bluuebunny/crossref_metadata_2025 huggingface dataset:
Rheological Properties of an Amine Oxide Viscoelastic Surfactant With Application in Well Stimulation
Authors: Aryanpanah S. , Nasr-El-Din H.
Published: June 2014

The use of proper fluid system is one of the most important factors in the success of well stimulation processes like hydraulic fracturing and matrix acidizing. Viscoelastic surfactant (VES) based fluids are among stimulation fluids which recently have been used with promising results. The rheological properties of a tallow amine oxide amphoteric surfactant base fluid with applications in matrix acidizing and hydraulic fracturing have been studied. To find the linear viscoelastic region, the stress amplitude sweep tests were conducted in the constant frequency of 1 Hz and the shear stress range of 0.1 to 10 Pa. The linear viscoelastic region has been found to be between 0.1 to 1 Pa. Then, the effect of stress amplitude and temperature on elastic modulus (G′), viscous modulus (G″) and complex modulus (G*) have been investigated and the results were interpreted on the basis of Cates' tube theory. The frequency sweep tests have been carried out within the frequency range of 0.01 to 4 Hz and the constant stress amplitudes of 0.1, 0.5 and 1 Pa. For the evaluation of the effects of temperature on the properties of the VES solution, the tests have been done at the temperatures of 25, 28, 30 and 35°C and constant stress amplitude of 0.1 Pa. The results of experiments at the constant temperature and different stress amplitudes showed that the increase in stress amplitude caused an increase in transition frequency and widen the viscous dominant region. In the other hand, with increase in temperature at the experiments with constant stress amplitude, the transition frequency decreased and the VES solution showed the dominant elastic behaviors. The results of frequency sweep tests in the form of Cole-Cole plots showed that the surfactant system highly deviated from Maxwell's mono relaxation model and, therefore, the stress relaxation mechanism in the fluid found to be the combination of reptation and breaking of wormlike micelles. These results can be used to better understand the rheological properties of VES-based fluids and manipulate their properties for using in well stimulation processes.
Mitigating Vibration with Roller Reamer Technology Improves Drilling Efficiency in Hard/Abrasive Formation, Sao Francisco Basin, Brazil
Authors: Mario Breton , Julio Mayol , Martin Gerlero , Oscar Rojas , Gerardo Leon , Joao Pedro Tocantins
Published: June 2014

When drilling operations commenced in Sao Francisco basin, the operator knew the exploratory well campaign would present a major investment. However, as operations progressed the well costs and time exceeded assessments mainly drilling the 8½″ production hole section through two hard and abrasive formations. Due to the unconventional nature of the reservoir, well costs must be held to a minimum in the exploration phase to ensure each project is economically viable. To accomplish the objective, several tool technologies were analyzed and proposed with the aim of reducing down-time and tool failures. One of the main issues identified was the high level of shock and vibration (S&V) observed while drilling the Macaubas and Paranoa formations. The environment had a negative impact on drilling efficiency and contributed to tool failures and excessive wear on BHA components leading to additional trips and preventing the operator from achieving higher ROP and run lengths.

After an engineering analysis, the drilling team determined the root cause was BHA/bit whirl while along with several other contributing factors related to the challenging hard and abrasive formations. Based on this information, the provider recommended using a roller reamer in the bottom hole assembly (BHA), to mitigate shock and vibration and improve drilling efficiency. Results were positive and the roller reamer reduced NPT and overall well costs in this economically sensitive play. Roller reamers are currently part of standard packed BHA and are being used as a reference for operators experiencing the same type drilling dysfunctions.
Improving Unconventional Completions by Pinpointing Multistage Fracturing with Coiled Tubing: Cases Histories from Burgos Basin
Authors: Lopez-Bonetti E. , Araujo O. , Ortiz J. Ramon , Hernandez J. , Castillo H. , Basurto E.
Published: June 2014

In northern Mexico, from the Burgos basin to the Chicontepec field, horizontal wells have been a viable choice for exploiting hydrocarbons in tight gas and shale reservoirs. Successful drilling and completion of such wells has allowed goals in this complex operation to be reached. The learning curve trend means good knowledge has been acquired and difficulties encountered during completions can be addressed using new techniques available within the area.

To achieve high performance when fracturing multiple zones, the application of an abrasive perforating technique using coiled tubing (CT) has proven a very effective alternative for acquiring optimum results. This has been particularly true for applications in highly deviated and horizontal wells. Although this technique has been applied in others regions since 1998, its implementation within this region has only become more common during the past three years.

