bluuebunny/crossref_metadata_2025 huggingface dataset:
A Novel Procedure To Apply a Relative Permeability Modifier During Perforating Guns and TCP
Authors: Suzart W. , Llerena H. , Lopez E. , Gonzalez M. , Paz F. , Davila E.
Published: June 2014

Water sensitive formations, mature fields, and relatively depleted formations can require complex fluid formulations using specific bottomhole assemblies (BHAs) and underbalanced guns fired to help minimize formation damage. Results have demonstrated that, in many cases where standard procedures were followed, production decreased and such procedures were not always completely effective. This phenomenon can be attributed to formation characteristics, such as kaolinite, smectite, silica incrustations, tertiary precipitations, pH changes, clay swelling, and others.

Relative permeability modifiers (RPMs) are being formulated and used within the oil industry to help mitigate such issues. Physically, the objective is to decrease the relative permeability to water without any (or minimum) modifications of relative permeability to oil. Basically, this methodology can be applied in water wet formations without oil permeability modifications. A standard procedure was executed in four wells and two different formations to prove this technique.

The technique involves using a standard BHA to clean and condition the well, after having selected the zone where the perforating guns will be fired. A specific formulation of RPM treatment is placed inside the casing using a balanced fluid placement technique in front of the section to be shot. This type of fluid has no salinity sensitivity and very low viscosity (less than 4 cp). After placing the RPM fluid, tubing must carefully be pulled out of the hole (POOH) to avoid disturbing and damaging this temporary plug. Guns are run into the hole(RIH) to the selected zone to be perforated after spotting the RPM and then fired, squeezing the system into the desired formations through the casing. The pressure limit must be related to the casing integrity and no more than 1,500 psi as closure pressure (10 min stabilization trend) is measured at surface, and then the final BHA run to begin production.

The primary objective of this paper is to present a non-damaging fluid that can be pumped (or gravity injected) through recently open perforations, reaching casing closure pressure, and changing nearby water permeability, without causing any completion fluid invasion into the formation or induced damage. This process can put the well into production immediately, without any additional cleaning fluid necessary for the removal of the RPM fluid from the formation. The treated wells experienced production with zero damage to formations.
Application of Concepts To Improve Oil Production in Low-Permeability Turbidite Reservoirs in Mexico
Authors: Murillo G. Gutierrez , Rodriguez J. Avendano , Centeno J. Saguero , Medina E. , Perez A.
Published: June 2014

Understanding the complexity of the reservoir is the first step for proper evaluation. By analyzing in an unconventional way using a comprehensive multidisciplinary team analysis and specialized tools to implement innovative completion techniques as the refracturing, multi-stage fracturing, and complex networks of fractures in horizontal wells will an operator have the best opportunity to achieve planned production.

The economic development of low permeability turbidite reservoirs requires efficient application of new techniques and concepts on completion methods and hydraulic fracturing with a precisely planned spacing and well location program to adequately improve the oil production.

However, it is necessary to perform analyses to determine the impact of induced fracture dimensions and orientation in order to maximize the production. The present work is a study performed to analyze some concepts which together could help to improve the production in this type of reservoir. Reservoir average data from a field in Mexico was used to build one simplified and one refined dynamic model. Fractures with different characteristics were built into the models and then simulations were performed and analyzed. This study shows how is the influence of induced fractures dimensions and the impact and benefits of induced fracturing can affect production and overall field development within a secondary recovery program. Additionally, a sensitivity to fracture orientation was simulated to illustrate the impact of knowing hydraulic fracture direction to best develop these tight reservoirs. During this study several scenarios were created and compared with the base case. The Technical and economical evaluation results show that the most profitable scenario is to develop the field with a high density of wells, producing with large induced hydraulic fractures and with water injection pressure support from the beginning of the development.
Old Problems, New Challenges: Evaluating a Horizontal Well in Naturally Fractured Carbonate Reservoirs
Authors: Moreno A. , Rosales S. , Reséndiz T. , Ramírez E. , Tellez F. , Losada M. , García G. , Quevedo M. , Añez A.
Published: June 2014

Extracting oil from horizontal wells in naturally fractured carbonate reservoirs (NFR) is challenging. To properly evaluate the formation, a solution was developed that integrates key formation evaluation technologies with stimulation systems and which has proved to be effective in holistically solving such challenges.

The holistic well analysis included evaluation of static data by integrating all available openhole data and special logs. To locate the most productive zones, fracture characterization was conducted using advanced interpretation techniques. Dynamic evaluation also included the analysis of measurements obtained using a formation tester. An integrated technical solution included a proper matrix stimulation design that considered all these data to reduce formation damage and connect the fracture networks.

