bluuebunny/crossref_metadata_2025 huggingface dataset:
Channelling Detection Using Data-Driven Models
Authors: Moreno G. A. , Garriz A. E.
Published: November 2015

Waterflooding surveillance is essential to optimize oil recovery in mature fields. Channeling or bypassing of injected brine is a common problem in mature fields. It is hard to build a reliable simulation model to predict the existence of a channel. Radioactive tracers are a practical way to reveal these high permeability zones and provide valuable information for the design of a solution strategy.

However, a method to minimize tracer injection or enhance its effectiveness in channel detection is desirable. Data driven-models are able to give a simple picture of the reservoir dynamics and often provide important information such as interwell connectivities. In this paper we show that the capacitance-resistance model (CRM) with dynamic connectivities can be used to guide the tracer test pair selection. This method requires only production and completion information and results in a straightforward screening that can be used to identify the most probable channeling path.

A field case, Chihuido de la Sierra Negra, a mature waterflood in Argentina with more than 1500 wells is presented and analyzed. In this case the model is used to reveal possible pairs with channeling problems in a time window where there exists prior information of tracer tests. The candidates selected using the model are compared with these measuremets, finding that there is good agreement with the calculated high risk set. This enables to use CRM to enhance channeling detection using tracers, also this model can be used to select a smaller set of wells where the probability of finding a connected pair is higher. In contrast to other techniques, the capacitance-resistance model with dynamic connectivities automatically takes into account dynamic boundary conditions such as new wells or shut-ins. A full-field history match and channeling detection routine can be run in minutes making this model a suitable tool for real time surveillance.
Quantitative Characterization of Porosity Partitioning from NMR Logs in Siliciclastic Reservoirs - Ecuador
Authors: Lafournére J-Paul. B. , Bringer F. , Reeder S. L. , Leon M. Naranjo , Bourge J-P. , Morales O. , Suter A. , Castillo F. , Ochoa J. , Sierra F. , Bravo J.
Published: November 2015

The "Oriente" basin is located in eastern Ecuador between the Andes Mountains and the Amazon rainforest. In 2012, daily oil production reached 505,000 barrels. The three main oil-bearing Cretaceous formations in the basin are the Hollin, T and U formations. Results from recent extensive coring of the U and Hollin formations showed that the pore size significantly affects oil saturation and production. Therefore, understanding pore size distribution can greatly enhance the success of a well. It is a major challenge to characterize and classify reservoir type and heterogeneity in reservoirs with pore-size variations using only well log data. We used core data from three wells in the U and Hollin formations to validate a new nuclear magnetic resonance (NMR) spectral analysis technique, applied in the echo domain, to estimate the pore-size distribution.

In certain carbonate reservoirs in the Middle East, the distribution of pore size classes can be accurately determined by fitting the NMR pulse echoe. The method was blindly tested on three siliciclastic wells from the Oriente basin, and the results were compared with pore-size analysis from mercury-injection and capillary-pressure data. Additionally, a multi-mineral petrophysical model was built for each eall from log measurements, omitting the core data. The porosity derived from the multi-mineral model was used as a porosity input to guide the time-domain inversion of the NMR echo trains. The inversion solves for continuous logs of the porosity, attributed to three pore families, representing the range of pore-body sizes from small to medium to large.

After completing the log-based classification into three pore families, the resulting porosity logs were compared to the analysis of core samples for several oilfields. For all formations and in all fields, the core-analysis inversion data was in good agreement with the time-domain NMR inversion results.

These results were used to select optimum intervals to be completed and to predict production in the studied fields.
Improved Fracture Characterization in the La Paz Field: A Case Study
Authors: Lander L. A. , Silva A. , Chiquito J. , Cadena A.
Published: November 2015

Maintaining and increasing production are the main challenges for oil and gas companies in today's difficult market. To achieve these goals, these companies are looking for new techniques to improve fracture characterization. Open natural fractures, when present, can provide the conduit for the majority of natural gas in low porosity, hard rock environments. Therefore, a complete understanding of fracture attributes is required for optimal production, as well as cementing and completion design, well placement, and reservoir modeling.

In the La Paz field in Venezuela, previous petrophysical interpretation assumed the cementation exponent, m to be equal to 2. This assumption was made due to the absence of special core analysis and logging information such as dipolar sonic and micro resistivity image logs, increasing the uncertainty in the petrophysical model.

Using the crossplot of Ø vs. Rt on log log coordinates it was possible to determine the cement exponent, m, value for each zone. This parameter was fundamental to the estimation of the fracture and matrix porosity, fracture Intensity Index, and the Partitioning Coefficient.