Using field experience with actual cases, this paper illustrates the available technologies and techniques that have become a new process in this region. Because of the undisputed completion and production results, pinpoint multistage fracturing is becoming the preferred completion technique used by the operator and will be used extensively as more horizontal wells are scheduled to be drilled and completed in upcoming years. Similarly, this has been the preferred choice when the formation is estimated to produce liquids.
Impact of the Heavy-Oil Properties in the Slug-Flow Characteristics
Authors: Brito A. , Marquez J. , Ruiz R. , Cabello R.
Published: June 2014

Slug flow is the most common flow pattern presented in multiphase flow gas-liquid pipelines for highly viscous liquids. In this sense, it is important to know how this flow pattern behaved when oil viscosity increases in order to improve the operation and design of surface facilities, such as: pipelines, separators, flow conditioners, risers and multiphase equipments as pumps and flow meters, and also to reduce the corrosion and erosion effect in the systems. This requires a rigorous study of slug flow characteristics, i.e.: slug holdup, slug length, translational velocity and slug frequency as well as pressure gradient and liquid holdup in the pipe. For these reasons, it is necessary to carry out experiments that allow a better understanding of slug flow pattern and improving mathematical models to predict slug characteristics.

In this work, an experimental study of three different gas/liquid systems is presented. This includes liquid viscosities of 1cP, 430cP, and 960cP and the liquid viscosity effect in slug flow characteristics such as: flow pattern transition, slug translational velocities, slug lengths, pressure drops, holdup, and slug frequency.
Quantifying Thin-Bed Modeling Contribution on Characterization of Bypassed Oil for Improved Oil Recovery
Authors: Martino L. A. , Loss M. Laura , Ucan S. , Thompson A. , Morettini E.
Published: June 2014

Improved oil recovery is more sensitive to sub-log scale heterogeneity than primary recovery processes. Determination of porosity, net-to-gross, saturation and permeability, both magnitude and direction, at scales below log resolution is often required in secondary and tertiary processes and can have an impact on the estimation of original hydrocarbon in place, by-passed oil and recovery factors.

Conventional log interpretation and conventional static modeling workflows may not capture sub-scale log heterogeneities, often due to the averaging involved in the upscaling process. Even though log values have been generally calibrated to plug scale (cm3) measurements, they are averaged over volumes much larger than their scale(s) of key heterogeneity.

This paper compares the simulated response derived from conventional and from effective property and lamina-scale modeling in three different oil bearing formations in the Argentinian Neuquen Basin, namely Quintuco, Sierras Blancas and Lotena Formations. All three Formations are candidates for waterflood developments and enhanced recovery processes options are being examined.

Permeability, porosity, saturation and net-to-gross ratio were determined by constructing high resolution models that enabled capturing sub-log scale heterogeneities. These models were subsequently upscaled at representative elementary volumes and the derived effective properties were used in building simulation models through different upscaling methodologies.

Results of the two scale models for each reservoir are compared. Strengths and weakness of the applied methodology, as applied to these specific cases, are evaluated and discussed.
Applying Mohr-Coulomb Cycle to Step-Rate Test: An Innovative Rock Mechanics Equation in Extreme Unconsolidated Formations
Authors: Suzart W. , Cayo M. , Jaramillo J. , Alarcon X. , Barragan E. , Calvachi C. , Torres C. , Mantilla A.
Published: June 2014

There are sand formations that do not have a minimum contact pore space cemented. Typically, these sands have very low toughness, high permeability, and high porosity. Such factors allow fines and solids migration. The consequence of this scenario is the increase of workover interventions and equipment damage/erosion caused by sand flow, thus resulting in increasing cost, lost time, and insufficient production. Drilling these formations is challenging. Taking core samples to perform rock mechanic tests in a laboratory is also a difficult task. Additionally, there are cases where wells do not have sonic dipole surveys to help with evaluations. Usually, the samples are not uniform, have cracks, are broken, or completely dispersed, making their application in rock mechanic characterizations impossible.

The presented methodology applies the Mohr-Coulomb cycling test for the first time to actually process step-rate, fracturing, and falloff tests. Field tests using this technique have shown good correlations and obtained reliable curves for hydraulic fracturing simulators. A package of rock mechanics equations described in the oil industry are evaluated and tested in field scale.

Many times, engineering teams must have a source of equations which can easily calculate required parameters to be used for sieve analysis, gravel pack, and fracture pack projects. Basically, the methodology is reliable because of the equations of theoretical soil mechanics (Terzagui 1943), Mohr-Coulomb, and field practices of determinations of minimum in-situ stresses and overburdens. After field test confirmations, the objective of this matter is to present correlations of Terzagui (1943) and Mohr-Coulomb equations to be used during gravel, fracture pack, and hydraulic fracturing operations. The methodology has an important presence during the study to help minimize risk during these jobs and obtain good approach simulations because, as previously discussed, this type of sandstone makes obtaining formation samples challenging. Equations can provide a good number of useful calculations and help reduce operational risk when performing these types of well completions or treatments.
Swelling of Elastomers in CO2 Environment: Testing Methodology and Experimental Data
Authors: Daou F. , de Miranda C. R. , de Oliveira J. L. , Engelke B. , Borman C. , Le Roy-Delage S. , Lungwitz B.
Published: June 2014

Elastomers are widely used in downhole tools for oilfield applications and are often exposed to gases, such Carbon Dioxide (CO2), and Hydrogen Sulfide(H2S) in addition to the produced hydrocarbons and water. Successful drilling operations and reservoir management involve the use of tools of appropriate metallurgy and sealing materials. Depending on the environment (High Pressure High Temperature, H2S, CO2, or others), the sealing property of the elastomers may fail, leading to HSE (Health, Safety & Environment) and operational related incidents. Examples of such incidents are the undesired production of fluids, contamination of ground water, and the consequent loss of time and profits.

