bluuebunny/crossref_metadata_2025 huggingface dataset:
An Integrated Methodology for Calibrating a Heterogeneous/Fractured Reservoir Model from Wellbore Flow Measurements: Case Study
Authors: Pourpak Hamid , Bourbiaux Bernard , Roggero Frédéric , Delay Frederick
Published: June 2014

Reliable flow modelling of highly-heterogeneous/fractured reservoirs necessarily goes through the calibration of poorly-determined geological and/or petrophysical parameters to field flow measurements. To that end, optimization procedures, based on gradient methods or on gradual deformation techniques, have been developed in the recent years.

This paper proposes a sequential methodology combining those two approaches. The case under consideration is a water-bearing reservoir constituted of heterogeneous, karstic and fractured limestones located near Poitiers city in France. In a preliminary step, drilling, core and log data acquired in about 30 wells were integrated into a geostatistical facies model used as the support for flow simulation.

Firstly, the facies petrophysical properties of this model were calibrated to well pumping and interference responses within a gradient-based inversion loop. Flow responses could be reproduced, except for a few "problematic" observation wells.

Secondly, the gradual deformation method was applied, globally then locally, to improve the distribution of facies while keeping the previously-optimized petrophysical properties. The "problematic" wells responses could be better reproduced without altering the other wells match. Furthermore, that good match of calibration wells was obtained on a simplified geostatistical model involving fewer facies as on the initial model. The gradual deformation method then appears as a robust and effective approach to find a model bestly matching a set of flow data among equi-probable geostatistical models.

To conclude, the sequential modelling methodology demonstrated herein is an effective way to actually integrate geological and flow data and to link geosciences and reservoir engineering skills, for setting up consistent models of hardly-tractable highly-heterogeneous reservoirs.
New Horizons in Gas Hydrate Recovery using Fluorine and Microwave Technology
Authors: Garg Rachit , Ogra Konark , Choudhary Arpit , Menezes Richard
Published: June 2014

Methane gas hydrates are cages of water molecule that trap small, low molecular weight gas molecules e.g. methane, ethane, hydrogen sulfide etc. the enormous quantity of gas stored in them (1m3 G.H = 180m3) makes them an important area of research for the scientist and petroleum engineers.

Over the years the various theoretical techniques for recovery of the gas hydrates are 1.thermal injection 2.inhibitors 3.depressurization. However due to inefficient and economic unfeasibility it is difficult to recover the methane from gas hydrates.

Low injectivity reservoir, small thickness of G.H bearing zone, heat loss especially in permafrost region, also the cost of the inhibitors (which change the thermodynamic condition) is litre of methanol makes it uneconomical, finally depressurization of an adjacent free gas zone can effectively dissociate hydrate but the endothermic nature of the hydrate decomposition will decrease the reservoir temperature and which may temporarily decrease the flow rate.

The technical problems with estimating the gas hydrate are

Technology to safely and economically produce methane from G.H deposits. Safety and drill floor stability related issues related to drilling through G.H bearing accumulations.

This paper deals with a new technique of a In this technique, the pressure of the fluids in contact with hydrate is lowered, pushing the hydrate out of its stability region and leading to its decomposition. Because no extra heat is introduced into the reservoir, the heat of decomposition must be supplied from the surrounding formation.

recovery of methane from G.H. This technique involves use of a micro strip antenna which has huge power gain and is relatively inexpensive, with wire line the tool is placed in well bore and frequency of 2450 MHz is released which melt the G.H into water and methyl radical (as they are almost similar to ice) such that they disturb the thermodynamic condition, then the fluorine is injected, this results in reaction between methyl radical and injected fluorine (halogenation), which is strongly exothermic (-431KJ/mole), this reaction propagates the reaction and simultaneously we have solubility of methyl fluoride with water which is 166cc/ 100 ml of water. This pressurized gas solution is then recovered via tubing from production well. Later by applying wurtz reaction, electrolysis and cracking methane can be recovered.

The main advantage of using this technique is micro waves interact strongly with some materials and weakly with others, energy absorption depends on microwave frequency, sample composition, temperature. The chemical compound fluorine is abundant in nature (540000ppb) and methyl fluoride is environmental friendly.
A New Flow Skin Factor Formulation for Hydraulically Fractured Wells in Gas Condensate Reservoirs
Authors: Mahdiyar H. , Jamiolahmadi M. , Sohrabi M.
Published: June 2014

Fracturing is one of the most common well stimulation techniques especially for tight gas-condensate reservoirs. Gas condensate flow around hydraulically fractured wells (HFWs) is different from conventional gas oil systems. This is mainly due to phase change, condensate drop out and coupling (i.e., the increase of relative permeability as velocity increases and/or interfacial tension decreases) and inertial (i.e., the reduction of relative permeability as velocity increases) effects.