The methodology applied in this case study is based on advanced acoustic analysis integrated with triple combo and borehole micro resistivity images. The triple combo (gamma ray, induction resistivity, neutron and density) and the image data allowed identification of the natural fractures, and the Stoneley wave analysis confirmed that several of the fractures observed in the borehole image data were open.

This methodology reduced the fracture characterization uncertainty of the La Paz Field and helped to more accurately estimate petrophysical properties where special core data is not available.
Well Testing Improvement Using Nitrogen Lifting in Shushufindi Field: Accelerating Well Response and Transient Data Quality
Authors: Ruiz Y. Lopez , Betancourt A. , Villanueva G. , Vargas A. , Tayo M. , Burgos J. , Vela I. , Egas A. , Loyola R.
Published: November 2015

Shushufindi field is the largest field in the Oriente Basin in Ecuador and is located 100 miles east of Quito. It contains 3.7 billion barrels original oil in place (OOIP) and represents 10% of country’s production. Determining reservoir properties using evaluation with hydraulic pumping for well testing has been a common practice in Shushufindi field since development in the early 1970s by Texaco Gulf Company and continuing in recent history with state company Petroamazonas.

Due to the high level of depletion and reservoir characteristics, obtaing good quality data from well testing is a challenge, and if a decision is made based on the wrong information, it could have a severe negative impact on the asset. Ambiguity in the results of well testing with a hydraulic pumping method can stem from failure on downhole shut-in that allows the development of wellbore storage, which in turn would lead to difficulties for well test interpretation, accurate flow capacity/ productivity evaluation, fluid sampling, etc.

To clarify all well testing concepts and results, a new procedure was developed for well testing in this field that uses a combination of drillstem testing tools, coiled tubing, and nitrogen lifting. With the developed method, the test is combined and continually conducted to test flow rate and drawdown buildups including downhole shut-in, providing reservoir and fluid parameters for a better evaluation and for artificial lifting design.

This paper will present a study of the implementation of this new method, covering the areas of well evaluation and the outstanding results in accelerating well response. The procedures are generally easy to follow and to understand and have an impact in reducing rig time and nonproductive time and result in a faster return of the well to production (workover). The pilot showed excellent results in obtaining reservoir property measurements that were validated by reservoir modeling and production history. The process is robust, repeatable, and applicable to other fields with similar characteristics.
A New Stimulation Method to Significantly Improve Hydrocarbon Recovery Using Temporary Beneficial Changes in Stress Anisotropy
Authors: Lewis B. J. , Surjaatmadja J. B.
Published: November 2015

As a result of the creation of a hydraulic fracture, transient geomechanics forces are exerted on the formation, which modify the stress landscape near the wellbore and the fracture plane. It has been observed that the potential exists for temporary reversal in the minimum stress direction, enabling a brief time interval in which a second hydraulic fracture can be created in a completely different direction. This provides hydraulic fracturing connectivity to previously unattainable locations in the formation, which can significantly improve initial hydrocarbon production and economic ultimate recovery from the formation.

This paper presents a computational validation of this multioriented hydraulic fracturing (MOHF) process. A unique transient 3D computational geomechanic fracture simulator was developed to perform this study, as traditional hydraulic fracture simulations are derived using static formation properties and steady-state assumptions. The new model incorporates cohesive zone elements to represent the fracture plane and friction elements to account for plastic energy storage of the multiple formation rock layers in the model. Time lapse stress fields show distinct windows of opportunity wherein new fractures can be influenced to extend in alternate directions.

This new stimulation method enhances the state-of-the-art in hydraulic fracturing. However, a deeper understanding of the transient geomechanic response in the treatment area is necessary to successfully design and perform the stimulation operation. Unfortunately, it also creates new complications with respect to industry standard hydraulic fracture models being incapable of modeling the transient response of the system. Furthermore, the availability of data related to the dynamic behavior of rocks is limited, and unique testing equipment and procedures must be developed to obtain such data.
Effect on Water Breakthrough When a Near-Critical Fluid Reservoir Reaches Saturation Pressure
Authors: Paredes J. E. , Perez R. , Perera L. M. , Larez C. J.
Published: November 2015

Many factors affect water movement within the reservoir; it's already known that petrophysical characteristics of the porous media, reservoir fracture networks and exploitation rhythm are some of them. In naturally fractured reservoirs containing near-critical fluids (oil systems) there is evidence that fluid properties have a direct effect in the strong water breakthrough at the time that the saturation pressure is reached in the reservoir.

These reservoirs undergo substantial changes in volume and composition, due to its high oil formation volume factors that cause a sudden advance oil water contact that is aided by the presence of fracture networks. This semi-instantaneous variation can be up to 40% loss of liquid saturation and it will depend on the characteristics of the fluid itself. This effect is usually confused by channeling or water coning when conventional techniques are used to diagnose water breakthrough.