Consequently, the selection of the sealing material used for downhole oilfield applications is critical and needs to be carefully considered, either for short-term drilling operations or for long-term completion activities. Elastomer compatibility studies covering a variety of media such as diesel, oil- and water-based muds, and brine are available in the literature. However, compatibility to super critical fluids like pure CO2 or H2S are not widely documented and even difficult to find in public domain. This paper describes a testing methodology to investigate the behavior of selected elastomers under CO2 environment at different temperatures and pressures. It focuses on the swelling behavior of different materials upon contact with CO2.

Two testing methodologies are investigated. One is using a High Pressure High Temperature autoclave from "Parr Instrument". It allows samples to be simultaneously exposed to two different environments; the wet supercritical CO2 and CO2-saturated fluid. The second is using a High Pressure High Temperature Visio-Cell equipped with a high resolution camera. The benefit of such a set-up is that it allows a "real-time visualization" of individual particles while in contact with CO2.

Results obtained show the HPHT Visio-cell to be the best fit for assessing the behavior of the tested material. Additionally, some components appear to swell less with CO2 than others.
Efficiently Delivering Difficult Tortuous Well Profile Deepwater Brazil Ream-on-Demand System Saves Operator Trip for Tool Change-Out
Authors: Lima Araken , Oliveira Danielle , Breton Mario
Published: June 2014

To reach the reservoir in Campos Basin, deepwater Brazil requires the operator to drill a difficult "S" shaped wellbore geometry through shale and sandstone with UCS (5–15kpsi). To achieve the objective, an operational plan was devised that had two major phases: 1) drill to the base of the reservoir in under-reaming mode building angle from 30° to 80° while enlarging the hole 12¼-in x 14¾-in for 600m; 2) then drill 300m of 12¼-in drop-off section down to 3700m MD. After reaching 12¼-in TD, the plan calls for reservoir evaluation then pumping a cement plug to sidetrack and drill a long horizontal section. Efficiently delivering the relatively deep wellbore as planned would be challenging and present a significant risk because of daily rig-rates approaching $1 millon USD. To ensure all contingencies were considered, the operator initiated an engineering analysis to identify tool/BHA limitations: 1) Using a reamer to drill into the reservoir would have a negative effect on ROP and require the operator to pump more cement for the sidetrack plug; although improved image quality would be achieved by logging in the smaller 12¼-in hole section.2) The operator also considered placing the concentric reamer 300–400m offset from the bit to drill the drop-section without tripping to remove the reaming tool from the BHA. However, this BHA configuration would be susceptible to vibration induced RSS/MWD/LWD damage, drilling dysfunction and would also increase the risk of a parted connection.

To solve the application changes, an engineering analysis was conducted to determine if a new-type ream-on-demand (RoD) tool would be an appropriate solution. Since the RoD tool is equipped with an innovative hydraulic system, it can perform multiple activations/deactivations of the cutting blocks while downhole. Because the RoD system does not require a ball drop to engage, BHA design flexibility is greatly enhanced.

The study used a well records database and numerous offsets runs with a conventional expandable reamer used in Roncador field. A rock-strength identification program, that uses log data including GR and sonic, was applied to determine formation type and foot-by-foot UCS. A hydraulics analysis was performed to determine proper operational and indexing flow rates. Finally, an FEA-based modeling system identified an optimal parameters window (RPM/WOB) to reduce damaging vibration levels while reaming/drilling. The RoD tool was run and drilled a 12¼-in hole into the reservoir without requiring a trip that is required to lay down a conventional ball-drop activated reamer. The new-style BHA also improved ROP when drilling into the reservoir. The RoD system saved the operator between 24–36 hrs of rig time for a cost savings of approximately $1 million USD. The operator plans to keep using the ream-on-demand tool in future applications where the "S" well profile is required.
Integrated Methodology for Laboratory Evaluation of Shale Plays Cores
Authors: Pérez E. R. , Pachón Z. , Gómez J. J. , Marin M. P.
Published: June 2014

In the last 10 years, shale gas has emerged as an alternative source because of its contribution to oil and gas reserves. Colombia has a high hydrocarbon potential in unconventional shale gas deposits, and this become the main objective of the national oil industry. Currently proven reserves of conventional gas in Colombia are about 6 TCF, while technically recoverable reserves of shale gas according to the US. Energy Information Administration (EIA) studies1 are about 55 TCF, so successful production of these reservoirs will increase significantly gas reserves in Colombia.