Description of HFWs in gas condensate reservoirs using the existing reservoir simulators requires the use of very fine grids to capture the significant changes of flow and rock properties occurring in and around the fracture. This tasks it very cumbersome, time consuming and impractical.

In this work a two dimensional mathematical simulator has been developed, which is based on finite-difference methods and accounts for the combined effects of coupling and inertia using our recently developed generalized correlation. This single-well model, which simulates the steady-state flow of gas and condensate around HFWs, also allows for phase change in these low interfacial tension systems. A series of sensitivity studies were carried out using this simulator. The results were used to develop a general method for estimation of flow skin factor based on the definition of dimensionless effective fracture conductivity. In the proposed method the skin factor expressing the impact of pertinent parameters are then converted to an effective well bore radius, which can be used by a reservoir engineer to conduct a realistic open-hole simulation of flow around HFWs.
Low IFT Gas-Oil Gravity Drainage in Fractured Carbonate Porous Media
Authors: Karimaie H. , Torsæter O.
Published: June 2014

This paper addresses a study of gas-oil gravity drainage in fractured carbonate rock subjected to gas injection in low interfacial tension. The purpose of the experiments described in the paper was to investigate gas injection in fractured carbonate reservoirs in both secondary and tertiary cases (after water injection), focusing on gravity drainage using equilibrium gas followed by re-pressurization. Gas injection experiments were performed on 20 cm long and low permeable outcrop chalk core surrounded with a fracture established with a novel experimental set-up in reservoir conditions. The core was saturated with binary mixture live oil consisting of C1 and C7 of a known composition, while the fracture was filled with sealing material to obtain a homogeneous saturation. After core initialization, the sealing material was removed by increasing the temperature to higher than its melting point and displaced by live oil. Gas was then injected into the fracture and gravity drainage experiments were performed in low interfacial tension (< 0.5 mN/m) where the IFT between the phases were measured experimentally by selecting the proper pressure and temperature.

Experiments were performed at different pressures and reversibility of the effect of the interfacial tension was checked by re-pressurization process. The oil recovered from the bottom side of the block was measured versus time.

Based on the results of this study, the recovery of oil showed a significant increase by re-pressurization in gravity drainage process. It was also clear that low-IFT gravity drainage is capable to recover a significant amount of oil in fractured reservoirs even after water injection.
Bidding Schemes and Their Impacts on Risk Assessments by Oil Companies
Authors: Rodriguez M. R. , Suslick S. B.
Published: June 2014

Petroleum auctions in US-GOM and Brazil are a common value first-price sealed bid, with fundamental differences on bidding systems defined by the regulators regarding the winner proposal. The US-GOM bidding model for offshore exploration areas considers the higher bonuses values as the winner offer. In Brazil, two main variables define the winner: the signature bonus and the minimum exploration program (PEM). The PEM aggregates value to the government, as it is a firm commitment to acquire geological data on the first exploration years. The amount of PEM committed reflects the importance of the exploration area for the bidders. This information not necessarily could be addressed by the simple high bids' analyses as in the US-GOM system. The Brazilian bidding model allows the bidders to a "full risk assessment" on their competitor's bidding behavior. This paper compares the risk perceptions of oil companies using the US-GOM and Brazilian bidding results for years 2005 and 2006, assuming the same oil price scenario and areas of similar geological settings. Another contribution of this paper is to present a competition model for evaluate different risk perceptions by using measures such as cash bonus (upfront money) and PEM (a long-term disbursement) generated by diverse bidding schemes. Preliminary results show that Brazilian high bids are in the same range of US-GOM bonuses (20,000.00 to 30,000.00 US$/km2). Nevertheless, considering bonus and PEM as the winner offer, Brazilian high bids double the American ones. The competition model used for evaluate the firm performance in both bidding systems indicates that the utilization of bonus and PEM allow companies' decision makers to perform a better portfolio management, but demands the inclusion of a solid risk perception to select the best areas for bidding.
Vorticity-Based PEBI Grids for Improved Upscaling of Two Phase Flow
Authors: Evazi M. , Mahani H. , Hejranfar K. , Masihi M.
Published: June 2014

Highly detailed geological models, which are primary inputs to reservoir simulator, necessitate the reduction of number of grid blocks to be used in the solution of flow equations. However preparing a coarse scale model that can mimic the fine scale behavior is a challenging task. Cartesian grid suffers from some shortcomings, as in adaptation with geological and geometrical features and the phenomenon of grid orientation effect that motivates the use of unstructured grid. Different methods have been used for this purpose, but no one is robust enough that justifies the need for more research.

