with oil-base mud. The inversion accounts for challenging scenarios where the tool sensors are affected by filtrate invasion, gas phase, complex mineralogy and mechanical damage. The output consists of porosity and radial distributions of fluid saturations and pore shape extending several feet from the wellbore. The output is robust, accurate, and consistent with radial investigation depths of all the tools.

The formation model assumed in the inversion has homogeneous porosity and radially varying pore shape, oil, gas, and water saturation. Radial changes in fluid saturation and pore shape are caused by filtrate invasion and mechanical damage respectively. The data for different tools are simulated from sonic and electromagnetic forward solvers, linked to the formation model through a saturation-resistivity transform and an effective medium rock physics model. The inversion estimates formation properties such that the simulated data match the measured data. For the first time, sonic data for both dipole flexural wave and monopole compressional-headwave are included. These data are sensitive to porosity and pore shape effects, and the compressional-headwave additionally provides sensitivity to gas saturation in soft formations.

The inversion was tested on synthetic data and applied to two field data sets for gas-bearing formations. The results are visualized as 2D images with radial distribution of formation properties at each log depth. The images characterize radial depth of filtrate invasion and mechanical damage, which can guide completion and production decisions. The inversion also provides far-field saturation and porosity. The far-field properties are in overall good agreement with core data and traditional interpretation, with differences from traditional interpretation in key intervals. Quality controls enable checking validity of models assumed in the inversion. The results demonstrate an efficient inversion framework for guiding formation evaluation decisions in challenging scenarios.
Towards a Complete Removal of Barite Weighted Water and Oil Based-Drilling Fluids in Single Stage
Authors: Mahmoud Mohamed , Elkatatny Salaheldin
Published: October 2017

Barite is one of the most common weighting materials used in drilling fluid for deep oil and gas wells. Consequently, the main source of solids building the filter cake is the weighting material used in drilling fluids ‘Barite particles’. Barite is insoluble in water and acids such as HCl, formic, citric, and acetic acids, as well as the barite has low solubility in chelating agent such as Ethylene Diamine Tetra Acetic Acid (EDTA).

The present study introduces a new formulation to dissolve the barite filter cake using converters and catalysts. Barite can be converted to barium carbonate at high pH medium using combination of potassium hydroxide (KOH) and potassium carbonate (K2CO3) solution. Then HCl acid can be used to dissolve the barium carbonate. Another solution is to use high pH EDTA chelating agent and potassium carbonate as a catalyst/converter in one step. The removal formulation also contains polymer breaker (oxidizers). The three components of the new formulation are compatible and stable up to 300°F. Solubility tests were conducted using industrial barite particles with size ranged from 30 to 60 micron. The solubility experiments were carried at 300°F for 24 hours. Different concentrations of catalyst were added to select the optimum concentration. The designed formulation was examined to remove filter cake formed by Barite drilling fluid using High Pressure High Temperature cell (HPHT).

The result of this study showed that the barite removal efficiency of new formulation reached to 87 % in water base mud and 83 % in oil base mud. The solubility test results presented that the solubility of barite particles in 0.6M EDTA was 62 % in 24 hours at 300°F. Adding potassium carbonate catalyst to the 0.6M EDTA solution the increased the solubility of barite to 90 wt. % in 24 hours. The use of converting agents increased the barite solubility from62% to 90% in EDTA. The EDTA was compatible with the polymer breaker (oxidizer) so the filter cake removal will be in single stage. The oxidizer concentration used was 10 wt%, potassium carbonate concentration was 10 wt% and EDTA concentration was 0.6M. The new formulation achieved 85% filter cake removal in both oil-based and water-based drilling fluids. In oil base mud a water wetting surfactant, mutual solvent, and emulsifier should be added to the formulation to remove the oil. In this study, two solutions were proposed to remove the barite filter cake and barite scale from oil and gas wells at different conditions. The first one is by using HCl acid after converting the barium sulfate to barium carbonate using high pH medium such as KOH and K2CO3. Then HCl can easily remove the barium carbonate. The second method is to create the high pH medium by using the removal fluid itself which is EDTA chelating agent in addition to potassium carbonate as converter.
Reservoir Surveillance with 4DVSP - A Case Study in a Kuwait EOR Steam Flood Project
Authors: Al-Mutairi Amal , Al-Haqqan Hamad , Ren Zu Biao , Tinnin John , Randazzo Santi , Pare Antoine
Published: October 2017