Ecopetrol was the first company in Colombia in starting the characterization of unconventional shales through the stratigraphic well La Luna-1 located in the Medium Magdalena Valley, from which 3445 feet of core were recovered in five months between 2011 and 2012.

The need for interpretation frameworks in order to understand properties such as rock source quality, mechanical properties and production performance from a diverse range of measurements require a laboratory characterization of rock properties that is an important part of any resource evaluation. This was the challenge for the labs of the Colombian Petroleum Institute, that based in its experience in Conventional reservoir analysis could adopt its skills and methodologies for analyze 2851 rock samples. The work flow includes geochemical analysis for Total Organic Content (TOC), Pyrolysis Rock Eval VI (parameters S1, S2, Tmax) and quantification of gas content (canister). Samples selection for other analysis was based on core Tomography and Spectral Core Gamma. From the same foot of core, the samples were taken for petrographic analysis, quantitative mineralogical analysis by XRD, mineral distribution and microtexture by SEM, geomechanical Analysis (elastic module and the rock strength), basic petrophysical analysis and Mercury Injection Capillary Pressure (MICP). The information obtained was integrated in order to obtain petrographic rock types, hydraulic rock types and identify the most prospective intervals. The coherence in the parameters obtained by different methods demonstrated the sturdiness of quality system and methodologies applied.
PCP Run Life Improvement in Orinoco Belt With New PCP Technology
Authors: Caballeroa D. , Hurtado Y. , Gomez A. , Zimmer L.
Published: June 2014

In 1997, the commercial development of the large Heavy & Extra Heavy Oil (HO & EHO) resources of the Orinoco Belt (7 to 12° API / Estimated 295 Bbbl of Recoverable Crude Oil) was initiated. The SINCOR Project (SINcrudo ORiente – then a JV between Total, Statoil & PDVSA), now operated by Petrocedeño JV, was the first of its kind in the area, and until today it is considered as a reference when it comes to developing the most recently allocated blocks in the area.

After more than 10 years of intensive production programs, some fields are showing signs of depletion and associated production of gas is increasing. PCM, who is involved in supplying Progressing Cavity Pumps technologies to the Orinoco belt since the very beginning, has developed the exclusive & patented HR-PCP (Hydraulically regulated PCP) technology in order to extend run life of the conventional PCPs in these fields where ALPCP systems' Mean Time Between Failure (MTBF) has shown sharp decrease in the last few years.

In 2011, a project was launched in collaboration with Petrocedeño optimization department in order to validate HRPCP technology in this field. 2 × 115E1600 HRPCP pumps were installed in XA07 & YA02 selected wells. The wells selections criteria were: Wells with high gas production & high estimated GVFShort pumps run life

Following the study of Progressing Cavity Pump Technology's behavior in Multiphase conditions (SPE95272), the subsequent development of the "New PCP" (SPE 97833), and the example of the first commercial and large scale deployment in Argentina (SPE 152228), this paper shows how the HRPCP Technology benefits to the specific Orinoco Belt environment, and what this technology could bring to further development of this heavy oil basin.
Preventing Premature Gravel Pack Failures Using FLUX Calculations on High-Rate Dolphin Field Gas Wells_A Case Study
Authors: Lerza A. , Dolan J. , Guerrero A.
Published: June 2014

One of the most important rock properties in Reservoir Engineering is very often absolute permeability. Unconsolidated sands offer some of the highest permeabilities due to their typically low consolidation degree, leaving more space between the porous media for conductivity. This low degree of consolidation, however, also brings high sand production potential while producing the reservoir; therefore sand control is required. This paper discusses how well failure histories were used, along with downhole analytical methods, to determine maximum FLUX limitations recommended to be used to minimize completion failures and sand production while producing at the highest safe rate.

Chevron has a 50% working interest in an NOJV area with BG, in three different offshore dry gas fields located in Trinidad and Tobago. Dolphin field is the main producing field, having been on production since 1996 from four main groups of sands, all of which are unconsolidated (D, Upper E, Lower E and G sands). Due to the sands highly unconsolidated nature and targeting high gas production rates, all completions in the field utilize openhole gravel packs for sand control.

During the field production history, several sand completion failures were encountered, as evidenced by formation sand production at the surface and reduced rates; and in some cases, complete cessation of flow (due to sand fill). After completing various analyses on possible failure root causes, it was found that the highest probable reason for sand completion failure was high FLUX across the completions. After drawing this conclusion, it was imperative for the Reservoir Management and Production Teams to understand FLUX associated with the failures, determine the maximum recommended FLUX to avoid future failures and finally, to apply a FLUX limit on current and future forecasts, from a prudent reservoir management perspective, in order to develop more realistic and reliable production forecasts.