This work was developed in order to demonstrate the effects and consequences of reaching the saturation pressure in the advancement of water oil contact in naturally fractured reservoirs (NFR) that contains near-critical fluids, using traditional reservoir engineering analysis, novel diagnostic plots and numerical simulation.
Selection of Customized Polymers to Enhance Oil Recovery from High Temperature Reservoirs
Authors: Gaillard N. , Giovannetti B. , Leblanc T. , Thomas A. , Braun O. , Favero C.
Published: November 2015

While polymer flooding has proven to be an effective technique to improve oil recovery from mature reservoirs, the new objective pursued by the main stakeholders consists now in optimizing the overall costs and decrease the risks associated to the implementation of chemical enhanced oil recovery methods. This is particularly true for reservoir conditions with high temperatures (above 85°C) using injection brine with high hardness.

In such conditions, using specific robust polymers is necessary to ensure stability over months during propagation in reservoirs. These polymers containing Acrylamido-Tert-Butyl-Sulfonate (ATBS) and N- Vinyl Pyrrolidone (NVP) are more expensive than regular HPAM and have to be overdosed to reach target viscosities since their molecular weights are low. In extreme cases, the project can be aborted for economic reasons. However, many fields, especially in South America, have access to very soft injection brines with a total dissolved salt lower than 3000 ppm in many cases. Using such brine is a tremendous advantage for polymer flooding since less robust polymers can be selected and target viscosity can be achieved with low dosages.

This paper describes the selection and evaluation of polymers dedicated to high temperature reservoir conditions (from 85°C to 140°C) using very low salinity brine in comparison with harder brine. A series of rheological, shear and thermal stability tests have been performed to select the most appropriate polymer for each case. The impact of the chemical composition and the microstructure shows that the incorporation of NVP is not necessarily required to ensure stability over 6 months above 100°C in soft brines. Results show as well that ATBS improves shear and thermal stability in both soft and hard brine conditions. Besides, the incorporation of thermo-responsive moieties in the polymer improves viscosity properties resulting in a lower dosage even at high temperature to reach target viscosity.

The objective of the study is also to demonstrate the possibility to develop innovative and cost-effective polymers for each reservoir condition. It encompasses an early and particularly close cooperation between the polymer manufacturer and the company willing to improve oil recovery from its reservoirs.
Elastic Seismic Inversion for Sandstone Prediction: Lower U Sandstone Reservoir, Limoncocha Oilfield - Ecuador Case Study
Authors: Galárraga M. F. , Pazos J. C. , Izurieta A. J.
Published: November 2015

This paper shows the results of the Lower U Sandstone prediction of Limoncocha Oilfield using the pre-stack elastic seismic inversion method, based on available well and seismic data. This study was focused to reduce the uncertainty in the location of new wells. The Poisson's Ratio (PR) is the most sensitive elastic parameter for discriminating lithology. Data of 49 wells were used in this study and the cross-plots analysis between mean PR obtained of seismic inversion and sand net thickness gotten of the wells show the best correlation (90%). Based on the results of this study 21 new wells were located and drilled, including horizontal and sidetrack wells. Currently, the cross-plots between these parameters in the Lower U Sandstone, including the new wells, keep a high correlation (83%). These results show the validity of this method for predicting the net sand thickness of the Lower U reservoir in the Limoncocha Oilfield. Production data were also correlated with the mean PR, and the best production matches with thickest sand development. Maybe this method could be applied in other Oilfields with similar results.
Innovative Dual Completion Application to Overcome High Oil Viscosity Challenges - Case Study from Pañacocha Field, Ecuador
Authors: Almeida R. , Lomas J. , Madrunero C. , Castillo M. , Chicaiza F. , Silva A. , Contreras C. , Korgemagi A.
Published: November 2015

The Pañacocha field, located on the Northeast part of Ecuador, is part of the Block 12 from Petroamazonas EP in an ecologically sensitive area of the Amazon rainforest.

Heavy oil (less than 14°API) producers Ml and M2 formations in Pañacocha field are not being fully developed due to challenges of handling fluids with viscosities that increase exponentially as their temperature decrease.

This paper shows how the design, planning and installation of an inverted concentric dual completion string combined with the gravel pack technique for sand control and forced convection to minimize fluid heat transfer through the tubing, allowed to produce high viscosity fluids.
A Comprehensive Mathematical Model for Predicting Thermophysical Properties of Superheated Steam in Horizontal Injection Wells Considering Phase Change
Authors: Cao Renyi , Gu Hao
Published: November 2015

Superheated-steam injection in horizontal wells is a complex process, involving not only mass and heat transfer, but also phase change. The objectives of this work are to establish a comprehensive mathematical model for predicting thermophysical properties (i.e. mass flow rate, fluid pressure, the degree of superheat and steam quality) and to analyze the performance of superheated-steam injection in horizontal wells.

