bluuebunny/crossref_metadata_2025 huggingface dataset:
Subsurface Capability Building
Authors: Kloosterman H. J.
Published: October 2014

Shell has implemented in the last few years a structured new approach for the capability building for its graduate recruits as well as its mature hires, with the objective to shorten the time to autonomy. Two structured programmes, the Shell Graduate Programme (SGP) and the Shell Advanced Technical Programme (SATP) have been specially designed for this purpose. These programmes form part of the overall talent pipeline in Shell for building technical Capability (Figure 1) and link to a simplified competence framework set-up, in which proof points are defined for each competence, allowing for consistent assessment of capability building progress. Both programmes follow a blended learning approach, integrating formal and informal learning through work-based activities.

The Subsurface Learning portfolio (covering Reservoir Engineering, Petrophysics & Geomechanics, Production Geology, Geophysics, Exploration Evaluation, Geomatics & Data Management) consists of some 100+ global as well as some 70+ regional courses (some 400+ learning events in 2013), delivered by 15 Full-time Learning Advisors, supported by some 100+ technical experts from the business. On average, some 10+ new subsurface courses are developed every year.

The latest developments in Subsurface Learning delivery focus on the integration of "Digital Geology" through augmented reality techniques with static and dynamic reservoir models, carried out at the relevant scale to support the associated business decision. These cross-discipline learning events will initially take place in Shell's 3D-visualisation centre in Rijswijk, the Netherlands (iScope), to be subsequently rolled-out to other Shell-locations. This paper will present an overview of the latest developments in Subsurface Learning in Shell, as described above.
Methodology To Estimate The Chance Of Success Of A Time-Lapse Seismic Project Using Reservoir Simulation
Authors: Ferreira Carla J , Schiozer Denis J.
Published: October 2014

Time-lapse seismic technology has been successfully used in the petroleum industry. It provides important information regarding properties of the reservoir between and beyond the wells; 4D (time-lapse) seismic data is used as input for several processes, such as: well planning/completion; geological model constraining and reservoir simulation history matching. However, there are technical issues to be addressed before starting a 4D seismic project. Several geophysical studies use the chance of success concept to identify favorable cases; evaluating the seismic survey and the magnitude of seismic changes. However, from an engineering point of view it is important to evaluate the chances of business success, which relies on the use of the new information to identify infill well locations, increase the predictive capability of reservoir simulations, optimize the reservoir performance and develop well intervention programs. A 4D seismic project is considered an economic success if the impact on field operations generates more monetary benefit than the acquisition cost. The complex estimation should be based on field uncertainties and decision analysis. Given the importance and difficulty of predicting economic success, this paper presents a methodology to estimate the chance of success of a 4D seismic project from the engineering perspective applied to a synthetic model. The methodology was applied to a synthetic reservoir model to obtain a first estimate of the chance of success of a 4D seismic project for a specific production period. The process was performed in the developing phase and it comprises several methodologies such as: risk analysis, representative models selection, production strategy optimization and value of information concept. The presented methodology provides information of the chance of success of a 4D seismic project at a specific production period assisting the decision maker to evaluate the need for further analysis or to establish the acquisition or not of 4D seismic data. This decision is taken considering the acquisition cost, the increase of NPV due to new data and other influential factors. Thus, the main benefit derived from the acquisition of 4D seismic data was on the identification of remaining oil areas. Time-lapse seismic data has been successfully used in reservoir monitoring; several published cases report the success of its use in the improvement of production efficiency. But it is important to predict if acquiring new information will be profitable before the acquisition. This is a complex but essential part of time-lapse seismic reservoir management.
Dynamic vs. Static Ranking: Comparison and Contrast in Application to Geo-cellular Models
Authors: Kelkar M. G. , Pochampally S. , Bahar A. , Sharifi M.
Published: October 2014

With increasing computational power, large geo-cellular models are constructed comprising of multi-million cells. Using uncertainty work flows, large number of geo-cellular models (realizations and scenarios) are constructed which can incorporate uncertainties in static parameters. The typical number of geo-cellular models can range between as few as thirty to as high as hundreds or even thousands. Once these models are constructed, the geo-modeler as well as simulation engineer realizes that all these models cannot be flow simulated without significant upscaling. Therefore, a search begins to find a method which would cost effectively select just a few of these geo-cellular models which can bracket the uncertainties present in these models.

Static methodologies, which rank these realizations based on static properties such as Hydrocarbon Pore Volume (HPV) or STOIIP/GIP may not truly represent the ranking based on actual performance of the reservoirs. For example, a reservoir which contains large HPV but is not well connected will ultimately produce less oil/gas than a reservoir which is well connected but contains less HPV. We, therefore, need a ranking based on dynamic characterization of the reservoir.