This study successfully confirmed the presence of hydrocarbons in the T field in southern Mexico for the first time. Production not only exceeded expectations, but also added reserves to this new exploration area, aiding in the development of the Upper Cretaceous formation referred to locally as the KM.
Water Injection in Offshore Naturally Fractured Reservoirs Associated to a Common Aquifer
Authors: Toledo-Piña R. , Leon-García A. , Padilla-Sixto R.
Published: June 2014

The APC complex include three naturally fractured reservoirs, Abkatun, Pol and Chuc, which were of the most important fields of Mexico; they are located offshore and communicated by a common aquifer. Of these, the most important is Abkatun, producing a light oil which began its production in 1980 with average values of 8% and 2,000 md of porosity and permeability, respectively; reached its maximum oil production in 1983, maintains a production volume of 300×103 STB/D from 1986 to 1994; in 1985 were subject to a pilot test of water injection and its implantation was performed in 1991 and suspended in 2006.

This paper presents an analysis of the pilot test design process, implantation, monitoring and adjustment of the injection project, also an evaluation of results. With the pilot test was possible to found that in Abkatun field the water injection caused high drops pressure in fractures and therefore an early influx of water due to the high production of wells, so it was proposed the injection into the aquifer associated to the three fields of APC complex far away the production area. In the implementation initially was injected 420×103STB/D of treated seawater, reduced gradually to 80×103 STB/D in order to maintain the reservoir pressure of the three fields and generate a more uniform advance with a total volume injected of 1, 386×106 bbl. The benefit of the injection program was 455×106 bbl of oil. The greatest achievement of the water injection project to APC complex it was to hold a production platform of 550×103 STB/D in the period 1990 to 1994, increasing the total recovery factor from 37 to 43%. A compute of the residual oil saturation in the water invaded zone is in the order of 40%, which address to the implantation in a very near future of another process of advanced recovery.
Economic Comparison for the Potential Development of Onshore Unconventional Resources and Offshore Conventional Prospects in Uruguay
Authors: Ferro S. , Tomasini J. , Gristo P. , de Santa Ana H. , McLeroy P. G.
Published: June 2014

As a result of the bidding Round 2009 and Uruguay Round II, 10 Production Sharing Agreements were signed for offshore areas, in which 8 IOCs are involved as contractors. The exploration that is currently taking place implies a superlative increase in the knowledge of Uruguayan offshore basins. For awarding onshore contracts there is an open door system in place. The fiscal regime is very similar to the one applied offshore, but with slight differences. Nowadays there are 4 contracts for exploration-exploitation of hydrocarbons onshore Uruguay, with 2 IOCs as contractors, in Uruguayan Norte basin, which is the southern extension of Chaco Paranaense Basin. The Norte basin potentially has Devonian-age shale oil and shale gas resources, in addition to conventional leads and prospects.

This work presents an economic assessment for a shale gas and shale oil development in a 10 000 km2 Area in Norte Basin, resulting that the viability of the project could only be possible in the values of EUR higher than the P5 case, and it is strongly related to the drainage area and the cost of drilling, completing and hydraulic fracturing of the wells.

In addition, for the sake of comparison of profitability indexes and project profit distribution related to slightly different fiscal regimes, the same resources volumes were considered for an offshore project. On the other hand, the results show that the offshore development project is economically viable for the case of higher resources volumes. Finally, the Minimum Economic Field Size was calculated for offshore prospects, for the oil and associated gas case.

This work constitutes a first approach to a technical/economic evaluation applied to the development of unconventional resources onshore Uruguay, comparing its results to conventional prospects offshore Uruguay. Its findings and conclusions are significant for those international oil companies that are already carrying out or interested in potentially conducting exploration activities in both onshore and/or offshore Uruguayan basins. The results of this assessment are also very illustrative of the comparison of government's take for the different onshore and offshore fiscal regimes and represent a valuable input for ANCAP and the Uruguayan government to take into consideration to define offered areas policies.
Hydraulic Unit Determination and Permeability Prediction Based On Flow Zone Indicator Using Cluster Analysis
Authors: Aguilar Cesar , Hugo Govea , Rincón Guillermo
Published: June 2014

Classical discrimination of petrophysical rock types is based on subjective geological observations and on empirical relationships between permeability and porosity data. The Hydraulic Unit approach is a methodology for classification of rock types and prediction of flow properties, based on flow zone indicator that incorporates geological attributes of texture, mineralogy and the physics of flow at pore scale to discriminate distinctive hydraulic units.

This paper presents a methodology for the determination of Hydraulics Units and permeability prediction using a cluster analysis technique due to a hydraulic unit's zonation process requires a rigorous statistical approach. MULTI-RESOLUTION-GRAPH-BASED CLUSTERING (MRGC) is a very powerful non-parametric algorithm which allows defining the optimal number of hydraulic units.