This case study shows how the failure history data was used and integrated with a downhole velocity analytical approach in order to determine the maximum FLUX limit to prevent current and new completion failures and sand production.
Journal Assurance Data (JAD) – Customization and Integration of Standard Production Tools at Orncem for Ensuring Quality Control of Production Data from Sacha Oil Field
Authors: Díaz A. , Caicedo P. , Enríquez R. , Erazo B. , Gabarron R. J. , Crespo C. G.
Published: June 2014

The aim of this project is to implement the Journal Assurance Data (JAD) as a control mechanism that allows to guarantee reliability and integrity of information related to production processes, from data entry to management reporting, and for control agencies of the Ecuadorian State.

The concept of JAD is based on the need to define a time period within which production data recording, evaluation and processing are viable, within a single source scheme for data entry, ensuring the quality of entered and processed data, for the purposes of determining production values generated during such period on a quantitative basis. This system allows to perform a retrospective evaluation of previous journals as well as a projection towards future journals based on complete and reliable information.

The success of JAD is based on ensuring reliability and consistency of input data for production processes, aiming at delivering quality information for decision taking as final product. This could only be accomplished with the implementation of efficient control mechanisms for data entry, as well as tools for monitoring workflows and occurrence of changes during their execution.

For the initial recording of production data, it should be checked that such data belong to the current JAD only (last 24 hours). Information regarding previous journals could only be included with due consent and previous authorization from the information quality team (Data Management).

In relation to follow-up tools, automatic notifications to work teams have been implemented in order to keep them updated regarding process execution, current changes, such as out-of-range records (from other JADs), non-valid values for entered parameters, required parameters not entered, etc.

Now then, as regards integration processes for computer applications, for both data export and import, it should be noted that the same control mechanisms are applied; that is, only information from the current JAD will be processed, being it possible to process information from previous journals provided that the information quality team has previously given their consent. Thus, information flow based on defined control guidelines is guaranteed, and any change occurred in the information can be detected and timely collected at each stage involved in production processes.
Technical-Economic Evaluation of Downhole Electric Heater Cable Application in Orinoco Oil Belt: Successful Case
Authors: Quintero E. , Quezada A. , Romero I.
Published: June 2014

This paper presents a study of the reservoir simulation OFI INF SDZ-2X located in Zuata Main Field, Junin Division of the Orinoco Oil Belt to evaluate the incidence and extent of Electric Heating in downhole with heating cable technology as the mechanism of enhanced °API ≤10 oil recovery.

The proposed simulation model uses the historical data of JK2306 well to which was applied a pilot test with system of electrical heating turning out an increase in its production therefore decreasing viscosity from 14.500cp (120°F) to 3.500 (150°F) and improving rock-fluid and fluid-fluid properties of reservoir. Once the history of the production-before and after the electrical heating-was matched, values of the thermical variables were obtained of reservoir for the contribution of a second simulation model where production forecasts were made for 6 years from a sample of 4 wells of the RS19 cluster it was obtained a profile of increased production of it and the impact of technology in the recovery factor. Furthermore, an economic analysis was elaborated by checking the scenarios for which the application of the technology of heating cable in extra-heavy oil reservoir from the Orinoco Oil Belt is profitable.
QVA (Quick Value Assessment) of San Andrés Oil Field, Veracruz, Mexico
Authors: Meza-Pérez Edgar , Reyes-Alanis Francisco , Reyes-Aguirre José Manuel , Silva-López Pedro , Irani Barry
Published: June 2014

The Quick Value Assessment (QVA) method is designed to quickly pinpoint and highlight the reserves and production potential of a field and to identify rework, recompletion, enhanced recovery and drilling opportunities that could lead to additional reserves and production. A QVA study provides a first order magnitude range of reserves for all potentially productive reservoirs in a field. (Subsequent additional work can be undertaken as required to further refine the analysis and to obtain more deterministic values for each identified opportunity.)

Another objective of the QVA study is to develop a relatively quick, easy and reusable process to organize and evaluate data. It is designed to adapt to technical information and hard data, which are entered into an application, thereby generating a reliable database so that all the information, technology and processes are available for future consultation, modification and subsequent studies.

QVA software helps to visualize surface and subsurface data in an organized manner, which facilitates analysis.

All available information including openhole well logs, production information, wellbore mechanical information, available reservoir rock and fluid information, and results of tests and special studies were used in the analysis.