In this study, using mass and momentum balance to a differential control volume of a horizontal wellbore, we present governing equations for mass flow rate and pressure drop, respectively. More importantly, phase change behavior of superheated steam is taken into account. Then, implicit equations for both the degree of superheat and steam quality are further derived based on energy balance in the wellbore. Next, the above equations are coupled and solved iteratively for each segment and a calculation flowchart is provided. Finally, the effects of the degree of superheat, injection rate, injection pressure, reservoir permeability and oil viscosity on the profiles of the above thermophysical properties are analyzed in detail.

The results indicate that for a given degree of superheat, the mass flow rate drops faster after superheated steam is cooled to wet steam, but in the same position of the horizontal wellbore, the mass flow rate increases with the degree of superheat. Secondly, we show that enhancing the injection rate maybe a good method to ensure that the toe section of the horizontal well can also be heated effectively, more importantly, the higher the injection rate is, the longer the distance from the phase change point to the heel-position of the horizontal well is, and after phase change occurs, the lower the injection rate is, the faster the steam quality drops. Thirdly, it is found that both the mass flow rate and the degree of superheat in the same position of the horizontal wellbore decrease with injection pressure. Finally, the paper further reveals that when the reservoir permeability is high or the oil viscosity is low, the mass flow rate and the degree of superheat decline rapidly.

Superheated-steam injection in horizontal wells has not been widely reported in the literature. The comprehensive mathematical model proposed in this paper, which is supported by the measured field data, can be adopted to predict the thermophysical properties and to analyze the performance of superheated-steam injection in horizontal wells. In our study, we also consider the phase change behavior of superheated steam that possibly occurs in practice.
Improving Efficiency in Mineralogy and Saturation Determination in Open and Cased Wells with New Generation Spectroscopy
Authors: Bustos U. , Grau J. , Horkowitz J. , Rose D. , Nieves I. , Salazar G. , Chaparro D. , Geney G. , Ulloa J.
Published: November 2015

Determining hydrocarbon saturation in Colombian oilfields is particularly challenging for conventional methods since the formation water in most of the tertiary sand targets is extremely fresh, frequently in the 100 ppm to 3,000 ppm NaCl equivalent range. In these conditions, the uncertainty in resistivity and sigma-based saturation interpretation methods is huge. Recent advances in measurement technology and interpretation including the combined use of dielectric dispersion and radial magnetic resonance provide a considerable uncertainty reduction in water saturation and hydrocarbon mobility evaluation. These open-hole measurements have a very shallow depth of investigation (DOI) and provide valuable information from the flushed zone, at one to four inches within the reservoir.

A new, advanced nuclear spectroscopy tool conveyed on wireline makes a direct total carbon measurement at a DOI from four to nine inches within the reservoir. When the inorganic mineral carbon is subtracted from the total carbon measurement, the resultant total organic carbon (TOC) can be used to directly compute formation hydrocarbon volume and saturation. Validation is available from the slightly shallower dielectric-derived water filled porosity. These combined measurements provide a saturation profile independent of resistivity and salinity, and allow key reservoir evaluation parameters including hydrocarbon type and oil mobility to be evaluated more accurately.

In mature fields, slim carbon-oxygen logging has been the main technique historically for estimating oil saturation behind casing, given its salinity independency. In order to achieve a desirable statistical precision and accuracy, carbon-oxygen data with slim tools requires several logging passes over the zone of interest. A typical acquisition strategy consists of a sigma pass acquired at 1500 ft/h and three or more carbon-oxygen passes acquired around 120 ft/h. In addition to borehole fluid sigma and salinity, these measurements provide information on formation porosity, lithology, matrix properties and oil saturation.

The advanced spectroscopy tool was run in the same wells as the slim carbon-oxygen devices. Comparison of measurements from both services indicates that the advanced spectroscopy device is capable of providing lithology, matrix properties and hydrocarbon volume and saturation from TOC with improved accuracy in a single logging run, at a logging speed five time faster that one single carbon oxygen acquisition pass from the slim logging device. The advanced spectroscopy tool also provides improved precision and the measurement of additional elements compared with previous generation tools, allowing for a more accurate computation of mineral components and matrix properties.
Feasibility of La Grita Member of Early Cretaceous as a Possible Unconventional Reservoir Play. Case Study. Western Venezuela
Authors: Méndez J. N. , Molina A. , Lobo C. , Pautt A. , Luzardo F.
Published: November 2015

This research has been carried out in an area of 678 km2 to the southwest of Maracaibo Lake Basin, where the lower La Grita Member of Early Cretaceous Capacho Formation has an average depth of 7600 ft (2.31 km). La Grita Member consists mainly of calcareous dark grey and laminated shale with oil traces, deposited at about 80 ft (24.38 m) which span from uppermost Albian to Cenomanian. This member represents a transgressive cycle associated with the low section of La Luna Formation (main oil and gas source of the western Venezuela). Besides, this research area has some relative flat in the Cretaceous section with little tectonic affectations, which allow developing unconventional reservoirs.