The methodology was applied to Venezuelan Eocene sandstone reservoir integrating core data (flow zone indicator) and log data such as porosity, shale volume and caliper as an input data. Compared to previously classification, based on lithofacies information, it yielded to increased accuracy of permeability prediction and enhance reservoir description. All geological information available was integrated (core descriptions, image log, lithofacies, XRD, thin sections and SEM information) and five hydraulic units were identified, without any "a priori" subjective knowledge. A detailed characterization was achieved, determining rock properties (porosity and permeability) and SCAL properties (capillary pressure and relative permeability curves) by each rock type, which is an input data in the dynamic modeling of the reservoir.

In order to verify this approach a nodal analysis was performed in an uncored well using all data available (buildup-flowing bottom hole, RFT-pressure data, petrophysical and fluid reservoir properties) obtaining and excellent match between real and predicted initial oil production.
Wireline Perforating Technology Maximizes Well Productivity and Minimizes Operational Risks
Authors: Baumann C. , Gultom D. , Williams H. , Yudhatama A. , Rahman R.
Published: June 2014

In this paper we describe a perforating technology that helped deliver highly productive wells in the Tunu field, a multilayer sandstone gas reservoir in Indonesia. We describe the simulation models used to evaluate perforating designs and operational risks, and we include post-job productivity data for 9 wells, all of which ended up delivering more than 500% of the expected productivity, in large part due to highly conductive perforation tunnels.

The intervention technique used in the Tunu field is based on applying Dynamic Underbalance (DUB) perforating with a nitrogen kick-off technique to perforate on balance or slightly under-balance. This technique enables perforating long intervals with deep penetrating charges at high shot density, and with very low risk of gun jumping. This technique also promotes natural well flow after perforating, without the extra cost of coiled tubing intervention to perform liquid unloading.

We discuss several aspects of job design and simulation. Predictive simulations based on API RP 19B Section 4 data and rock perforating models for sandstones indicated that perforating damage clean-up with dynamic underbalance would deliver the highest well productivity. The simulation model that predicts wellbore dynamics, namely pressure waves in the wellbore, at the sand face and inside the reservoir, also predicts the gunstring dynamics with the associated gunshock loads on the conveyance. Gunshock simulations showed that the DUB technique also minimizes operational risks.

All the important aspects of the DUB perforating technique were predicted in the job planning stages. Guns were custom loaded to produce a good dynamic underbalance to remove the low permeability crushed rock zone from inside and around the perforation tunnels, thus minimizing perforation skin and maximizing well productivity. In many cases well productivity turned out to be exceedingly high, more than 500% of the initially expected productivity for7 DUB perforating jobs and 2 DUB post-perforating clean-up jobs.
Finite Wellbore Radius Solution for Gas Wells by Green's Functions
Authors: Sousa E. P. , Barreto A. B. , Peres A. M.
Published: June 2014

Even when written in terms of a pseudo-pressure function, the diffusivity equation for flow of gases through porous media is, rigorously speaking, non-linear because the viscosity-compressibility product is pseudo-pressure dependent. However, several techniques and analysis procedures neglect such non-linearity. A new methodology for constructing solutions for gas reservoirs through the Green's Function (GF) technique was recently proposed in the literature. Such methodology handles the viscosity-compressibility product variation rigorously and it has been applied to solve several gas well tests problems successfully. In those problems the wellbore is always represented by a line source. This work extends a little further the theory by considering a finite wellbore radius boundary condition for a single vertical well producing at constant rate from an isotropic homogeneous and infinite gas reservoir. The presented solution does not consider non-Darcy flow effects and wellbore storage and skin as well. Results from our finite wellbore radius (f.w.r) solution are compared to a commercial finite difference reservoir simulator that shows a very close agreement. We also compared the f.w.r solution to the correspondent line source solution to study the difference between the two solutions. As expected, the pseudo-pressure solutions do not match at early times but they do agree at long times, which is exactly how f.w.r and line-source well solutions for slightly compressible fluids behave. It seems that, even for gas well problems, the wellbore can be satisfactorily represented by a line source without significant loss of generality. The line source assumption greatly simplifies the math and the computational effort. This aspect is especially attractive for complex non-linear gas well problems that remains to be solve by the GF approach.
Electrical Wellbore Heating in Environmentally Sensitive Llancanelo Field, Argentina
Authors: Ucan S. , Savoy E. , Federici M. A. , Azcurra M. O.
Published: June 2014

Steam injection processes were abandoned due to environmental regulations in Llancanelo heavy oil field. This reservoir consists of a series of interbedded sandstone and conglomerates in cretaceous aged Neuquen Group. Down-hole electrical well bore heating technique, which is insensitive to the environmental regulations, was implemented. Despite that electrical heating for heavy oil reservoirs are established methods for in situ viscosity reductions, the commercialization and wider application of this heating technique required detailed analyses to determine optimal application conditions in horizontal well trajectory design for a heterogeneous reservoir.