A QVA study was applied to a mature field in Mexico with very encouraging results.
Numerical Simulation of 2D Hot Waterflooding Using Analytical Solutions Along Streamlines
Authors: Vicente B. J. , Priimenko V. I. , Pires A. P.
Published: June 2014

Streamline simulation is an alternative method to conventional finite difference methods, more suited to complex reservoir physics but limited in size by computational effort. The main feature of streamline modeling is replacing the space variable by the time-of-flight. In this approach, the fluid transport equation is solved along each streamline. This method is more attractive in convection-dominated flow and in large heterogeneous models. In high paraffinic oil reservoirs cold water flooding does not lead to satisfactory ultimate recovery factors due to the precipitation of solid paraffin from the liquid in the pore space. For this particular case, hot water flooding is an enhanced oil recovery technique option to increase oil production. In this work the process of displacement of waxy crude by a hot water slug followed by cold water drive in porous media was modeled. The liquid phase is composed by two pseudo-components, oil and paraffin. It was assumed that the viscosities of the components and paraffin concentration in the liquid phase are functions of temperature only. The simulations were run in 2D incompressible models without heat losses to adjacent layers and neglecting gravity and capillary effects. The system of hyperbolic equations that represents the mass conservation of each component was solved analytically. The solution of the continuous injection problem is self-similar, but in the case of slug injection interaction between waves of different families occurs. An important characteristic arising from the use of analytical solutions along streamlines is the ability to capture correctly the saturation and temperature shocks. Using analytical solutions along streamlines allowed to reduce the number of time steps and achieved results free of numerical diffusion. The results of streamline simulations were compared a commercial finite difference based simulator and presented close agreement with lower computational cost. The simulations were performed for two cases. The first one considers the injection of a high temperature water slug followed by water drive at the reservoir initial temperature. The second case analyzes the injection of a water slug at a lower temperature followed by water drive at a temperature higher than the reservoir temperature.
Online Transient Simulation To Support Production Operations Planning in Wet Crude-Oil-Gathering System
Authors: Mollinedo R. , López L. F. , Kulkarni M. , Lazcano J. , Villanueva F. , Vivas P. , Palacio S. , Solano E.
Published: June 2014

Production operations planning is an important function for the integration of petroleum midstream delivery activities, as it defines the strategy for product delivery at the operational level in order to meet delivery contracts.

This paper describes a practical application of real-time online transient flow simulation technology to support operations planning in a crude oil gathering system, in which an onshore terminal manages production from five offshore pipelines. Planning operations at the terminal is a daily challenge due to limited storage and water processing capacities, and is further complicated by large uncertainties in fluid arrival volumes and product quality caused by operating changes.

A production planning support system based on transient flow modeling technology was implemented in the wet crude pipeline network. The objective was to track the dynamic state of the system and use it to provide virtual measurements of hydraulic conditions in the pipelines, along with production volumes and product quality indicators at the terminal. Such information is generated in real time and has enabled the following business functionalities: Planning for crude oil production at the terminal proactively rather than reactivelyQuantifying oil and water volume impact on terminal operations in response to operational changes taking into consideration dynamic oil/water holdup effectsForecasting water production volumes and exposing results to manage operation of water treatment facilities according to capacity and availability

The modeling system has proven to be an effective tool in the tracking and forecasting of the pipeline operation, and has been incorporated into the operator's daily production planning workflow. The system has also drawn much needed attention to the transient aspects of fluid flow in an oil-water pipeline network, behavior that is often perceived as immaterial for liquid only systems, but was largely responsible for the quality and volume tracking issues that the operator was facing.

This paper is a reissue of the paper published in 2013 (SPE-166537), which has now been updated to reflect the newly expanded scope of the online system to cover both the light oil (original scope) and heavy oil (new scope) pipeline networks.
Shallow Horizontal Drilling Meets with Very Extended Reach Drilling in the Venezuelan Faja
Authors: Chamat Burgos E. , Peñaranda J. , Gonzalez K. , Trejo E. , Meneses M. , Rosales A. , Martinez J.
Published: June 2014

Early in the 1990s, Venezuela accelerated drilling and production of the Orinoco oil belt called "La Faja." Since then, thousands of horizontal wells have been drilled. Despite the giant reserves in the highly porous and permeable sands found in the Faja, low reservoir pressure and heavy oils with reduced crude API require that reservoir exposure for production is maximized. Because of this, longer horizontal sections are being drilled and will continue to be drilled in the Faja.

Drilling of the Faja started in reservoirs of true vertical depths (TVD) from 2, 500 ft to 4, 000 ft; however, as the development of the Orinoco belt has moved towards the south, reservoirs in the last 5 years have been drilled at TVDs from 1, 500 ft to 2, 500 ft. Further development, in the last 2 years, of the southern Faja has required drilling reservoirs at TVDs from 1, 200 ft to 1, 500 ft. Drilling horizontal wells at these shallow TVDs requires adequate planning and execution because of the inherent risks of high dogleg severity, cyclic stress of bottomhole components, high torque and drag, poor hole cleaning, inadequate weight-on-bit transfer, pipe swaps, wiper trips, and stuck pipe events. To maximize reservoir exposure, recent advances in extending horizontal lengths of these shallow wells have also been achieved. A few wells drilled in south Faja in 2013 fit the very extended reach drilling classification as defined by the oil industry because of their 1:4 stepout ratio, the ratio of true vertical depth versus horizontal displacement.