The methodology proposed by Kuuskraa et al. (2013) to assessment an unconventional reservoir play was used in multidisciplinary studies. A total of 35 wells, one well core, several 2D seismic data, electric logs and geochemical analysis were considered to carry out this study. To make petrophysical analysis the methodology of Passey et al. (1990) was used.

The geochemical data in core samples indicated that this interval shows good conditions for oil generation, where the organic matter percent is between 4.5 – 7.5% of TOC, with a maturity profile in oil window (0.5 – 0.9% Ro). The sedimentation environment suggests that the organic matter is marine. Lithologic description of drill core exhibits calcareous shales with muddy appearance. The Member is composed mineralogically by quartz/feldspar (32), calcite (50%), clay (15%) and other minerals (3%). The brittleness index of the member is around 77%. The electric logs in Member exhibit high radioactivity in some zones possibly associated to abundance of organic content. The petrophysical model matches with core samples results, where the intervals observed with high radioactivity were associated with organic richness. The geomechanical characterization in the area reveals that the state of stress in situ was estimated as normal to transcurrent. Mechanical properties of unit show moderate values of Poisson's ratio (0.23 – 0.26), high values of Young's modulus (0.88 – 4.46 * 106 psi) and UCS (6000 – 13500 psi). The Member can be classified as brittle, according to methodology of Grieser and Bray (2007). Finally, the geochemical and geological features of the member allow suggesting a possible oil play in this area. Moreover, the brittleness index and mineralogical analysis show excellent properties to horizontal hydraulic fracking of rocks.

La Grita Member has never been considered as rock generater of oil in the area. However, the member has reservoirs associated where wells produce oil through natural fractures of the unit. In these reservoirs oil production decrease quickly, affected by low permeability of rocks.
Improved Waterflood Analysis Using the Capacitance-Resistance Model Within a Control Systems Framework
Authors: Holanda Rafael Wanderley , Gildin Eduardo , Jensen Jerry L.
Published: November 2015

The Capacitance Resistance Model (CRM) is a fast way for modeling and simulating gas and waterflooding recovery processes, making it a useful tool for improving flood management in real-time. CRM is an input-output and material balance-based model, and requires only injection and production history, which are the most readily available data gathered throughout the production life of a reservoir. In this work, the CRM input-output relationship is explored by representing the CRM with state-space (SS) equations. The linear system SS equations define the relationship between inputs, outputs and states to completely describe system dynamics. The SS-CRM is a multi-input/multi-output (matrix) representation, which provides more insight into reservoir behavior than analyzing performance on a well-by-well basis. Thus, it is computationally faster and easier to apply in fields with large numbers of wells. The CRM parameters are estimated using a grey-box system identification algorithm. The matrix form of the CRM history matching and a sensitivity analysis to the CRM parameters estimates are presented. Minimal realizations and reduced order models are easily obtained with the SS-CRM approach. The performance of three CRM representations are analyzed: integrated (ICRM), producer based (CRMP) and injector-producer based (CRMIP). The methodology developed here is tested in two reservoir systems, homogeneous with flow barriers and channelized. We find that the ICRM does not reproduce the rate fluctuations as well as the CRMP and CRMIP. The CRMP works well for wells in low heterogeneity regions but not as well as the CRMIP in more heterogeneous areas, e.g. near the flanks of channel deposits. This new approach facilitates closed-loop reservoir management by enabling CRM's use for linear control algorithms, which can improve tracking performance and predictability, and is amenable to real-time optimization.
Increased Well Productivity from the Use of Carbon Dioxide to Foam Fracturing Fluids During a Refracturing Treatment in Saudi Arabia
Authors: Al-Dhamen Mohammed , Soriano Eduardo
Published: November 2015

CO2 has been a significant part of the advancement and development of hydraulic fracturing. This technology was proven in the 1970s as an energy source to help recovery of well stimulation fluids and is predominantly used to stimulate tight sandstone reservoirs because it is both clean and effective. The first application of CO2 in Saudi Arabia is discussed, highlighting its success in terms of 50% increased productivity, quick cleanup, and reduced water volume.