We have developed methodology based on Eikonal equation which can rank multiple realizations extremely efficiently. The method determines the time it takes for a traveling of a pressure "wave" to reach a particular grid block from a given well and assumes that time it takes to "tag" a grid block will reflect how quickly that grid block can be drained from a given well. Unlike finite difference or streamline simulation, the method does not require solving any matrix; hence, it is unconditionally stable. In matter of few minutes, a geo-cellular model containing more than fifty million cells can be interrogated.

Using both synthetic and field examples, we demonstrate that the ranking based on our methodology is consistent with the ranking one would obtain using finite difference simulator. Further, ranking based on static properties does not correlate well with the dynamic response of the reservoir. By using the proposed methodology, limited number of geo-cellular realizations can be selected which can capture true dynamic uncertainty in reservoir performance.
A Combined Bottom-hole Pressure Calculation Procedure Using Multiphase Correlations and Artificial Neural Network Models
Authors: Li X. , Miskimins J. L. , Hoffman B. T.
Published: October 2014

The desire to have accurate bottom-hole pressure (BHP) data can come during different phases of a well's life, including well design, mini-frac test, well testing, and production analysis. But frequently, it is not practical, feasible, or economic to deploy a pressure gauge to measure the BHP directly. In most cases, however, the unknown flowing BHP is calculated from the known parameters and surface measurements using multiphase correlations or mechanistic modeling. Recently, artificial neural network (ANN) techniques have been adopted to predict BHP and proved to have better prediction performance than other conventional prediction methods. With the design applied in this study, the use of ANN techniques can be more fully utilized to solve complex multiphase flow problems, such as pressure gradient prediction and complex well trajectories.

Back-propagation (BP) neural network models have been modified to fit into the piece-wise calculation procedures of multiphase correlations to achieve higher prediction accuracy and broaden the prediction range. The model training requires well-segment-scale data sets, which contain pressure gradients as the model output and the model inputs, including inclination angle, liquid and gas superficial velocities, gas-liquid surface tension, liquid density, specific gravity of free gas, liquid and gas viscosities, average pressure and temperature. Different BP neural network model structures have been tested to find a suitable neuron number in the hidden-layer of the model. Two pressure gradient prediction models were trained for slug flow and annular mist flow.

Ultimately, a combined BHP calculation procedure was designed combining the multiphase correlations and trained ANN models. The statistical tests using the collected data showed that the combined procedure gave the best prediction performance against the eleven multiphase correlations studied in this work and had the lowest average absolute percent error of 3.1% and standard deviation of 0.034. Independent field data was used to test the extendibility of the combined procedure prediction range. Comparing to the multiphase correlations, the combined procedure gave fairly accurate predictions with an average absolute percent error of 23.0% and a standard deviation of 0.176. To facilitate field application, a multiphase flow BHP calculator with a user interface was developed.
Development of Improved Testing Procedure for Wells with Sustained Casing Pressure
Authors: Kazemi Mohammad , Wojtanowicz Andrew K.
Published: October 2014

In the US, the Bureau of Safety and Environmental Enforcement (BSEE) regulations require pressure bleed-down/buildup (B/B) testing of wells with annular Sustained Casing Pressure (SCP) if the casing head pressure is greater than 100 psig. The test involves bleeding the pressure with a needle valve followed with up to 24-hour monitoring pressure return after the valve is closed. As the test description is limited to its principle, the way it is actually performed varies considerably among operators leading to different results.

Analysis of B/B tests described in the API standards is merely qualitative and limited to the finding if pressure could be bled to zero and if it would re-build to its initial value before the test. Needless to say, the two findings might depend upon the way needle valve has been operated and also they do not provide any quantitative information about gas migration in the leaking cement. Quantitative analyses methods and models have been already proposed, but – as shown in the paper – they either produce ambiguous results or they have oversimplifying assumptions that lead to widely-spread estimations of the cement leak size by orders of magnitude.

The presented work is a study of the B/B testing as a source of useful information for SCP problem assessment and remediation. Simulation software based on improved mathematical model of SCP well is used for theoretical parametric study of the testing process. Analysis of variance and multivariate regression method consider four unknown system parameters to be determined from the test (length and permeability of the leaking cement, and length and compressibility of the annular fluid above the cement). The study qualifies significant system parameters controlling each of the three stages of the B-B test: pressure bleed-down, stabilization and buildup. The results show that significance of these parameters varies between the stages. The finding indicates that B-B test should involve three stages – instead of two stages presently practiced. Also, the results show merit of a stage-by-stage analysis of the test instead of trying to find all system parameters by matching the whole test.