Along with the evolution of shallow horizontal and extended reach drilling, advances in surface pads and trajectory design, bottomhole assemblies (BHAs), drilling practices, directional drilling tools, and advanced geosteering techniques have allowed drilling extended reach wells of longer total depth with reduced nonproductive time, enabling increasing oil production in the Faja. Experience in the execution of shallow horizontal ERD wells has led to the consolidation of lessons learned and capture of best practices which will be key to improving drilling along the extensive southern area of the Faja, where reservoirs even shallower than 1, 100 TVD are found.
The Effect of Oil Price on Oil Consumption and Reserves
Authors: Aguilera Roberto F. , Aguilera Roberto
Published: June 2014

There has been considerable price volatility in the crude oil market since 1861. At times the yearly variations, as reported by the BP Statistical Review, have been minor but on occasion they have been quite significant. The small and large variations have been matched successfully with a Variable Shape Distribution (VSD) model. Remarkably, the comparison between actual price variations and those calculated by the VSD leads to a coefficient of determination (R2) larger than 0.98. Given this validation, we integrate the results with a Global Energy Market (GEM) model developed in 2007 that presented an oil consumption forecast to 2030. Thus far, the forecast has been in line with actual oil consumption to 2012.

Contrary to statements made by various oil commentators, the integration of results suggests that the possibilities of seeing sudden, large and permanent increases in future oil prices are very low. Given the huge quantities of conventional and unconventional oil available at or below current market prices, society should be able to substitute between alternative sources long before depletion causes oil to become unduly expensive.

Further, a case can be made that with the vast global oil resource base and the significant technological advances being implemented by the industry, oil prices could decrease in the future.
Dynamic IPR – Modeling Reservoir Well Interactions to Improve Transient Simulations of Wells
Authors: Garcia Artur Posenato , Neto Gilson Moura , Machado Marcos Barbosa , Carvalho Renato de
Published: June 2014

The objective of this work is to present a new IPR model for transient well simulations that gives precise results without the high computational costs of the reservoir finite difference simulation. The limitations of using conventional IPR models for transient well simulations, specifically for oscillatory wells experiencing severe slugging or casing heading phenomena, are evidenced. The flow rate calculated with the IPR might significantly differ from the results obtained with the reservoir finite differences model for periodic bottom-hole pressures. Analytical solutions of a radial homogeneous reservoir were developed (both in time and Laplace domain) and they were used to generate its frequency response. A low order transfer function that approximated this frequency response was generated, which was named "Dynamic IPR".

Adequate boundary conditions are essential to obtain a precise result for transient well simulations. The conventional IPR models are frequently employed as the bottom-hole boundary conditions to represent the reservoir response even in transient simulations. Another possibility is to couple the reservoir finite difference model with the well and solve them simultaneously, when the IPR transient response is known to be inaccurate. A new alternative approach, the Dynamic IPR, is presented as a low order system of ordinary differential equations that can be applied for oscillatory wells and supposedly for any transient simulation without complex reservoir behavior such as coning for example.

The Dynamic IPR was compared with the two analytical solutions (the deconvolution of the Laplace domain solution was performed with the Iseger algorithm) and the conventional IPR. A sinusoidal bottom-hole flowing pressure was assumed and the corresponding liquid flow rates were calculated. The liquid flow rates determined from the transfer function were almost identical to the exact results and the computational costs incredibly lower than performing finite differences in cases in which the conventional IPR presented poor results.

This work emphasizes that there are some situations for which the IPR are inadequate and presents simple procedures to determine when that is the case. Most importantly, the proposed Dynamic IPR can be easily included in any transient simulation and greatly improve the results.
Generating Synthetic Well Logs by Artificial Neural Networks (ANN) Using MISO-ARMAX Model in Cupiagua Field
Authors: Alzate G. A. , Arbeláez-Londoño Mastan , Agudelo A. Naranjo , Romero R. D. , Bolaños M. A. , Escalante D. L. , Quintero S. Gómez , Peláez C. A.
Published: June 2014

Well logs acquired directly in field have turned out to be one of the most key engineering elements to evaluate hydrocarbon formations. Nevertheless, the lack of information, some technical troubles related to the unfolding of tools, the operational states of the well and many other reasons may sharply limit the carrying out of an optimal formation characterization methodology along the entire productive or injective lifespan of a reservoir. Nowadays, artificial neural networks (ANN) are one of the strongest tools to supply such missing information in order to generate synthetic logs.