Classically, conventional hydraulic fracturing (acid or proppant) has been used to maximize long-term production and minimize near wellbore (NWB) damage. This paper discusses how CO2 fracturing can offer more advantages by reducing or eliminating the use of the underground water. It also provides a gas drive solution for effective cleanup. CO2 can be used to significantly reduce interfacial tension and resultant capillary forces, thus helping remove fracturing fluid, connate water, and emulsion blocks, which are among the primary damage mechanisms when fracturing gas wells.

CO2 has been a significant part of the advancement and development of hydraulic fracturing since the 1970s, but mostly just in the US during those early days. This paper discusses in detail the first application in Saudi Arabia using CO2 to foam a proppant fracturing treatment. The implementation of this technology was successful. This was demonstrated by the resultant 50% productivity increase in the study well. Using this method allowed a very fast and effective cleanup compared to other wells fractured using conventional crosslinked fluid methods. Additionally, using this method provided the added benefit of reducing water volume, which is a critical factor in this area because of limited water availability.

The first CO2 application in Saudi Arabia is discussed, highlighting its success in a resultant 50% productivity increase. The method allowed fast and effective cleanup compared to wells fractured using conventional crosslinked fluids. Additional benefits included reduced water volume, which was critical in this area because of limited resources.
A Tuning Strategy to Align Static and Dynamic Modelling
Authors: Bourge J.-P. , Bolaños M. J. , Lafournère J.-P. , Naranjo Leon M. A. , Vega Torres J. , Archard G. , Suter A. , Castillo F.
Published: November 2015

The main aim of geological modeling is to include all available data, such as seismic data, well logs, and core data, and to combine these data with more descriptive information, such as the geoscientist's understanding of the conceptual geological model and their experiences in similar environments, to predict the reservoir properties between the wells. However, in many cases, when the static model is passed to the reservoir engineer for history matching, the detailed geological knowledge and uncertainty is not fully utilized. This can lead to a model that may match the production data but actually has very little predictive power.

Depositional maps provide very useful constraints on model building. By giving a visual representation of the geological context, they can incorporate well and seismic information and the dynamic characteristics recognized from the production data, tracer information in cases of water injection, and pressure information. However, there always remains a degree of uncertainty with respect to the geometries and orientations of the geobodies, so the tuning of the maps is, by definition, an iterative process. This coupling between static and dynamic modeling is critical to achieve true discipline integration, aiming to retain the key information from each domain.

This paper presents an iterative technique to update these depositional maps in the areas of uncertainty between the wells. The required changes to honor production data and reservoir pressure trends during the history match are translated into facies modifications that are validated in terms of being consistent with both the control well data and with the conceptual depositional model.

This methodology was applied to the modeling of Shushufindi field, Ecuador. The long-term field development plan is being guided by a fine-scaled geocellular model that was designed to capture the geology at a high resolution. The workflow adopted required the collaborative efforts of the geology, geophysics, petrophysics, and reservoir engineering team members throughout the entire process.
Modeling Wax Appearance Temperature
Authors: Rocha T. S. , Costa G. M. , Embiruçu M.
Published: November 2015

Wax precipitation is one of the most important flow assurance problems that cause a decrease of oil production rates, an increase of energy consumption and failure of facilities. A very simple and accurate model can be used as a fundamental tool to predict and prevent solid precipitation at different conditions. An extension of the Won (1986) model is presented that calculates the Wax Appearance Temperature (WAT) considering the temperature dependence of the solubility parameters of the individual components in the liquid and solid phases as well as the molar volumes of the individual components. In addition to predict WAT, the liquid and the solid composition in equilibrium are estimated without having available the Paraffins, Naphtenes and Aromatics (PNA) analysis. Results are compared for 18 oils from literature data. Regarding the experimental data it is enough to know only the molar fraction and the molecular weight of each component. Even if the oil composition is known only up to C7+ fraction the extension of residue is possible through Pedersen et al. (1989) method. A percentile absolute average deviation of about 2% to 3% for WAT was obtained.
Wellbore Stability Analysis: A Stochastic Approach Applied to a Colombian Cretaceous Formation
Authors: Plazas F. , Calderon Z. , Quintero Y.
Published: November 2015

Implementing a stochastic approach along with the conventional wellbore stability analysis enables to take into account uncertainty from input data in order to obtain more realistic and reliable predictions which improve decision making process in drilling operations. By means of the methodology proposed, the uncertainty assessment for each parameter can be addressed through distinct methods depending on available information, and a sensitivity analysis is used as complement to the Monte Carlo Simulation to identify those lesser impact variables which can be treated as deterministic values and so that processing time is reduced.