In addition, three operational parameters of the B-B test (bleeding rate and time, and pressure recording time step) are evaluated to see how they affect test results in view of possible improvements in the testing procedure. It is shown that the operational parameters have significant effect on well response and may cause misinterpretation of test results. Early closure the bleed valve prior to gas flow stabilization would not indicate the true bleed-down pressure and produce pressure buildup that misrepresents the cement leak size.
CFD Simulation of ESP Performance and Bubble Size Estimation under Gassy Conditions
Authors: Zhu Jianjun , Zhang Hong-Quan
Published: October 2014

As a high-efficiency tool to convert rotating kinetic energy to hydraulic pressure head, the electrical submersible pump (ESP) is widely used in the petroleum industry to increase hydrocarbon fluid production rates. Previous studies showed that the presence of gas would cause ESP hydraulic head degradation. Flow behaviors in ESPs under gassy conditions, such as gas pockets, further deteriorate ESP performance. It is important to investigate flow structure inside ESPs with gas involvement. In this paper, we use Computational Fluid Dynamics (CFD) to simulate fluid flows through an entire ESP stage, including impeller and diffuser. We also calculate the corresponding heads under both liquid and gas-liquid flow conditions. Additionally, the pressure field, velocity profile and gas distribution inside ESPs are analyzed. The commercially available CFD software was used for geometry editing, mesh generating, finite-volume-method solving and post-calculation. Sensitivity analysis of meshing was also conducted.

The CFD simulation results of ESP performance under single-phase water conditions matched manufacturer performance curves. For two-phase flow simulation, water and nitrogen were used as working fluids with different gas volume fractions (GVF) from 1.0% to nearly 20% and considerable degradation of pump performance was observed. In contrast to previous simulations in the literature using constant bubble sizes, our simulation results reveal that bubble size is a key factor related to an increase in GVFs. The CFD simulation results were compared with experimental measurements from the Tulsa University Artificial Lift Projects (TUALP) and good agreement was achieved under both single and two-phase conditions. The observed results using proper bubble size estimation indicated that CFD simulation is a reliable tool for analyzing ESP performance.
Characterization of Asphaltene Transport over Geologic Time Aids in Explaining the Distribution of Heavy Oils and Solid Hydrocarbons in Reservoirs
Authors: Mullins Oliver C. , Wang Kang , Chen Yi , Hernandez Diana , Pomerantz Andrew E. , Zuo Julian Y. , Hammond Paul S. , Dong Chengli , Elshahawi Hani , Seifert Douglas J.
Published: October 2014

Asphaltenes are a very important component of reservoir fluids. They have a huge impact on crude oil viscosity and are a Flow Assurance concern. They can undergo a phase transition, giving rise to tar mats that seal aquifers precluding aquifer sweep. Local tar deposits can act as a drilling hazard. Upstructure tar (or bitumen) deposition can occur which can flow with produced light hydrocarbons greatly reducing the productivity index. In EOR, miscible gas injection can also give rise to asphaltene deposition. Characterizing these disparate observations is now performed within a simple overarching framework. Here, we combine asphaltene nanoscience, thermodynamics, and fluid mechanics to model asphaltene-rich fluid flow and asphaltene deposition that occur in reservoirs in geologic (or even production) time. This analysis successfully accounts for extensive measurements in several reservoirs in different stages of similar processes. Reservoir black oils with a late, light hydrocarbon charge experience asphaltene instability. This instability does not necessarily cause precipitation; instead, weak instability can cause a change in the nanocolloidal character of asphaltenes without precipitation. Consequently, this less stable asphaltene remains in the crude oil and is thus mobile. This process can result in fluid density inversions and gravity currents that pump asphaltene ‘clusters’ in oil over reservoir length scales relatively quickly in geologic time. These asphaltene clusters then establish very large asphaltene and viscosity gradients at the base of the reservoir. If the light hydrocarbon instability event continues, a regional tar mat can form. In contrast, if the light hydrocarbon charge is sufficiently rapid, the displacement of the contact between the original and new reservoir fluids overtakes and precipitates asphaltenes locally producing deposition upstructure often near the crest of the field. In this paper, several reservoirs are examined. Two reservoirs have massive, current gas charge and have bitumen deposition upstructure. Another reservoir is shown to be midway through a slower gas charge, with the asphaltene instability causing migration of asphaltenes from the top to the base of the oil column in the form of clusters creating large asphaltene gravity gradients. Another reservoir is shown to have this process completed yielding a 50 meter column of heavy oil at the base of the oil column underlain by a 10 meter regional tar mat. This integrated analysis enables a much simpler understanding of many production issues associated with asphaltenes and provides a way forward for treating disparate asphaltene problems within a single framework.
Environmentally Friendly Fracturing Fluid as Utilized in a Western Canada Sedimentary Basin Case Study
Authors: Nixon Tara , Tomszak Jay , Lawrence Sally , Richardson Lee , Hepburn Krista
Published: October 2014