Recovery factor obtained with natural depletion was less than 0.2%. Viscosity and temperature relationship was the most critical parameter to determine the applicability of the project in the productive interval. In this paper, it has been shown that electrical well bore heating can be an alternative in this environmentally sensitive reservoir with two different oil viscosity layers; Green zone with 11200 cp and Olive zone with 3880 cp at the surface conditions.

The impact of the different heating temperature and heating time on additional oil recovery were analyzed for the reservoir rock and fluid properties. Detailed simulation runs were conducted to understand recovery mechanism of convective and thermal conductive processes for well heating. By increasing the well bore temperature from initial 56 °C to 100 °C, the following results were obtained; 1- An additional oil recovery for Olive zone can be increased up to 110%, on the other hand an additional oil recovery for Green zone can be increased up to 62%, respectively.2- Energy consumption of 1 MM BTU for Olive zone will lead an additional oil recovery of 6 STB, whereas 1 MMBTU consumption for Green zone will lead an additional oil recovery of 3 STB.3- Energy rate per horizontal length is in range of 40–60 Watt/ft per the Green zone.4- Well bore heating will not change the reservoir temperature and viscosity of the oil beyond 30 m far away.

In this paper, it has been shown that electrical well bore heating was economically viable in environmentally sensitive and heterogeneous reservoirs.
Evaluation of Multiphase Flow Models to Predict Pressure Gradient in Vertical Pipes with Highly Viscous Liquids
Authors: Ruiz R. , Brito A. , Marquez J.
Published: June 2014

The prediction of pressure drop in multiphase flow for risers is of particular interest for the oil industry and also a critical variable for the right design of surface facilities in offshore fields. Empirical steady state correlations, mechanistic models and dynamic models are available to calculate the multiphase flow pressure drop, holdup and phases distribution.

The main purpose of this paper is to evaluate the accuracy of several steady state pressure drop prediction models with two phase flow laboratory data conformed by 108 point using air as gas phase and liquids with viscosity up to 310cP. The models considered in this study, for predicting pressure drop are Beggs and Brill, Duns and Ros, Govier and Aziz, Hagedorn and Brown, Mukherjee and Brill, Orkiszewski, Ansari and OLGAS model, using PIPESIM simulator. The evaluation was based on the comparison between the predicted and the measured pressure drops, demonstrating the performance of each model for highly viscous liquids. Statistical parameters as average absolute percent error and standard deviation have been calculated to find the most acceptable one. The statistical analysis showed that among the evaluated Hagedorn and Brown model has the best performance to predict pressure drop in risers with highly viscous liquids.
Effect of Oil Saturation on Acid Propagation during Matrix Acidization of Carbonate Rocks
Authors: Kumar R. , He J. , Nasr-El-Din H.
Published: June 2014

The existence of an optimum injection rate for wormhole propagation and face dissolution at low injection rates during matrix acidizing are well established. However, little has been documented that describes how the presence of residual oil affects carbonate acidizing. This study demonstrates the impact of oil saturation on wormholing characteristics while acidizing field and outcrop cores under reservoir conditions (200°F). Knowledge of the effect of different saturation conditions on acid performance will contribute towards the design of more effective acid treatments.

Coreflood experiments at flow rates ranging from 0.5 to 20 cm3/min were performed to determine the optimum injection rate for wormhole propagation when acidizing homogeneous limestone reservoir cores and low permeability Indiana limestone cores of dimensions 3 and 6 in. length and 1.5 in. diameter. The absolute permeability of the cores ranged from 1 to 78 md. The study involved acidizing cores saturated with water, oil, and waterflood residual oil using 15 wt% HCl. The viscosity of the crude oil used was 3.8 cp at 200°F. CT scans were used to characterize wormholes through the cores. The concentrations of the dissolved calcium and magnesium ions were measured using Inductively Coupled Plasma–Optical Emission Spectroscopy (ICP-OES) and the effluent samples were titrated to determine the concentration of the acid.