In this paper, we propose an unstructured grid generation scheme that utilizes the vorticity of fluid flow in porous media as the determining parameter for background grid generation. It entails the simulation of single-phase flow on the fine grid and obtaining the velocity field and subsequently vorticity map. Vorticity is then used to generate the background grid that plays an essential role in the generation of desired final coarse grid. At this stage user needs to determine the value of some parameters such as maximum and minimum spacing, vorticity cut-off and intensity degree. Advancing front method and Delaunay triangulation are then resorted to provide the triangular and Voronoi (PEBI) grid. The developed technique, which aims at capturing both flow and geologic details, produces grids with higher resolution at critical vorticity areas, such as around layer boundaries, and with lower resolution where vorticity is negligible, like in homogenous regions.

This technique is applied to two channelized and heterogeneous models and the results are presented. Two-phase flow simulations are performed on the generated coarse grids and the results are compared with the ones of fine scale grid and uniformly generated coarse grids. The results show a greater accuracy compared to uniformly gridded models.
Innovative Implementation of Compositional Delumping in Integrated Asset Modelling
Authors: Vignati E. , Cominelli A. , Rossi R. , Roscini P.
Published: June 2014

In reservoir simulations it is a common practice to use a limited number of components to describe the reservoir fluids, ranging from 2 (black-oil models) to 5-12 (compositional equation of state based models). On the opposite, surface models usually require a greater number of components, typically from 15 to 30. The hydrocarbon components used in the surface model are usually lumped into pseudo-components in the reservoir. This disparity in the description of the mixture may become an issue whenever integrated asset models are developed with the aim of linking surface process and reservoir engineering.

Leibovici et al.[10] presented a method to delump pseudo-components and predict the detailed phase compositions according to the results of a flash calculation performed on a lumped mixture. Leibovici et al.[11] proposed to use the delumping in the context of compositional reservoir simulation to predict the detailed composition of the produced fluid. The key-feature of this method is to calculate the phase equilibria with a simplified fluid and transfer the results in the detailed fluid model description applying a linearization in the space of equation of state parameters. They implemented this method by post-processing the results of a compositional simulation and use computed phase velocities to trace the delumped components. The delumping method was then implemented in a commercial compositional reservoir simulator by coupling the algorithm with a tracer advection module. The simulator option is usually referred as compositional tracer option. In this paper we used the Leibovici et al. approach in the context of the integrated asset modeling of complex reservoir fluids. Process models with detailed compositional formulation were linked to compositionally simpler reservoir models, using the compositional tracer option to feed the surface model with the produced reservoir streams.

The proposed workflow was applied to simulate two different recovery processes, namely a) a gas injection below the dew-point in a sour gas condensate reservoir; and b) a miscible gas injection in a near critical volatile oil reservoir. Results of this implementation, in which detailed components are traced in the reservoirs, are compared to integrated simulations where all the stages, including reservoirs, are modelled using detailed composition.
Non-Darcy Flow: Laboratory Measurements in Unconsolidated Porous Media
Authors: Macini P. , Mesini E. , Viola R.
Published: June 2014

In recent years, the petroleum industry has shown a renovated interest in Non-Darcy flow, in order to better understand reservoir performances. Non-Darcy flow is typically observed in gas wells when the fluids converging to the wellbore attains the velocity peculiar of turbulent flow. As a consequence, pressure drop around the wellbore cannot be estimated from the classic Darcy equation, where the pressure gradient is a linear function of the flow velocity. In that case, in fact, the use of Darcy equation would lead to inaccurate production performances evaluation.

In order to describe correctly this phenomenon, the well-known Forchheimer equation is normally used, where the inertial coefficient ß is defined. In gas wells this coefficient is usually determined by the analysis of multi-rate pressure tests performed on site. Unfortunately, such data are not easily available (or not economical) in many cases. So, it is a common practice to use particular theoretical and empirical correlations that can be derived by exploiting experimental values of the inertial coefficient.

This paper reports a laboratory study in which the inertial coefficient ß can be correlated to the structure of the porous media, and, in particular, of its grain size distribution. Gas flow laboratory experiments have been performed on laboratory models of glass beads and natural sands of different sizes. Moreover, porosity and permeability, together with the Klinkenberg constant, have been determined on natural sand cores with both flat and peaked grain size distribution, and a correlation with the Forchheimer equation has been checked. Forchheimer's number has been calculated and correlated to the superficial velocity as well. In the light of the above, specific laboratory equipment has been devised in order to rely on a wide range of flow rate under appropriate pressure gradients.
Improved And Robust Drilling Simulators Using Past Real-Time Measurements And Artificial Intelligence
Authors: Nybø Roar , Bjørkevoll Knut S. , Rommetveit Rolv , Skalle Pål , Herbert Mike
Published: June 2014