As result of this workflow, quantified uncertainties are propagated into model and probability distributions for collapse and fracture mud weights are generated, and a mud weight window as a function of success probability for drilling without instability problems is built. Ultimately, a study case is developed to assess the probabilistic mud weight window for a drilling process in a Cretaceous Colombian formation.
Predictability, Distribution and Characteristics of the Unconventional Resources in Latin America
Authors: Gomez M. G. , Rebay G. , Robles F. , Hurtado M.
Published: November 2015

An investigation of the factors controlling the regional distribution of unconventional reservoirs - organic rich shales / carbonates - in Latin America, included the analysis and identification of the vertical relationship and characteristics between the reservoirs of different basins. The analysis provided evidence to understand why different formations in different basins have similar potential and supports a proposed interpretation.

The study is based on the analysis of the main source rocks which are being developed or targeted as unconventional reservoirs. These reservoirs grouped by basin, age, formation, and characteristics such as depositional environment, extension, lithology, thickness, depth, organic content, and kerogen type were analyzed. More than 20 basins in Latin America and 30 formations considered source rock, from Silurian to Cretaceous, have been evaluated (Figure 1). The paleogeography, in particular the distribution of the marine and terrestrial environments, at the moment of the deposition of these rocks was used to understand their presence and distribution in the subsurface.

Figure 1 Evaluated Basins, Organic Rich Shales and Age.

The distribution of relevant Latin America's unconventional resources is related to a sum of very well-known global factors closely associated with the extent of the Jurassic- Cretaceous seas in times of high eustatic levels, when most of the sediments generating unconventional resources were deposited. Proper interpretation and knowledge of the distribution of Mesozoic seas and their coeval events enables predicting the location of unconventional reservoirs, understanding the reason for their existence, and anticipating the main characteristics to be found in these rocks.

The geographical distribution of some of the most representative unconventional reservoirs in the main basins of Latin America relates to the regional event causing the deposition of these rocks during the Upper Cretaceous. Sediments of this age include formations in the north of South America, such as La Luna, Querecual, Naparima Hill and equivalents, which are synchronous with deposits such as Eagle Ford and Agua Nueva formations. The Upper Jurassic and Lower Cretaceous comprise a second group of unconventional reservoirs among which is the extended Vaca Muerta formation.

Understanding the relationship between occurrence, genesis and distribution of unconventional reservoirs in Latin America is fundamental to predicting the presence of these reservoirs, using global factors such as tectonic plate distribution and sea level. The summary with the characteristics of each of these reservoirs can be used as a guide to understand the magnitude of the hydrocarbon potential.
Simplified Reaction Kinetics Model for In-Situ Combustion
Authors: Klock K. , Hascakir B.
Published: November 2015

We integrate the results of six one dimensional combustion tube tests and several reaction kinetics experiments conducted with Thermogravimetric Analyzer and Differential Scanning Calorimetry (TGA/DSC) to investigate fully the burning characteristics of a Canadian bitumen (8.6 °API, 54,000 cP at 25 °C). Our ultimate goal is to estimate the variations in the chemical reactions occurring during in- situ combustion (ISC) within a reservoir which has heterogeneously distributed fluid saturations. Thus, six combustion tube experiments are conducted at varying initial water (Swi=0%, 16%, and 34%) and oil (Soi=34%, 54%, and 84%) saturations. The best performances are achieved for high initial oil and water saturation cases. The dominance of the low temperature oxidation (LTO) reactions is observed in the experiment with the intermediate water saturation (16%). The combustion front for the experiments without water (Swi=0%) could not sustain. The combustion tube results are further investigated with the reaction kinetics experiments. Hence, ISC experiments are simulated by TGA/DSC at constant (5, 10, and 15 °C /min) and varying (observed during combustion tube experiments) heating rates. The combustion tube tests suggest that water is a critical component which maintains the sustainability of the combustion process. The reaction kinetics experiments reveal that at the latent heat, interaction of steam with bitumen enhances the burning characteristics of bitumen. If the combustion front temperature (~ 400 °C) is reached with low heating rates (5 °C /min), the LTO reactions lead the formation of several different types of fuel which cannot generate sufficient heat to maintain the sustainability of combustion. Hence, LTO products adversely affect the performance of ISC for the cases which had insufficient heat generation or no initial water. However, higher heating rates (10-20 °C /min) lead the formation of more effective fuel which can generate more heat upon cracking at higher temperature ranges and maintains the sustainability of the combustion front. Because at lower initial oil and at no water saturation cases lower heating rates are observed during ISC experiments, ISC could not sustain. And, since at higher initial oil saturation with the existence of initial water saturation cases higher heating rates are witnessed during ISC experiments, the combustion process could maintain sustainability. Therefore, we recommend the injection of water to the zones with lower initial water saturations prior to field application of ISC to increase the heating rate of ISC zones.
UNISIM-II-D: Benchmark Case Proposal Based on a Carbonate Reservoir
Authors: Correia M. , Hohendorff J. , Gaspar A. T. , Schiozer D.
Published: November 2015

Brazilian pre-salt reservoirs are mainly carbonate formations and they represent a great opportunity for research development. There is an increasing need of synthetic simulation models that reproduce these Pre-salt flow features for research development in reservoir simulation. This work presents a simulation benchmark model available as public domain data that represents Brazilian pre-salt trends and add a great opportunity to test new methodologies for reservoir development and management using numerical simulation.