In this paper, we explain the putting into practice of an ANN methodology with the aim of provide useful input information in geomechanical modeling for the hydraulic fracturing simulator GIGAFRAC. More explicitly, the purpose of the schemes presented here is to provide transit-time curves for primary or compressional waves (DtP) and secondary or shear waves (DtS), based on full information measurements of Gamma Ray, Neutron-Porosity, Density, DtP and DtS logs; for some wells in the Cupiagua field located in Colombian Foothills, which break through some geologic formations such as Mirador, Barco, Guadalupe, and Los Cuevos.

A noteworthy amount of considerations were taken into account to ensure the success of the ANN estimation phases. A strong focus is done regarding to filtration and quality control of the input information to the network, relating to the control mechanism of outliers, as well as the splitting-up of logs in zones by using a geological criteria and spreading of data information in computationally convenient vectorial and matricial arrangements. Finally, good adjustments were obtained throughout the validation phases and they all were considered as successful outcomes, together with training phase and subsequent use of the same for estimating DtP and DtS curves.
Boscan Field_Highly Deviated Wells to Avoid Water Production in a Heavy-Oil Reservoir Influenced by an Active Aquifer
Authors: Plaza R. , Urdaneta L. , Valera N. , Bassano F. , Smith B. , Shannon C. , Izgec O. , Benson I. , Suman B. , Matheus L. , Molina A.
Published: June 2014

The Boscán field is a giant heavy oil reservoir (10° API) located in western Venezuela. The field is operated by the Empresa Mixta PetroBoscán. OOIP is estimated as high as 35 billion barrels. For over 60 years of production history, only ~5% of the OOIP has been recovered thereby considerable development opportunities remain at Boscán to increase recovery. Drilling highly deviated completions has proven to be a successful strategy to maximize oil recovery and mitigate ever increasing water production.

The southern part of the reservoir is in contact with an active aquifer where a high contrast in fluid viscosity is present between formation water and heavy oil (0.7 vs. 350 cP) generating large differences in the mobility ratio. This causes premature water breakthrough and sharp increases in water cuts over short periods of time. Water production during the last 10 years has exceeded the handling, separation and injection capabilities at Boscán leading to a significant number of wells being prematurely shut-in.

In the past, in order to control water production, shorter vertical wells were drilled and bottom water shut-off jobs were performed. However, these strategies have proven unattractive since overall net pay was reduced and coning tendencies were high. A new strategy was introduced of drilling highly deviated wells to maximize the reservoir exposed and mitigate water production by reducing pressure drawdown in the near wellbore region.

Recently, a ~5.5 million upscaled grid-block reservoir simulation model was developed and is being utilized to understand the aquifer impact and for optimal field development. Initial simulation results confirmed that highly deviated wells perform better and delay water conning.

This paper focuses on a deviated well strategy to increase recovery per well from a heavy oil reservoir with a strong aquifer influx. It shows how multi-disciplinary teamwork is being utilized to develop and execute the strategy and how Boscán may be used as an analogy for other fields having similar reservoir conditions.
Innovative Fiber-Based Proppant Flowback Control Technique Unlocks Reservoir Potential
Authors: Ramones M. , Rachid R. , Milne A. , Pelaez K. , Gutierrez L. , Madrid O. , Ponce G. , Ponce O. , Cruz S.
Published: June 2014

Most of the reservoirs in Ecuador are in mature fields with subhydrostatic pressure. To produce from these reservoirs, an artificial lift system must be included as part of the completion, and stimulation treatments are frequently required to produce economically.

Hydraulic fracturing is commonly applied today to remove formation damage, since the penetration of the matrix treatments sometimes is not enough to fully bypass the damage zone because of the depletion. However, in the U formation, after performing fracturing treatments, the maximum drawdown is limited to ensure proppant pack stability. Proppant flowback has been an issue in the first wells hydraulically fractured. Apart from the production limitations, the consequences of proppant flowback may include: decreasing of fracture conductivity, damage to surface and downhole equipment, additional operational cost, and loss of workover efficiency, one of the main factors affecting the Ecuador oil industry scenario.

All these consequences have created the need for a new approach to be able to produce these well economically without the mentioned issues. An innovative fiber-based technology for proppant flowback control (FBPFC) was proposed. At surface, low concentrations of short fibers are easily dispersed into the fracturing slurry. Meanwhile, at downhole conditions, the fibers are activated by temperature, becoming sticky and bonding with each other to create a continuous web that consolidates the proppant pack. The fiber web has negligible effect on conductivity, creating a stable proppant pack that is resistant to cyclic stress loading. This translates into higher drawdown and productivity.

The novel FBPFC technique has been successfully implemented in Ecuador, after determining the associated risk of proppant flowback, based on the geomechanical reservoir properties. More than 30 stages have been pumped with this technique without proppant flowback despite optimizing the drawdown after the treatments. This resulted in a four- to five-fold increase in production compared with a two- to three-fold increase in wells where the bottomhole flowing pressure was limited by the risk of proppant flow back. The use of FBPFC enabled the full potential of the reservoir to be realized.