Time series data from past drilling operations are an under-utilized resource in oil-companies. In this paper, we present a simple example of how knowledge implicit in time series can be complementary to traditional modeling. In particular our system reduces the occurrence of a false kick alarm typically seen when making a connection during drilling.
Monetizing Gas: Focusing on Developments in Gas Hydrate as a Mode of Transportation
Authors: Rajnauth Jerome , Barrufet Maria
Published: June 2014

Natural gas and energy resource management is a major challenge in the rapidly changing global and business environment. Increase in gas recoveries and gas production have led a major review in the ways of transporting natural gas energy. Monetizing gas has now become a high priority issue for many countries. Natural gas is a much cleaner fuel than oil and coal especially for electricity generation.

Interest in gas hydrate being used as a means of transporting natural gas has increased over the last decade. New technology development has been focusing on using gas hydrates as a way of converting gas to solids to transport to markets around the world. Gas hydrate may be a viable means of storing and transporting gas but more focus should be given to some critical considerations for this gas hydrate development.

This paper would discuss some of these issues as we move towards monetizing gas in the form of hydrate. These include present and future gas prices, energy balance in hydrate formation and re-gasification, storage of the hydrate, form of transporting the hydrate and distances to be transported. Other important factors are re-gasification technologies, economics compared to other gas transportation modes, environmental, climate and other issues.
The Impact of Sandstone Strength's Behavior as a Result of Temperature Changes in Water Injectors
Authors: Tovar J. , Navarro W.
Published: June 2014

In water injection programs it is accepted that the temperature at which water arrives at the formation will cause the rock to shrink resulting in a reduction in the minimum horizontal stress and possibly a fracture of the rock. This effect is known as TIF or Thermally Induced Fracturing. However, little research has been carried out as to how the cooling of the rock by the injection water affect the formation mechanical properties. This paper presents work carried out to determine the effect of temperature changes on the strength of sandstone reservoirs used for water injection.

An effort was initiated by Pluspetrol Norte, S.A. as part of their produced water disposal programs to develop an understanding as to how various sandstone reservoirs used for re-injection respond to temperature changes and what implications can it have for their operations. Pluspetrol production comes from two(2) main blocks in Northern Peru, Total water production has reached over 1000000 bwpd of which over 450000 bwpd are currently being re-injected throughout both blocks.

A large core testing program was designed and completed to measure unconfined rock strength in a number of sandstone cores available from both blocks. The cores were heated and cooled and their strength measured to identify possible changes in strength magnitude. The results obtained were analysed and compared with those available in a large geomechanical model of the blocks developed earlier known as the Custodian(1), a new predictive model was developed using the results obtained. A number of simulations were carried out using a TIF model to compare the measured field data during water re-injection with the predictions from the TIF model using the new strength model. These results are presented in detail and its application to other geomechanical problems such as sand production in water injectors is also discussed.
Petro-Elastic Models: How Many and at What Scale?
Authors: Alfred D. , Atan S. , Hamman J. G. , Caldwell D. H.
Published: June 2014

This paper describes an integrated workflow that determines the minimum number of petro elastic models required to adequately predict elastic properties for a given flow scale. The workflow involves the formulation of scale-dependent petro-elastic models (PEM) and petro-elastic facies from well logs. Then through an error evaluation technique, determines the minimum number of PEMs required and the maximum vertical grid size limit for the flow scale. The validity of the fine scale PEMs across different scales is also tested in the workflow.

Elastic properties of reservoir rocks can be predicted through petro-elastic models which relate fluid and intrinsic reservoir properties to elastic properties through mathematical functions or rock physics models. Although we would like to generate PEMs at flow scale, very often the PEMs are generated from logs that are consistent with core data. A PEM is lithology and rock fabric specific. In an upscaled flow model, the lithologies or textures are mixed. Fine scale PEMs may no longer adequately describe the elastic properties of the reservoir at flow and seismic scale.