The work structure is divided in three steps: development of a reference model with known properties, development of a simulation model under uncertainties considering a specific date that represents the field development phase, and, elaboration of a benchmark proposal for studies related to the oil field development and production strategy selection. The reference model, treated as the real field, is a fine grid model in order to guarantee a high level of geologic details. The simulation model under uncertainties is a large scale model, a result of a development project considering an initial stage of field management.

The benchmark model is based in a combination of Pre-salt characteristics and Ghawar field information given its diagenetic events and flow features close to Pre-salt. Based on the available information, several uncertainty attributes were considered in structural framework, facies, petrophysical properties, discrete fracture network. Economic and technical uncertainties were also considered. There is an increasing need of synthetic simulation models that reproduce these Pre-salt flow features for research development in reservoir simulation. This work presents a simulation benchmark model available as public domain data that represents Brazilian pre-salt trends and add a great opportunity to test new methodologies for reservoir development and management using numerical simulation. The main result of this project is achieved: the construction of a reference model and the construction of a simulation model under uncertainties assuming the well log information from three wells. This work provides a great contribution for further research development in reservoirs with geologic and dynamic pre-salt trends.
Dynamic Drill-rate Test Approach Appplied to a Pre-salt Case Study
Authors: Nascimento A. , Elmgerbi A. , Roohi A. , Prohaska M. , Thonhauser G. , Mathias M. H.
Published: November 2015

Pre-salt basins and its exploration have become more and more frequently mentioned over the years, not just for their potential reserves, but for the implicit challenges in terms of general operations (downstream and upstream) to be faced in order to make these fields effectively commercially viable. Several research efforts aimed at to addressing these related barriers, but still in the drilling optimization and efficiency discipline, as a known challenge, a considerably low drillability is experienced when drilling throughout the pre-salt carbonates itself.

A lot of already known rate of penetration (ROP) modeling and Specific Energy (SE) studies have been developed and improved during the past 50 years, helping in post- and pre-operations analysis, allowing simulations and tendency estimations, enabling a better understanding of possible parameters and design combinations for operations optimization and efficiency enhancement.

Pre-run tests may be a very important tool together with consequent interpretation and re-usage of the results to help in boosting optimization in operations. Thus, the main focus of this paper is to address a reverse engineering by evaluating specific well data and information, identifying gaps to boost rate of penetration for a pre-salt well case study, based on a drilling mechanics analysis proposing a new analysis methodology, by playing-back through a reverse engineering procedure the drill-rate test curves, exemplifying its impact in analysis with a more dynamic and real-time focus.
Predicting and Managing Inorganic Scale Associated With Produced Water from EOR Projects
Authors: Jordan M. , Mackay E.
Published: November 2015

Inorganic scale associated with conventional hydrocarbon extraction has been well studied over the past 50 years and the mechanisms of formation, inhibition and removal are now well understood within the industry. For enhanced oil recovery (EOR) significant changes occur within the reservoir as a result of injected chemical or changes in fluid type that are used to increase the oil recovery. Two such EOR processes, CO2 and alkali surfactant polymer (ASP) flooding, are the subject of this paper.

CO2 is miscible with oil when injected at high enough pressure, but is also very soluble in water. The resulting low pH carbonic acid typically increases the geochemical reactivity of the system, and thus it is no longer sufficient to consider the scale risk associated with the formation and injection brines, but the impact of mineral dissolution deep within the reservoir may also be a factor when analysing the scale risk as the brines are produced. The requirement for such calculations, which are not typically conducted during conventional hydrocarbon recovery processes, is discussed. Consideration is given to the value of developing models that will predict the concentration of scaling ions, and hence the scaling risk, at the production wells based on in situ reactivity.

In the case of ASP flooding, the current industry understanding of scale prediction models for such systems is discussed, along with the current inhibitor screening tests to qualify scale inhibitors for squeeze application. The design of the different squeeze treatments applications for treatment of formation water and injection water production are presented. Along with the scale challenges within the production well, the scale issues associated with processing the produced ASP fluids will be reviewed in terms of additional scale risk not associated with conventional hydrocarbon production.

The objective of this paper is to highlight the challenges, current understanding and gaps in the industry knowledge and processes when it comes to scale management for EOR projects.