Kuwait Oil Company conducted a 4DVSP steam flood monitoring program in a heavy oil field to help optimize development options. The baseline survey for this 4DVSP was acquired in January 2016 and the monitor survey was acquired in January 2017. The key objectives for this reservoir surveillance project include acquiring a repeatable baseline survey; image two vertically stacked thin reservoir units, perform characterization to understand reservoir complexity and lateral barriers, and estimate the steam chest size (sometimes referred to as a steam chamber) after 30 days of steam injection.

The 3DVSP survey took less than a week with rigless acquisition only during daylight hours. The survey area was fairly congested with infrastructure making it difficult to manoeuvre between source positions easily. To tackle this, two groups of vibrators were used with a source driven acquisition technique. This meant much of the acquisition process was automated providing better efficiency and reducing human error.

The resulting data was processed and imaged with proprietary 3DVSP Kirchhoff depth migration algorithms. Due to an innovative acquisition design, output frequencies were 30% higher than achieved in previous VSPs or seismic data in the area. Velocity models were derived using the zero offset VSP data and a geomodel was derived from well data. The migration was sampled at dX/dY/dZ values of one meter each to help create a high resolution image. Synthetic seismograms from well logs and corridor stacks from the zero offset VSP were used to accurately tie the well data to the 3DVSP volume. This data volume was mapped using seismic workstations and amplitude anomalies were obvious around the steam injected well making possible the mapping of the steam chest. Deterministic inversions from this data help identify facies changes and channels explaining the direction and pathways of the steam flow. In summary, each of the goals for this project was achieved. The two thin reservoir units and the top sealing shale were resolved while inversions were very beneficial for reservoir characterization and understanding facies changes. The steam chest was easily discernable and its volume was calculated. These results justified the first ever 4DVSP in Kuwait which was acquired in January 2017. Ultimately, knowing where the steam fronts travel, where lateral barriers divert the steam, and how quickly it moves will help to optimize the development plans for the best possible EOR effectiveness and recovery rate improvement.
Proven Hydraulic Fracturing Field Applications for Real-Time Visualization and Monitoring System
Authors: Hlidek Barry T. , Lee Charlie
Published: October 2017

The confirmation of critical downhole events helps operators make effective real-time decisions during hydraulic fracturing operations. A relatively new monitoring system has been gaining traction in the industry, using high resolution pressure and acoustic signals to help operators visualize downhole and surface events. This paper briefly describes the real-time visualization system (RTVS) monitoring operation and focuses on case histories from the field.

Traditionally, downhole events such as fracturing sleeve shifts are verified by surface pressure signatures. Gaps may occur when conventional pressure signatures are ambiguous, if, for example, the bottomhole pressure is low. The monitoring system provides a visual and audible representation of downhole and wellhead events, using a unique and specialized array of electronic sensors. The monitoring system operates alongside conventional pressure measurement, as a separate and independent verification. The data stream can be integrated with conventional monitoring data.

Through a series of both onshore and offshore case histories, the system is proven to be able to confirm both pressure and non-pressure events. The paper includes detailed field examples utilizing the visualization system. Specific examples include determination of ball launches from the wellhead to confirm launch equipment and procedures. Fracturing sleeve operations can be verified, including balls seating and sleeves shifting. Failed ball launches at surface or unshifted sliding sleeves downhole can result in a costly loss of entire treatment stages or inadvertent overstimulation. Equally important are troubleshooting issues, which, if correctly diagnosed, allows the problem to be effectively addressed. Themonitoring system has detected equipment failure, including pump and casing breaches. Also, the paper will address limitations of the monitoring system; some types of events are not clearly identifiable.

The RTVS is deployed on surface, can be set up in 30 minutes, and has a small footprint. Real-time monitoring adds an extra layer of information, enabling better completion optimization, and reducing uncertainty and downtime. Continued data collection will provide theindustry with a better understanding of unseen events that will contribute tofuture operation and technology development.