Prediction is improved in a flow model that integrates all available measurements. Scale inconsistencies of the measurements need to be addressed for better integration and prediction. In this paper we will show that through a unique and iterative approach, PEMs must be generated at flow scale for improved integration. The methodology has been tested with synthetic data and resulted in a better predictive flow scale model, which is consistent across all scale resolutions.
Continuous History Matching a HPHT Gas Condensate Field during the First Two Years of Production
Authors: Christoffersen K. R. , Quin J. G. , Zweigel P. , Hansen O. R. , Zaostrovski A.
Published: June 2014

The HPHT Kristin field is located offshore Norway in 350 m water depth and is developed with four sub-sea templates. Since production began in November 2005, reservoir pressure has dropped around 4 times faster than predicted. The main Kristin field statistics include: an initial pressure of 910 bar, a reservoir temperature of 170°C, a dew point of around 400 bars (rich fluid accounts for 50% of income) and in-place volumes of around 100 GSm3 of gas and 100 MSm3 of condensate. The Kristin reservoir section comprises three separate Jurassic sandstone units and the field is segmented by faults. This paper describes the process of continuously history matching pressure decline during the first two years of production in Kristin using: production data, RFT pressures from wells drilled following production start-up, shut-in wellhead pressures, and data from two bottom-hole gauges. Close multidisciplinary cooperation between geophysicists, geologists and reservoir engineers has been key to ‘re-understanding' the Kristin reservoirs since production start-up and has facilitated the process of tuning the simulation model to obtain a better history matched model. The most important modifications have been the introduction of horizontal pressure barriers to match RFT pressures, and a significant reduction of pressure support from the eastern part of the field. The poor pressure support is interpreted to result from enhanced fault seal in one of the main reservoir units, and a rapid easterly decrease in reservoir properties in the other (main) reservoir unit. These changes have been directly input into the simulation model and have resulted in a good match of the pressure history from the 11 producing wells. Directly input into the simulation model has shortened the updating cycle to a few minutes and saved several months in the history matching process. Work is currently ongoing to refine a more detailed geological model based on these results, and the additional knowledge gained by testing different solutions directly in the simulation model. This improved understanding of the reservoir behaviour also gives valuable input to the uncertainty study required before updating official reserves.
Reservoir Compartmentalisation in the JG Field – Western Desert Egypt
Authors: Hoogerduijn Strating Eilard H. , Postuma Willem
Published: June 2014

The JG field is located in the North East Abu Gharadig (NEAG) Basin of the Western Desert in Egypt. With first production in 2002, it is the first commercial discovery in the Middle Jurassic Lower Safa Reservoir Units in this basin. Oil and gas are produced from the tidally influenced estuary channel deposits in the Lower Safa A Unit and oil from the massive braided fluvial channels in the Lower Safa C Unit.

At first, the field was believed to consist of one single hydrocarbon column. However based on production behavior and additional well information it became apparent that the field was highly compartmentalized in the vertical and horizontal domain. Since then multiple data sources have been leveraged in order to obtain better compartment definitions: 3D seismic, logs, PVT data, geochemical fingerprinting, repeat pressure surveys and production data.

The boundaries between the reservoir compartments are defined by a combination of faults and stratigraphic heterogeneities. Although clear in places, some compartment boundaries can only be defined from non-geological data sources. Understanding these heterogeneities and compartment boundaries is essential for optimizing the field development.

Like so many fields the JG field proved to be more complex than initially expected. It is argued that extensive data gathering, in particular in the early field development, is essential in helping to timely identify and properly define such complexities.
Oil Recovery from Matrix during CO2-Foam Flooding of Fractured Carbonate Oil Reservoirs
Authors: Fjelde Ingebret , Zuta John , Duyilemi Olawale Victor
Published: June 2014

The recovery of oil during CO2 flooding of fractured carbonate oil reservoirs strongly depends on the transport of CO2 from the fracture to the matrix. Molecular diffusion of CO2 from the fracture to the oil in the matrix will therefore affect the rate of oil production from the matrix to the fracture. CO2-foaming agents have been shown to increase the macroscopic sweep efficiency in CO2 floods. However, whether the foaming agent either increases or decreases the rate of oil production from matrix to fracture needs to be understood.

The effects of a CO2-foaming agent on the rate of oil production during CO2 flooding of fractured carbonate oil reservoirs at reservoir conditions have been studied in a fractured model. The fracture model was created by transferring the waterflooded core plugs into stainless steel cells with an annulus space around the core plugs. The fractures were flooded by injecting CO2 gas, co-injecting CO2 gas and aqueous foaming agent solution, or injecting aqueous foaming agent solution outside the core plugs. CO2 bulk diffusion coefficients for synthetic seawater, stock tank oil and an aqueous solution of a CO2-foaming agent were determined using the pressure decay method.