At injection rates 0.5 to 20 cm3/min, 15 wt% HCl was effective in creating wormholes with minimal branches for cores with residual oil (Sor=0.4–0.5). Compared to brine and oil saturated cores, waterflood residual oil cores took less acid volume to break through. Additionally, the wormholing efficiency of regular acid improved with increased acid injection rates in the presence of residual oil. A decrease in acid pore volumes to breakthrough for oil saturated cores was noted at high acid injection rates, which could be attributed to viscous fingering of acid through oil. Unlike brine saturated and oil saturated cores, waterflood residual oil cores showed no face dissolution at low acid injection rates. Conclusions from this work will aid in the design of better acid jobs by highlighting the impact of oil saturation on wormholing characteristics of acid while acidizing carbonate rocks.
Registration and Fusion of Backscattered Electron Images and Energy Dispersive Spectroscopy Images on Siliciclastic Rock Samples for Petrophysical Calculations
Authors: Lattanzi D. A. , Salazar L. , Jaime P. I. , Tallec G. , Chan K. , Gerwig T.
Published: June 2014

High resolution Backscattered Electron images (BSE) can be used to extract textural information such as grain and pore size; specific surface area; and so forth. Based on this information porosity and permeability can be estimated. On the other hand, low resolution Energy Dispersive Spectroscopy Imaging (EDS) provides valuable information about the mineralogy and chemical composition of the rock samples. Scanning Electron Microscopy (SEM) instruments are capable of generating BSE images of core and cuttings samples in a relatively short period of time at very high resolutions. The story is different if EDS images are also acquired. For example EDS images at 20 μm point spacing usually do not take longer than 30 minutes to be captured, but if point spacing is reduced to 10 μm, then measurement time increases approximately by 4 times.

This paper proposes a new methodology to combine high resolution BSE images with low resolution EDS images and to use the combined textural and mineralogical information in order to improve grain segmentation, grain size calculations as well as estimating porosity and permeability in rock samples. This methodology starts with the acquisition of the BSE and EDS images looking for an optimal relationship between acquisition time and image quality. Secondly the registration and fusion of the two images is performed and advanced image processing techniques are applied to extract information that corresponds to underlying physical characteristics such as porosity and permeability.

Results of this methodology are encouraging, 4 to 5 μm point spacing BSE images have been registered and fused with 20 μm EDS images and excellent grain segmentation has been achieved. Calculated porosity values show a good match with helium porosity core data and estimated permeability using the Kozeny-Carman equation gives results in the same order of magnitude.

This new approach saves time, operating costs and enable geoscientists to collect valuable rock data at the micro-scale level. Furthermore, this information can be used to estimate important rock properties when integrated with other data sources to improve reservoir characterization especially in cases where information is scarce or difficult to obtain.
Numerical Simulation of a Dry Combustion Tube Test for a Brazilian Heavy Oil
Authors: Mercado Sierra D. P. , Trevisan O. V.
Published: June 2014

Combustion tube tests’ simulations become an increasingly important part in the design of projects aimed at the implementation of this recovery technique. Although simulations at the laboratory scale cannot be scaled directly to the field, they provide essential knowledge on how numerical modeling of physical and chemical phenomena that occur during combustion could be dealt with. The present paper reports simulations and history matching of a dry combustion tube test for a Brazilian heavy oil. Reaction model includes a coke generation reaction and three high temperature oxidation reactions of coke, heavy and light oil components.

The history matching process is conducted in three stages. The first stage considers the matching of the combustion front velocity and fuel consumption, by altering the activation energy of the heavy fraction cracking reaction and the frequency factor of coke oxidation. In the second stage, production fluid rates and pressure drops are considered with the adjustment of the relative permeability curves and heat losses. In the third stage, the peak temperatures and produced gas composition are matchedby reviewing the kinetic parameters and the reaction stoichiometry.

From the analysis of the laboratory data, a significant influence of the steam plateau in the production behavior is identified. It is observed that the initial volume of water present in the system is produced almost entirely before oil production begins. The oil bank approximates to the producer well once the initial water volume of the system has been produced. To better represent such occurrence, it is necessary to consider the relative permeability variation as a function of oil temperature, besides taking into account the radial heat losses in the system. This is shown as an efficient alternative to more adequately represent the fluid distribution along the combustion tube. Finally, it should be noted that the simulated results show an overall good representation of the experimental data.
Flow Modeling and Comparative Analysis for a New Generation of Wireline Formation Tester Modules
Authors: Kristensen Morten , Ayan Cosan , Chang Yong , Lee Ryan , Gisolf Adriaan , Leonard Jonathan , Corre Piere-Yves , Dumont Hadrien
Published: June 2014

Wireline formation testing (WFT) is an integral part of reservoir evaluation strategy in both exploration and production settings worldwide. Application examples include fluid gradient determination, downhole sampling, fluid scanning in transition zones, as well as interval pressure transient tests (IPTTs). Until recently, however, formation testing was still challenging and prone to failure when testing in low-mobility, unconsolidated, or heavy-oil-bearing formations, especially with single-probe type tools. A new-generation WFT module with a 3D radial probe expands the operating envelope. By using multiple fluid drains spaced circumferentially around the tool, the new module can sample in tighter formations and sustain higher pressure differentials while providing mechanical support to the borehole wall.