In recent years, the oil and gas industry has been highly focused on reducing the environmental footprint caused by hydraulic fracturing fluids. This parallels society's fixation on developing "greener" technologies and processes. Environmentally friendly or "green" is a vague term referring to processes and products that reduce or eliminate any impact to human health and the environment (US EPA, 2014). Although this is a common goal among those in the oil and gas industry, there is a lack of structure around what defines "green." The definition varies across continents, governing bodies, companies, departments, and individuals, with each employing a different set of criteria they deem relevant. Developing a process for environmentally responsible fracturing without a clear and accepted definition is a cumbersome undertaking.

This paper describes a process by which the concept of safer and "greener" hydraulic fracturing operation can be accomplished, with a strong focus on the chemical components of the fracturing fluid. The discussion will center around: health and safety of personnel, environmental impact of utilized chemistries, geographical applicability in conjunction with corresponding local regulatory policies, and an in-house developed chemical hazard rating system. The application of this process will be described through a case study which includes more than 100 pumped intervals in multiple geographic areas. The case study provides: stimulation job designs, treatment reports, and production results.

Once a specific set of criteria has been established, a system that meets the aforementioned criteria needs to be developed. This process entails evaluation of each system component for environmental applicability and system performance. Additionally, through collaboration with chemical manufacturers, toxicologists, and fluid experts, the technical accuracy and applicability of toxicological data can be determined. A cradle-to-grave development of a foamed linear fluid system will be the example illustrated in this paper to showcase the development and implementation of a "green" hydraulic fracturing fluid system. This specific system encompasses a significantly reduced environmental profile in comparison to similar systems, while maintaining equivalent performance and overall cost to customer. The fluid system has been optimized and continues to be pumped with great success.
Development of Reduced-order Oil Reservoir Models using Localized DEIM
Authors: Yoon Seonkyoo , Alghareeb Zeid M. , Williams John R.
Published: October 2014

For applications of numerical reservoir simulators such as production optimization or uncertainty assessment, hundreds or thousands of reservoir simulation runs must be performed. Such huge computational cost is a major problem in petroleum engineering, and reduced-order model (ROM) based on proper orthogonal decomposition (POD) has been intensively studied in recent decade to overcome it. While POD-based methods have been shown to be efficient compared to full order model (FOM), it is not as efficient when it is applied to a typical large dimensional nonlinear reservoir system. One of the reasons for the inefficiency is that in a typical nonlinear reservoir system ROM based only on POD is still dependent on the dimension of FOM. This is due to the fact that to compute the reduced nonlinear term in mass balance equation of a reservoir system, one must first reconstruct the full-order state solution such as pressure and saturation, evaluate the full-order nonlinear term before projecting it onto a reduced subspace. Therefore, we developed a reduced-order reservoir model based on a discrete empirical interpolation method (DEIM) to approximate nonlinear phase potential terms so that the repeated online evaluations of the ROM in Newton iteration are independent of full-order dimension. The independence comes from the fact that DEIM just needs to evaluate the nonlinear term only at interpolation indices that represent grid blocks that are important in terms of preserving the continuity properties of the mass balance equation. A case study was carried out to investigate the performance of DEIM compared POD. Although the testing schedule of well controls is far apart from the training schedule of well controls, close matches are obtained. Thus, the ROM using DEIM is expected to enable the practical application of reservoir simulator, such as production optimization in which many simulation runs must be performed, in a reasonable time frame by significantly relieving the required numerical effort.
Detecting Fracture Growth Out of Zone Using Temperature Analysis
Authors: Ribeiro Priscila M. , Horne Roland N.
Published: October 2014

Hydraulic fracturing is a widely applied well stimulation technique. Recently the application of multiple hydraulic fractures along horizontal wells has made possible the exploitation of unconventional reservoirs, such as shale gas and shale oil. However, the process of horizontal well fracturing is uncertain and it is not fully understood yet. There exist many questions about the number and position of created fractures and whether or not the fracture stays contained within the main reservoir thickness.

This work presents the modeling and analysis of temperature data during and after the creation of multiple fractures along a horizontal well. Our model accounts for fracture growth and closure, the well effects and interaction between multiple fractures.

The interference between multiple fractures growing simultaneously and the presence of reservoir permeability heterogeneity were investigated. Capabilities and limitations of information carried by temperature data are presented through different geometry analyses.

A special consideration of fracture growth out of zone was addressed. For this case it was considered that one of the hydraulic fractures activates a preexisting fault and interconnects the reservoir with other zones hundreds of feet away.