Co-injecting CO2 gas and aqueous foaming agent solution was found to give slightly higher oil recovery than CO2 injection. Bulk CO2 diffusion coefficients measured in synthetic seawater and aqueous solution of foaming agent show that the tested foaming agent does not any significant effect on the transport of CO2 at the experimental conditions used. For the CO2-synthetic seawater and CO2-stock tank oil systems the bulk diffusion coefficients were estimated to be of the same order of magnitude as published in literature at reservoir conditions.
Alteration of Thermodynamic Equilibrium and Fluids-Rock Interactions during Acid Gas Injection into a Carbonate Sour Oil Reservoir
Authors: Ceragioli P. , Gianelli G.
Published: June 2014

An increasing number of prospects are concerning sour fields, whose development involves complex technologies which become highly attractive in the present high oil price regime. However the development of such reservoirs requires to properly handling the acid components of the reservoir fluid in order to avoid any environmental impact, so that the acid gas reinjection into the reservoir itself becomes one possible way to develop such fields. The technology, if properly handled, in many cases may be able to combine environmental preservation needs with enhanced oil recovery capabilities.

The development of sour reservoirs, and even more the reinjection of their sour produced gases, possibly increased of their acid concentrations, involves a complex phenomenology when compared with the normal reservoirs. Unlike what is usually accepted for non-acid fluids, mass transfer between sour/acid fluids and the connate brine cannot be neglected anymore, if not for their absolute amount, because of their possible significant effects. When a sour/acid fluid contacts the connate brine, significant amounts of its acid components dissolve into the aqueous phase changing its overall composition. The acid components may alter the equilibrium between the reservoir rock and the connate brine, thus driving possible interactions with the formations rock. The thermodynamic and chemical equilibria involved in this fluid-rock interaction process have been evaluated for a specific real case, and presented in this paper. By changing the pH of the connate brine, carbonatic minerals dissolve and the formation porosity increases, thus leaving the chance of more favourable injection conditions.

The quantification of these effects is relevant to well injectivity and stability. In fact, in carbonatic reservoirs, calcite dissolution appears to be the main geochemical effect, enhancing injection conditions. Connate water vaporization also make inejction easier, while salts precipitation could obstacolated it. However, when small amounts of everywhere immobile connate brine permeates a low porosity rock, the amount of dissolved calcite has revealed to be very low, so that any possible improvement is expected to be very limited.

Here a static approach, applicable to other sour carbonate oil reservoirs, where no connate water mobilization is expected, has been outlined and the conclusions, here referred to a specific case, can be easily generalized.
Bit Balling Mitigation in PDC Bit Design
Authors: Wells Michael , Marvel Tim , Beuershausen Chad
Published: June 2014

Historically, parameters like junk slot area (JSA), face volume (FV) and hydraulic horsepower per square inch of bit area (HSI) have been used to empirically predict the balling performance of drill bits. These performance gauges, however, generally produce inconsistent results. This paper presents new design features, guided by numerical predictions and the physical properties of actual PDC bit cuttings that reduce bit balling in PDC bits while drilling shales in water-based drilling muds. Validated by drilling simulator tests and field results, the new design criteria are shown to provide consistent reliable methods to reduce PDC bit balling.

The new design methods employ empirical design rules that govern the allowable proximity of two adjacent blades (pinch points) and the profile of the junk slots. These methods are shown to increase the maximum achievable ROP (that ROP where bit balling just begins) by as much as an order of magnitude. Highly controlled and repeatable drilling simulator tests show that failure to employ the new design rules consistently results in premature bit balling. The drilling simulator provides accurate results for bit sizes up to 12 1/4 in. although the principles most likely apply to all bit sizes.

Additionally, studies using computational fluid dynamics (CFD) in concert with drilling simulator tests indicate that the maximum achievable balling ROP of a PDC drill bit is increased with increased fluid velocity across the cutting structure. The correlation is shown to be valid over a wide range of bit types and sizes. The new bit designs incorporate strategic nozzle placements and new nozzle designs that improve PDC drill bit performance by increasing the fluid velocity across the cutters.
Improved Techniques for Acquiring Pressure and Fluid Data in a Challenging Offshore Carbonate Environment
Authors: Contreiras K. D. , Van-Dùinem F. , Weinheber P. , Gisolf A. , Rueda M.
Published: June 2014

The combination of low permeability, oil base mud and near saturated oils presents one of the most challenging environments for fluid sampling with formation testers. Low permeability indicates that the drawdown while sampling will be high but this is contra-indicated for oils that are close to saturation pressure. A logical response is to therefore reduce the flow rate but in wells drilled with OBM an unacceptably long clean-up time would result.

The Pinda formation in Block 2 offshore Angola presents just such a challenge. Formation mobilities are in the low double or single-digits, saturation pressure is usually within a few hundred psi of formation pressure and borehole stability indicates that the wells must be drilled with oil base mud.

In the course of several penetrations of the Pinda formation a number of attempts were made to acquire representative formation samples but were stymied due to either excessive drawdowns that corrupted the fluid or by excessive contamination levels that rendered the samples unsuitable for laboratory analysis. Clearly a more flexible solution was required.