We performed a detailed flow modeling-based analysis of the contamination cleanup behavior during fluid sampling with the new module. Using both miscible (sampling oil in oil-based mud) and immiscible (sampling oil in water-based mud) contamination models we studied the cleanup behavior over a wide range of formation properties and operating conditions. Comparison of the cleanup performance of the new module with the performance of conventional single-probe tools demonstrates that the new module is 10 to 20 times faster than the single-probe tools when sampling in tight formations. Finally, we also compared the new module against the sampling performance of dual packers and a focused probe.

This work is directly relevant to the planning and fundamental understanding of wireline fluid sampling. The key contributions are miscible and immiscible contamination cleanup models that include the effect of tool storage, a comprehensive analysis of contamination cleanup behavior for the new-generation WFT module with comparisons against conventional single-probe, focused probe, and dual-packer tools, and a characterization of fluid sampling conditions versus the preferred type of sampling tool.
Successful Extended Injection Test for Obtaining Reservoir Data in a Gas-Oil Shale Formation in Mexico
Authors: Araujo O. , Lopez-Bonetti E. , Garza D. , Salinas G.
Published: June 2014

This paper presents the results from a diagnostic fracture extended injection test performed in a well completed in the first oil shale reservoir confirmed in Mexico, which is situated in the Upper Jurassic in the Burgos basin in the northern part of the country.

The test was executed in an exploratory horizontal well during the first stage, perforated with abrasive hydra-jetting, and reservoir properties had been previously set with the correlation information logs. Usually performed before treatment(s), the primary objective of a diagnostic fracture injection test (DFIT) is to estimate parameters that provide fracture information critical both to designing the fracturing treatment and the characterization of the formation, as well as to obtain more reliable information for production engineering. Compared to other methods for the diagnostic of reservoir properties, the economic value that DFIT can provide is particularly effective in formations with ultralow permeability (K <0.1 md). These injection-falloff tests, which include small volumes of fluid pumped into the formation and use few resources to obtain data, proved to be an essential tool to understand some reservoir characteristics which can provide the information necessary for an optimal fracture design and warn of issues that might be experienced during the stimulation execution.

This paper evaluates all aspects related to the pressure falloff and how important values, such as permeability and reservoir pressure, were obtained using analysis in real time from the wellsite.
Advancements in Powered Rotary Steerable Technologies Result in Record-Breaking Runs
Authors: Jerez H. , Tilley J.
Published: June 2014

Drilling operators continually experience increasing pressure to achieve all objectives safely and at the lowest cost. Powered rotary steerable systems (RSS), applied within the correct drilling environment, can improve rate of penetration (ROP), lower risks, and reduce non-productive time (NPT), which can decrease drilling costs.

Using through motor telemetry (TMT) technology, a wired motor with a hollow rotor and flex shaft, allows a connection between rotary steerable systems (RSS) and logging while drilling (LWD) downhole tools. A conductor passes power and communication through the motor to operate and steer the RSS. The wired power section uses a uniform wall thickness stator design that reduces heat production and retention. It also delivers higher rev/min and torque directly to the RSS and bit. Using the TMT powered RSS not only has improved ROP, but has also mitigated stick-slip vibration and reduced NPT. The NPT improvements have been identified in areas, such as slip-stick vibration, drill string failures, drill string torque variations, casing wear, and rig equipment failures.

Early planning and risk assessment have also been key. Experience across the globe, both on and offshore, are presented to show the benefits of integrating advanced drilling technologies, such as TMT powered RSS and real-time downhole measurements with effective planning, to reap tangible benefits from drilling optimization.

With improved performance as a result of increased torque capacity and bit speed, and reduction of the stick-slip mechanism, this new motor-driven rotary steerable technology has delivered superior performance and improved ROP in challenging medium and hard formations. After more than 10,000 drilling hours and nearly half a million feet drilled, TMT powered RSS technology is setting new records and exceeding benchmarks by bringing greater horsepower to the rock destruction process with longer runs and higher ROPs.
Injection Leakage Detection in Mature Fields Using Data-Driven Models
Authors: Moreno G. A. , Garriz A. E.
Published: June 2014