Our work shows the advantage of using continuous distributed temperature data in comparison with the traditional single-point pressure analysis. The local characteristic of temperature allows us to identify not only which of the created hydraulic fractures has interconnected the main reservoir with a different zone, but also the location of this zone. We also account for the effect of the interconnection on the growth of the other hydraulic fractures along the horizontal wellbore.

The simultaneous multiple fracture growth shows that falloff distributed temperature data can predict the number of created fractures. More than that, in presence of heterogeneity the interaction between the contained fractures can be captured by the temperature analysis. Different from the pressure analysis, distributed temperature data can differentiate between different heterogeneity locations along the wellbore.

Throughout this paper we present a series of examples where the temperature can provide information that would not be obtained from the traditional pressure analysis.
Autonomous Inflow Control Valves - their Modelling and "Added Value"
Authors: Eltaher Eltazy , Muradov Khafiz , Davies David , Grebenkin Ivan
Published: October 2014

Wells equipped with inflow control devices (ICDs) are a proven method of improving sweep efficiency by passively controlling the influx of fluids into the well by the addition of a restriction to each completion joint. The application of ICDs is also essential to development of some oil fields previously found to be uneconomic. The ICD-completion design is a complex process requiring selection of the ICD restriction size, ICD type, and annular flow isolation (AFI). Several commercial ICD designs are now available, each of which react differently to the flowing fluid properties. This complicates the completion design process, which often requires the ICD completion to be specified against a poorly known reservoir and well performance prior to drilling the well. This adds a requirement for the ICD completion to improve oil recovery in a range of potential production scenarios.

Unfortunately ICDs do not provide an optimal well design after breakthrough of the unwanted phases, despite their ability to balance the well inflow profile and achieve a uniform sweep towards a horizontal well in early years. Field experience has taught that ICD completions balance the well influx initially, but may not offer the optimal solution throughout the well's life due to the changes in the inflow conditions as the well matures. The recently introduced Autonomous Inflow Control Device (AICD) aims to restrict unwanted phases (gas and water), (partially) overcoming the results of reservoir uncertainty at the well completion design stage.

Autonomous Inflow Control Valves (AICVs) are the next generation of flow control technology, being designed to virtually shut-off unwanted fluid inflows at completion joints. This paper describes the first AICV modelling workflow for integrated well/reservoir simulators. Its application allows reservoir and well engineers to quantify the value added by the optimal use of this new, down-hole completion technology.

The workflow has been used to compare the performance of advanced well completion options (AICVs and ICDs) in a synthetic, oil-rim reservoir model mimicking a larger North Sea field where production is dominated by gas-coning problems. Down-hole flow control with AICVs significantly increased oil recovery compared to ICDs and conventional wells employing wellhead choke control. Unwanted fluid production was also reduced by up to 80%; a result that combines higher oil recovery with more efficient use of reservoir energy by the AICV completion.
Profile Formulation of the Future Petro Technical Professional in Argentina
Authors: Abalos R. , Erdmann E. , Gallardo F. , Sidoruk B. , Osses J.
Published: October 2014

The objective of this paper is to formulate a Petro Technical Professional profile in Argentina to propose a new academic curriculum.

Argentinean university's curricula analysis is performed trying to elaborate the actual profile of the Petroleum Engineering Professional.

An analysis of the energetic situation and the petroleum industry needs in Argentina is also carried out attempting to know the work situation in which the future graduate will be immersed.

Unconventional oil and gas resources in Argentina and their potential exploration and improvement were decisive to initiate this work. New opportunities in this direction will be presented for future professionals so academic curricula should be adapted to follow them. The environment is also taken in consideration as an important topic to be included.

It is remarkable to mention the participation of two Petroleum Engineering's students in this work.
A Comparison of Proppant Erosion during Slurry Injection
Authors: Frosell Thomas , McGregor Molly , Ross Colby
Published: October 2014

During frac-pack treatments, proppant erosion is often a limiting factor for the allowable flow rate and total volume of proppant pumped during the job. Each completion assembly has a rating based on limited amounts of full scale erosion testing which is typically provided for one or two types of proppant. Previous testing results have shown that different types of proppant, such as lightweight ceramic (LWC), intermediate strength proppant (ISP), and high-strength proppant (HSP) have different erosion rates.

A jet impingement test facility was used to compare different sources of proppant for each of the commonly used proppant types. The test facility was designed to replicate the downhole conditions, while providing the capability to control the test parameters. A nozzle diameter was selected to represent the typical flow-structure size within the completion equipment and a linear gel with proppant loadings between 2 and 10 PPA was selected for the test slurry. The test coupons were low-alloy steel with a representative heat treatment of the material used for downhole equipment. The results were analyzed by measuring mass removal and the 3D erosion profile to compare the overall erosion rate in each test, as well as the erosion profile produced by the various proppants. Furthermore, the proppant was inspected using a laser confocal microscope to provide comparisons between proppant types and sources.