In this paper we review the learnings from previous attempts in the Pinda. We show the pre-job modeling that was done to predict the required flow rates and the anticipated drawdowns. Ultimately a two-step solution was used. We first ran a high efficiency pretest-only WFT in order to quickly gather formation pressure data and mobility data. This data was then used to design the sampling string which was a combination of an inflatable dual packer with focused probe. We discuss the decision process that governed the choice of pump, displacement unit, probe and packer. We pay particular attention to the unique pump configurations that were required to effectively manage the drawdowns when using the probe and also to allow sufficient flow rate when using the dual packer.

We conclude with a summary of recommendations and lessons learned for sampling in such an environment.
Modeling Production and Evaluating Fracture Performance in Unconventional Gas Reservoirs
Authors: Cipolla Craig L.
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

This article examines issues with forecasting and evaluating production from unconventional gas reservoirs such as those in the Barnett shale. How can reservoirs be commercial with matrix permeability measured not in millidarcies or even microdarcies (10-3md), but nanodarcies (10-6md)—typically, 10 to 100 nanodarcies? The key is maximizing the reservoir area that is connected to the wellbore by creating a very large manmade- fracture network. But how do we create a fracture network? The answer is large-volume high-rate hydraulicfracture treatments that use water and small-mesh proppant to "activate" or stimulate the existing natural fractures or rock fabric. The created fractures are far from the classic "planar" model; they are large, complex flow networks that typically encompass 50 acres or more where the rock has been "broken." Gas production is a function of the number and complexity of fractures created, the effective fracture conductivity, and the matrix permeability. Understanding the relationship between gas recovery and fracture complexity, fracture conductivity, and matrix permeability is a key component of economic shale-gas development. This article will highlight the application of reservoir simulation to model production in shale-gas reservoirs, providing significant insights into these relationships that can improve stimulation designs, completion practices, and field-development strategies. Currently, most shale-gas resources are being developed with horizontal wells, and the reservoir simulations in this article focus on horizontal completions.

Introduction

The exploitation of unconventional gas reservoirs has become an ever increasing component of the North American gas supply. Gas shales are organic-rich shale formations and are apparently the source rock as well as the reservoir. The gas is stored in the limited pore space of these rocks, and a sizable fraction of the gas in place may be adsorbed on the organic material. The success of the Barnett shale has led to the development of other shale plays in North America, including the Woodford, Haynesville, Fayetteville, and Marcellus. The natural-gas resource potential of gas shales is estimated to be between 500 and 1,000 Tcf (Arthur et al. 2008).
Microseismic Monitoring: Inside and Out
Authors: Warpinski Norm
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

Since its inception in the 1970s and its commercialization circa 2000, microseismic monitoring has proved to be an invaluable tool for understanding underground processes. While its most common and notable use has been hydraulic-fracture mapping, it also is used for reservoir monitoring of thermal processes, drill-cuttings injection, geothermal hot-dry- rock stimulations, reservoir surveillance, and many other processes in oil and gas and mining.

Fig. 1 shows a typical layout for a monitoring test, with the offset monitoring well at some reasonable distance from the fracture (inset) and a receiver array somewhere near the depth of the fracture treatment. Because the amplitude of the microseism decays with distance, there is a maximum monitoring distance that can be used in any test with respect to both horizontal and vertical positioning. Designed correctly, this type of monitoring can provide information on fracture height, length, azimuth, asymmetry, dip, and complexity, which can be used to optimize the fracture design and field development.

To most outsiders, the entire process of microseismic monitoring appears to be something of an art, and the "what," "why," and "how" details are not very clear even though there have probably been more than 6,000 fracture treatments monitored since 2000, in rocks ranging from tight sandstones and gas shales to carbonates and even volcanic, and at depths ranging from several hundred feet to more than 13,000 ft. The purpose of this article is to lay out a basic framework for planning, executing, analyzing, and interpreting a microseismic mapping project and, hopefully, add some rigor to the process that can be used for guidelines or standards.

Overview

Basically, microseismic monitoring is the placement of receiver systems in advantageous positions from which small earthquakes (microseisms) induced by some downhole process can be detected and located to provide geometric and behavioral information about the process. In the case of hydraulic fracturing—the process of primary concern here— a sensitive-receiver array having numerous levels typically is placed in an offset well at a depth relatively close to the process. This array detects the seismic energy generated by the microseism by use of three-component geophones or accelerometers, and then algorithms are processed to locate the "event" using an assortment of information obtained from compressional (P-wave) and shear (S-wave) arrivals detected by the array.
Parallelization of a Commercial Streamline Simulator and Performance on Practical Models
Authors: Batycky R. P. , Förster M. , Thiele M. R. , Stüben K.
Published: June 2014

We present the extension of a serial execution commercial streamline simulator to mulit-core architectures based on the OpenMP programming model and its performance on various field examples. This work is an extension of recent work by Gerritsen et al. (2008) in which a research streamline simulator was extended for parallel execution due to its intrinsically parallel algorithm.