The estimation of injected water distribution in mature fields is a key factor to optimize oil recovery. Ab initio models are hard to implement for surveillance proposes because of uncertainties in the input data and high computational cost. However, some data-driven models, such as the capacitance-resistance model with dynamic connectivities, are able to encode the emergent physical behavior of a mature field in a simple but still realistic description that can be calibrated using production and completion data. In this work we apply this technique to a big mature waterflood, Chihuido de la Sierra Negra, consisting of over 1500 wells. We show that the method is useful to calculate a set of possible problematic injectors based on the sum of estimated connectivity factors. Injection loss is identified when the total connectivity for a given injector is lesser than one. The numerical scheme allows an automatic history match within minutes yielding to the best estimates for the model parameters. The results of the analysis are compared with well surveys, revealing remarkable effectiveness in leakage diagnosis. This work demonstrates that the Capacitance-Resistance Model with Dynamic Connectivities paves the way for real-time surveillance of water distribution in mature fields based on production and completion data.
Velocity Modeling During Interpretation: A Case Study in the South Region of Mexico
Authors: de la Torre J. A. , Sevilla H. , Saucedo Reyes H. , Bejarano G.
Published: June 2014

This case study in the South Region of Mexico explains a complex modeling workflow from structural seismic attributes to regional velocity models that include different geological structures like shale diapirs, listrict regional faults and a salt body intrusion which represent vertical and lateral dramatic changes of velocity, making difficult to define units and boundaries in a formal sense, increasing the uncertainty and decision making risk and affecting the drilling operations even with lessons learns.

Hence, we present a seismic attributes case with velocity modeling to allow a complete and dynamic integration of geological interpretation and the velocity modeling building.

The solution approach consists of a combination of new generation structural seismic attributes in order to extract and highlight geobody structures with a structural framework modeling; the structural framework can be linked to seismic interpretation geobody, allowing the model to be built on the fly in a "Modeling While Interpreting" workflow facilitating the creation of structurally correct interpretation.

Then, the population of velocity is conducted in a combination of the 3D grid base modeling approach and the analysis of the velocity distribution especially inside the shale geobody obtaining a more accurate velocity variation.
Fully Compositional Integrated Subsurface-Surface Modeling: Carito Production Unit Case
Authors: Escalona J. , Figueroa A. , Lopez L.
Published: June 2014

A fully compositional integrated subsurface-surface model for the Production Unit Carito was develop to support a future exploitation plan that considers the maintaining of the oil production plateau and an aggressive infill drilling for the next 3 years. These issues make imperative an integrated asset modeling that conduct and help the reservoir management, decision making and accurate estimation of additional facilities capabilities.

The Production Unit Carito comprises two of the most important fields located to the east of Venezuela: El Carito and Mulata. These fields present deep and complex reservoirs with an unconventional column of fluids, showing a marked compositional gradient which cover from an initially undersaturated gas condensate at the top of the structure to an undersaturated black oil zone toward the base. The OOIP is about 7, 000 MMSTB and the current oil production rate reaches 230 MSTB/D. A secondary recovery process was implemented over 12 years ago, based on the injection of approximately 1, 000 MMSCF/D of natural gas.

Because of prevailing reservoir pressure conditions, the increasing volumes of produced gas has led that some points of the surface facilities reach their operational limits. Furthermore, the first of all, 187 well models in compositional format were built, performing sensitivities to define the multiphase flow correlations for vertical pipe and for critical/subcritical flow in chokes, considering dynamic gradients and production tests. A network model, which comprises more than 800 Km of lines, was also built in compositional mode honoring line sizes, lengths, elevation changes and connection points, reducing the number of nodes to decrease computing time. The robust numerical simulation model comprises more than 300, 000 active cells, and represents the most reliable characterization of the reservoirs. Each model was firstly initialized and isolated run to discard internal inconsistency. Finally, the full integration was done considering the sand face on the wells as the coupling point.

The integrated subsurface-surface simulation allowed predicting the behavior of reservoir production taking into account the constraints of the surface facilities. In this way, it was reduced the uncertainty of forecasts, and were identified limitations at surface facilities. It was also possible to determine accurately the details of the hydrocarbons streams at different pressure stages of the network, with an excellent matching with the oilfield production data.
Analysis of Inflow-Control-Valves Shutdown Effects in Well Production and Economics
Authors: Botechia V. E. , Barreto C. E. , Schiozer D. J.
Published: June 2014