The test results, presented in this paper, show that different sources of proppant within a single type of proppant can lead to significantly different erosion rates. Comparison between two sources of HSP showed that there can be a variation in erosion rate of over 60% and that the variation in erosion rate can double when comparing two sources of ISP. These results have verified that proposed changes, such as changing the proppant from what was tested originally for the frac-job operation, can affect the erosion within the completion equipment. Therefore, it is of critical importance to evaluate the possible effects of any change to ensure that the rating of the tool will not be exceeded.
Relative Permeability Normalization – Effects of Permeability, Wettability and Interfacial Tension
Authors: Jahanbakhsh Amir , Shahverdi Hamidreza , Sohrabi Mehran
Published: October 2014

The relative permeabilities (kr) are crucial flow functions governing the fluid distribution within and production from the petroleum reservoirs under various oil recovery methods. To obtain these important reservoir parameters, conventionally, it is required to take rock samples from the reservoir and perform appropriate laboratory measurements. Although, kr is expressed as a function of fluid saturation, it is now well-known that kr values are affected by; pore structure and distribution, absolute permeability, wettability, IFT, and saturation history. These rock/fluid properties often change from one region of the reservoir to another but it would be impossible to perform kr measurements for all regions of a reservoir. Generally, performing experiment on a core with higher permeability is faster and easier than a low permeability rock. Therefore, assuming all other parameters such as wettability, IFT, and displacement direction are the same for two rocks with different permeability, the question is, how do we estimate the kr of a rock with lower permeability from available (measured) kr of a higher permeability rock? How do we account for wettability and IFT differences? Normalization techniques have been proposed to remove the effect of irreducible water and trapped saturations, which would be different under different conditions. The relative permeabilities can then be de-normalized and assigned to different regions (rock types) of the reservoir based on their own irreducible water and trapped saturations.

The objective of this study is to predict the kr for a new rock/fluid conditions (i.e., permeability, wettability, IFT) using existing kr data measured at different conditions. Using measured data from coreflood experiments, we show that by applying an appropriate normalization technique one can adequately predict kr of rocks with different permeability and wettability conditions in two-phase flow. However, the results show that the effect of IFT change cannot be captured by normalization techniques. To improve the methodology, a new hypothesis is introduced and proposed here based on Dynamic Trap Saturation. Finally, using our experimental data, we evaluate the validity of Coats IFT scaling method. We demonstrate the shortcomings of the method and offer an improvement to its prediction.
Long-Time Diversion in SAG Foam Enhanced Oil Recovery From Field Data
Authors: Rossen W. R. , Ocampo-Florez A. A. , Restrepo A. , Cifuentes H. D. , Marin J.
Published: October 2014

The ability of foam to divert gas flow over a long period of gas injection in a Surfactant Alternating Gas (SAG) foam process is important for the economics of foam-diversion processes for enhanced oil recovery. Here we interpret field data from the foam test in the Cusiana field in Colombia, South America (Ocampo et al., 2013). In this test surfactant was injected into a single layer that had been taking about half the injected gas before the test; then gas injection resumed into all layers. Based on the size of the surfactant slug injected and estimates of adsorption and of water saturation in the foam in situ, we estimate that the treated region extended about 5.3 m from the injection well: fortunately the results to follow are not sensitive to this estimate. Based on the change in injection logs before the test and at day 5 of the test, when approximately 30 pore volumes of gas has been injected, foam still reduced gas mobility in the treated layer by about a factor of 9. We base this estimate on the decrease of injection into the treated layer and the increase into the other layers; the results are consistent among the layers. After 35 and 152 days of injection (220 and 1250 pore volumes gas injected), foam reduced gas mobility in the treated zone by about a factor of 4 and 2, respectively.

This result suggests that foam continued to reduce mobility by a modest amount even after long injection of gas. In this test, the large volume of gas had quickly penetrated far beyond the edge of the surfactant bank. In a design where a larger bank of surfactant were injected, a much greater and longer diversion of gas would be expected. On the other hand, foam did weaken progressively as it dried out. Foam models where foam remains strong at irreducible water saturation would greatly overestimate foam effectiveness at long times in this test.
Oil Relative Permeability During Enhanced Oil Recovery by Foam Flooding
Authors: Heins R. , Simjoo M. , Zitha P. L. , Rossen W. R.
Published: October 2014

A previous study (Simjoo and Zitha, 2013) reports enhanced oil recovery by foam injection in corefloods: that is, reduction in oil saturation in the core below waterflood residual. This reduction is achieved by foam in a process with reduced oil-water interfacial tension and increased pressure gradient. Those results, combined with bubble-column experiments, suggest that a new mechanism of oil recovery is involved in these floods: emulsification of oil into the Plateau borders between the bubbles of the foam and transport of oil along with the foam bubbles.