We identified that the streamline-transport step represents the bulk of the run time (65%-85%). It is exactly this step that is straightforward to parallelize owing to the independent solution of each streamline that is at the heart of streamline simulation. Because we are working with an existing large serial code base, we used specialty software to quickly and easily identify variables that required special handling for implementing the parallel extension. Minimal rewrite to existing code was required to extend the streamline-transport step to OpenMP. As part of this work we also parallelized an additional 2% of the runtime code which included the gravity-line solver and some simple routines required for constructing the pressure matrix.

We tested our parallel simulator on a variety of models including SPE10, a Forties UK oil/water model, a Judy Creek waterflood/WAG model, and a Middle East dual-porosity model. We noted speedup factors of between 2.5× to 3.5× for 8-threads. In terms of real time, this implies that large-scale streamline simulation models as tested here can be simulated in less than 4 hrs. We noted speedup scaling results that were reasonable when compared with Amdahl's ideal scaling law. Beyond 8-threads we did observe reduced speedups and attribute this to memory bandwidth limits on our test machine (AMD 8× Opteron 8218 2.6Ghz dual core).
Remote Sensing, Fuzzy Logic and GIS in Petroleum Exploration
Authors: Taheri S. Reza
Published: June 2014

To reduce the exploration costs for hydrocarbons during the reconnaissance stage of exploration, satellite images and available surface data could be used. This paper identified three significant surface patterns which are considered promising; surface temperature derived from satellite data, vegetation cover and gas geochemistry. These were integrated and their correlation to the presence of petroleum investigated.

By employing GIS and fuzzy logic a dynamic model was developed which could be applied to any new petroleum exploration target using variable input data of that particular exploration target.

A selected study area consisted of 53 existing petroleum-reach areas within 20 ASTER (Advanced Spaceborne Thermal Emission and Reflection Radiometer) Granules. Each granule covers an area of 3600km2 (60 km x 60 km) of land in onshore Iran. 20 ASTER scenes over the study area were purchased from NASA and surface thermal data over these existing fields were retrieved from the satellite images.

The direction of land surface temperature (thermal anomaly) was analyzed using variograms which correlated well with the direction of petroleum reservoir locations. Variograms were used to study the trend and direction of thermal anomaly behaviour over the reservoirs. Many contributing factors such as geological units, meteorological conditions, time and the seasons of ASTER data acquisition, thermal conductivity of stratigraphic units of the study area and other sources (hot springs, power stations, producing wells etc…) were considered and fuzzy membership values for corresponding pixels in the processed ASTER images were assigned accordingly.

Spatial pre-processing and registrations of satellite data, together with spatial analyses consisting of Land Surface Temperature (LST) retrieval from ASTER data and removing the false thermal contributors to LST, were among the key processing procedures applied for the thermal data layer in the proposed GIS system.
Complex Effect of Connate Water in Vapour Extraction Process
Authors: Etminan S. Reza
Published: June 2014

The objective of this work was to study the effect of connate water in the progression of the Vapor Extraction (VAPEX) process for heavy oil recovery. A large fraction of the physical model tests of the VAPEX process reported in the literature have been conducted without any connate water in the system. The absence of connate water was rationalized by suggesting that it has little or no influence on relative permeability of oil and since the vaporized solvent does not dissolve in water, there is no effect of water on the mass transfer process.

We have evaluated the effect of connate water on VAPEX performance using physical model experiments carried out in a visual model, with different connate water saturations. Butane was used as the solvent and fine Ottawa sand was used for packing the model to obtain permeability and capillary pressure values comparable to the field conditions. In addition to the visual observations of the size and shape of the vapor chamber, the rates of oil and gas production were monitored during the experiments.

The results show that connate water has a measurable effect on the process, both in terms of the shape of the vapour chamber and the drainage rate of the diluted oil. The presence of connate water causes faster spreading of the vapor chamber in the lateral direction and tends to increase the thickness of the mixing zone. This increase in the mixing zone thickness appears to result from capillarity driven fingering phenomenon. The mixing zone had a distinct uneven appearance that was similar to patterns generated by frontal instabilities in miscible displacements. The effect of connate water on drainage rate was an increase in the initial rate but a reduction in the rate subsequently. The presence of mobile water speeds up the communication between the two wells and leads to even faster spreading of the vapor chamber. Finally, the de-asphalting and oil upgrading was more significant in the presence of connate water.