Inflow control valves (ICV) can be used to add flexibility to petroleum production operation. They can be used as a reaction of an undesired event (reactive control), like water breakthrough, but they can also be used to prevent or to delay these events (proactive control). Proactive control can be an efficient form to control intelligent wells. However, the benefits of proactive control require an appropriate study to avoid premature decisions that lead to suboptimal results. This paper focuses on the evaluation of the effects caused by ICV operation and its impact on long term field production and cash flow, giving support to tools or equipment to apply proactive controls (use of seismic, sensors etc.). The main objective is to show when possible benefits of a proactive operation can be reached. An inverted five-spot model, representing a specific region of a reservoir, is used to verify the effects of ICV operation, with different production and injection constraints. The results show that proactive control with ICV can, in some cases, improve the performance of the field by increasing oil production and decreasing water production, however, this kind of control is not always profitable. The results also show that ICV shutdowns can significantly alter the behavior of the wells.
Integrated Modeling of a Highly Structural and Complex Reservoir Where the Normal Modeling Rules Do Not Apply, Cerro Fortunoso.
Authors: Thompson Anthony , Garriz Abel , Manestar Gaston , Vocaturo Griselda , Consoli Vanesa , Giampaoli Pablo
Published: June 2014

Cerro Fortunoso is a field with excess of 30 years production history which lies in Mendoza Province, Argentina. A study was undertaken to establish if the existing five injection well waterflood pilot could be expanded to encompass the rest of the 240+ well field and that the necessary investment for facilities could be justified.

A detailed look at the field quickly shows why waterflood has only been tried in a very limited fashion. The Cerro Fortunoso anticline is an asymmetric, west verging structure orientated NNE-SSW and affected by different kinds of faults located in a fold and thrust belt. The anticline geometry is affected by low and high angle reverse faults generating an eastern flank that dips up to 80° at the central part of the fold.

An initial static model representing the structural complexity and the 17 cycle high resolution stratigraphic framework was constructed. However interpretation of RFT data demonstrated that flow was controlled by thin sandstones lying in the same high order cycles but which were pressure isolated from each other, hence for secondary recovery it was necessary to understand the areal extent and connectivity of these sand bodies. Additionally the very high angle of dip and the heterogeneous fluvial reservoir meant that a sandstone body could plausibly connect with a number of different sandstones on a neighboring well, leading to a situation where different correlations schemes were plausible.

This paper details how the uncertainty in the correlation of the sand bodies was reduced by integration of static and dynamic data. A number of correlation scenarios were constructed in the static model and subsequently evaluated by dynamic testing against the production and pressure data. Through iterations, a dynamic model was subsequently constructed that matched production and pressure history and in which it was possible to determine which sands were more critical to the success of any waterflood.

The geological understanding developed demonstrated that sandstone throughout the field had similar connectivity and petrophysical characteristics to those in the waterflood pilot area. It was also seen that if the sandstones were to be more discontinuous or to have a lower net-to-gross than modeled, historical production could not be matched in dynamic simulation. This methodology has demonstrated the potential to recover significant incremental hydrocarbons by waterflooding the whole field.
Selection of Optimum Completion Intervals Based on NMR Calibrated Lithofacies
Authors: Lafournère Jean-Paul , Dutan Jorge , Hurtado Jorge , Suter Andreas , Bringer Florent , Naranjo Michelle , Bourge Jean-Pierre , Gozalbo Eduardo
Published: June 2014

The Shushufindi field is located in the Oriente basin of Ecuador. The field was discovered in 1972 and is sparsely developed with about 200 wells covering an area of approximately 400 km2. An initial lithofacies characterization based on capillary pressures, pore throat size distribution, and log derived total porosities and permeabilities has provided a coherent grouping for the reservoir types that matched in over 92% of the wells.

The importance of pore throat size in the initial lithofacies characterization has spurred the use of nuclear magnetic resonance (NMR) logs. NMR laboratory measurements on core samples complement the characterization with continuously calibrated pore body size derivations. Furthermore extensive whole core studies have shown that the pore throat size has a substantial impact on the initial oil saturation. Failures to respect this later point had previously generated disappointing oil production results. The challenge for the subsurface and engineering team is to take advantage of a lithofacies-based method to determine appropriate completion intervals and generate reliable production predictions.

Open hole wireline log measurements of derived pore bodies size show a good correlation to NMR laboratory measurements on plugs when grouped within the initial lithofacies characterization. These data are used to provide a calibrated continuous pore body size curve based on the NMR binned porosities, and using the inferred initial oil saturation, to estimate the flow capacities for each lithofacies. This approach provides adequate support for selecting the reservoir rock with the best flow capacity, thereby optimizing the well completion. In thin beds where the vertical resolution of standard density and NMR logs is insufficient to discriminate the best facies a modified method has been developed. Very high resolution imaging has been coupled with flushed zone (Rxo) measurements and high frequency dielectric dispersion log to identify the potential production.

This paper presents a lithofacies characterization enhancement methodology using NMR derived pore body size as implemented in the Shushufindi field, the results to date, its impact on the selection of completion intervals, and the resulting improvement in production from this technique.