Using these data we compute the oil relative permeability during this process of enhanced oil recovery. There is an initial oil bank with oil relative permeability of order 0.1. Thereafter, during the period of highest capillary number and oil production attributed to emulsified oil droplets, oil relative permeability is between 0.001 and 0.0001: far less than with surfactant flooding, for instance, at similar capillary number. Over time in these experiments, the final oil saturation is greater than, but is slowly approaching, that expected at the large capillary number of the experiment. Since in the proposed mechanism emulsified oil must travel with the foam, which has extremely large effective viscosity, but oil relative permeability is computed based on the much-smaller oil viscosity, the low oil relative permeability can be seen to be result of strongly adverse viscous coupling between the phases. Efficient oil recovery by the mechanism of emulsified oil droplets would require a large volume fraction of oil within the foam, a less-viscous foam, and/or a more-viscous oil. Other studies of foam displacing oil briefly examined here reflect a larger oil relative permeability during foam displacement, in large part because of a smaller contrast between foam and oil viscosity, or even a foam effective viscosity less than that of the oil it displaces.
Ensuring The Safety Of Onsite Personnel And Neighboring Community During Workover And Well-testing Activities With A High H2S Risk Potential – A Case Study
Authors: Ferrante Andrea , Daher Elie , Warwick Hugh
Published: October 2014

OMV Petrom had a planned workover and well-testing activity on a well with high potential concentration of hydrogen sulfide (H2S) located 200 meters from a neighboring community. To ensure safety during the workover and well-testing activity, a leading oil and gas group in Central Europe undertook a careful preparation of processes, systems and its personnel. Considering the proximity of the wellsite to the community, they also needed to inform and educate the surrounding community.

Servizi Integrati di Sicurezza (S.I.S. S.r.l.), part of United Safety International Group was given the task to ensure the safety of personnel and neighboring community through effective preventive actions including extensive H2S training and prevailing wind monitoring. A site-specific Emergency Response Plan (ERP) was developed that defined the coverage of the Emergency Planning Zone (EPZ). Wind speed and direction was monitored for a period of four months prior to the drilling activity which allowed the identification of high risks areas in the event of a gas release.

A dedicated wireless H2S and sulfur dioxide (SO2) gas detection system was installed including a general alarm system for public awareness in case of a public evacuation. Rovers were dispatched continuously to monitor remote areas of the EPZ. The safety solutions company conducted H2S drills, man down simulations, and public evacuations in coordination with the operator and the local community. Prior to commencement of drilling activities, nearly 400 training certificates were released to personnel, contractors and sub-contractors.

This paper discusses lessons learned and best practices of emergency planning and management of the EPZ as critical elements of drilling operations. It highlights the continuous improvement of EPZ management methods and discusses the importance of engaging affected communities and residents to build confidence, partnerships and ultimately boost a company's public image. The paper also demonstrates the impact of corporate citizenship and responsible care practices beyond the immediate community.
How Intelligent Coiled Tubing Technology Combined with Realtime Downhole Camera Visuals Created a Formula for Success During a Challenging Thru-Tubing Recompletion Operation in the North Sea
Authors: de Jonge R. M. , Tousis U. , Nijenhuis J.
Published: October 2014

A North Sea gas well was drilled and completed in 2000. Soon after the well was put in production, sand was also produced and became a major problem. Since the process system on the satellite platform was not capable of handling the sand, sand screens were installed in the well to prevent any further sand production. During the following years the sand screens became completely blocked and production ceased. The well was shut in for the next 10 years until a thru-tubing recompletion program was executed: milling out the permanent packer, fishing and retrieving the existing sand-screens and installing 130 m of new screens in a live well, all with 2 3/8–in. intelligent coiled tubing (CT).

Intelligent CT interventions are operations in which rea-time downhole data is used to improve operational efficiencies. The realtime downhole data that can be obtained during CT operations include accurate depth correlation, pressures, differential pressures and temperatures. In combination with a realtime downhole camera, the high quality of data proved to be very valuable during the decision-making process, since the actual downhole situation can be assessed while many uncertainties are being eliminated. The visuals obtained by the camera played an important role in the choice of fishing tools and in discovering the exact position of fish and packer elements.

This paper describes the challenges, the operational execution and the lessons learned from the recompletion project. It also explains in detail the operational aspects of the intelligent CT and how it was beneficial to the successful execution of the intervention program.

Following the successful operation, the well was produced through the well test package on board the support jack-up, and production figures exceeded expectations. After this initial well, interventions in several more wells followed, whereby thru-tubing sand screens were installed with use of intelligent CT.
Accelerated Oil Droplet Separation from Produced Water Using Magnetic Nanoparticles
Authors: Ko Saebom , Prigiobbe Valentina , Huh Chun , Bryant Steven , Bennetzen Martin V. , Mogensen Kristian
Published: October 2014

The treatment of highly stable small oil droplets in produced water is challenging for offshore production, where platform space is constrained, because their long residence time requires large equipment volumes. The use of magnetic nanoparticles (MNPs) to remove dispersed droplets is a promising alternative due to their quick response to external magnetic field, allowing easy separation of oil droplets on which MNPs were attached from water. The goal of this study is to prove the concept of magnetically separating oil droplets from produced water using surface-coated MNPs. Batch-scale experiments were performed and they showed that droplets in 5 wt. % of decane-in-water emulsions, which have negative surface charges, were successfully separated from water using cationic surfactant-coated MNPs, with decane removal efficiency of 85 to 99.99%, depending on the experiment conditions. Anionic surfactant-coated MNPs did not remove oil droplets, indicating that the electrostatic attraction between emulsions and MNPs control the attachment of the MNPs to the droplet surface. The settling velocity of a droplet coated with MNPs was derived by extending classical theory to account for the magnetic force as well as buoyancy and drag forces. Under the applied experimental conditions and considering the geometry of the oil-water-MNP system, velocity calculations show that the droplet settles spontaneously when a magnetic field is applied. Otherwise the MNP-coated oil droplets (MNP-droplets) would naturally migrate upwards due to buoyancy. The velocity of a single MNP-droplet is strongly dependent on the intensity of the magnetic field and it changes up to three orders of magnitude within the height of tested sample of approximately 3 cm.
Permeability of Organic-rich Shale
Authors: Wasaki Asana , Akkutlu I. Yucel
Published: October 2014

Measured permeability of an organic-rich shale sample vary significantly with applied laboratory conditions, such as the confining pressure, temperature and the measurement fluid type. This indicates that the measured quantity is influenced by several mechanisms that add complexity to the measurement. The complexity is mainly due to stress dependence of the matrix permeability. Also, it is due to the fact that organic-rich shale holds significant volumes of fluids in sorbed (adsorbed, dissolved) states, sorption can also influence the permeability through its own storage and transport mechanisms. The stress-dependence and sorption effects on permeability could develop under the reservoir conditions and influence the production, although we currently do not have a predictive permeability model that considers their co-existence.

In this work this is accomplished by considering that the shale matrix consists of multiple continua with organic and inorganic pores. Stress-dependency of the permeability comes along with slit-shape inorganic pores, whereas the sorption effects are associated with nano-scale organic capillaries. A simple conceptual flow model with an apparent shale permeability is developed that couples the molecular transport effects of the sorbed phase with the stress-dependence of the inorganic matrix.

Sensitivity analysis on the new permeability model shows that the stress-dependence of the overall transport is significant at high pore pressure, when the effective stress is relatively low. Diffusive molecular transport of the sorbed phase becomes important as the stress gets larger and, hence, the inorganic pores close. The constructed apparent permeability versus pore pressure curves show the dominance of the molecular transport as permeability improvement characterized by appearance of a minimum permeability value at the intermediate values of the pressure. The new permeability model can be used easily in history-matching a well performance and optimizing its production.
Analysis and Interpretation of Haynesville Shale Subsurface Properties, Completion Variables, and Production Performance Using Ordination, a Multivariate Statistical Analysis Technique
Authors: Eburi S. , Jones S. , Houston T. , Bonelli J.
Published: October 2014

Shale plays have been considered statistical plays by many people in our industry. During the early years of the shale boom and even today, technical teams have looked to find correlations between variables to help explain well performance. Simple one-to-one correlations between individual variables and production performance in the Haynesville Shale appear to be weak because complex relationships may exist. Regression analysis techniques have assumptions and limitations, moreover, such techniques encounter difficulties when analyzing complex relationships. In this study, ordination, a multivariate analysis technique, was applied to subsurface and completion data to identify the variables that seem to influence well performance. The debate of nature versus nurture has often been applied to shale gas developments where some believe an effective well completion can make up for a poor shale reservoir rock quality while others believe a high quality shale reservoir rock is essential to obtain better producers despite an average well completion. The ordination technique successfully separated better performing wells from the less prolific wells and identified the variables that characterize the better producers. The same technique provided various optimum ranges for the different variables that could be used to identify core and non-core areas within the play. Our results suggest that (1) ordination is a viable method for multivariate statistical analysis in the Haynesville Shale; (2) subsurface variables are critical in obtaining better performing wells; and (3) completions variables are secondary but also very important.