bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Implementation of a Directional Surface Hole as an Economical Solution for Reaching the Shallower Reservoirs in Wells of the Orinoco Oil Belt in Venezuela
Authors: Trejo E. , Machado P. , Aguilar V. , Garcia W. , Bonalde A.
Published: June 2014

The expansion of the heavy oil recovery campaign in Venezuela led by the National Oil Company and its partner has placed more attention on developing shallow reservoirs in the Orinoco Oil Belt. Here, the main challenge is to economically drill horizontal shallow wells at less than 1300 ft TVD, and with more than 5000 ft of lateral extension. To reach these reservoirs, the well path is normally planned with high build rates in the intermediate phase reaching ≥9°/100 ft before and after the tangent section that is required to place the pumping system.

When drilling using a mud motor, the high build rates planned for the intermediate section can result in even higher localized dogleg severities (DLS) as drilling switches between sliding and rotating. This creates several problems when drilling and completing the horizontal section, for example, poor transfer weight to the bit while sliding and torque and drag situations, which can make it impossible to reach the entire horizontal section planned with this BHA.

Progressive cavity pumps (PCPs) are preferred for use in the Orinoco Oil Belt as they are more efficient and economical. However, high dogleg severities are not recommended for production systems using PCPs. Most PCP designers recommend placing the equipment at doglegs of <7°/100 ft to increase service life and avoid premature intervention due to excessive wear.

To optimize design and extend the life of production equipment, a new mechanical well design was developed where the deviation of the hole starts in the 16-in. top hole using a directional BHA configuration with a mud motor. This configuration drilled successfully and safely; making possible to reach the entire planned horizontal section and complete it with an optimum production system.

By applying this new design and using conventional directional technologies, it is possible to drill the entire horizontal section and use the same completion system used in the rest of the area. This is an important cost savings because the custom directional technology can be used to reach the entire horizontal section but completion maintenance costs won't increase. In addition, we avoid deferred production costs due to shutting down the wells.
Automating a Comprehensive Methodology for Evaluation, Selection, and Sizing of Sand Control Methods in Fields With Sand Problems_A Case Study
Authors: Oliveira Gomes D. G. , Carruyo Villalobos J. F. , González Castaño E. R.
Published: June 2014

Evaluation of fields with sand problems is a complex activity that involves different disciplines of study and the review of several information, which is mainly related to well logs and reports, allowing for each of the studied wells the selection and sizing of recommended sand control methods. Automation of these calculation, with the use of a software originally designed to process reservoir static model, allows the use of all available well logs in the field to identify zones having the optimum rock properties to apply a specific sand control method, and to develop maps that shows the sized sand control methods applicable to each layer of the reservoir. Additionally, these results lead to more broadly assess all existing completions in this field and explain their success or failure over time.

Currently, several reservoirs in Venezuela and worldwide present sand issues, where in some cases the consensus for used sand control methods in the field have been established by trial and error over time, but in the case of a successful sand production reduction, a wrong selection and sizing of the filter media can bring problems from flow production restriction to plugging by fines, both affecting the well productivity or even the well life.

The need for integrated studies to evaluate these fields, covering all technical aspects involved, raises the need to automate calculation process performed for each well in the study, so that in this way is possible to maximize number of studied wells and thereby, obtain more comprehensive and detailed results to start, in a shorter time and with much more available information, the evaluation and analysis of the reservoir in terms of sand control completions.

Results of a case study are presented, and are related to a shallow weak consolidated reservoir in western Venezuela.
Application of Channel Fracturing in the Vaca Muerta Shale Formation
Authors: Ejofodomi E. A. , Cavazzoli G. , Morris J. , Prioul R.
Published: June 2014

The channel hydraulic fracturing technique was recently introduced to the oil and gas industry as an alternative to the conventional hydraulic fracturing methodology. Channel fracturing involves the creation of a network of open channels or flow paths within the stimulated fracture volume, enabling the increased flow of hydrocarbons through the channels and into the wellbore. This paper investigates the applicability of this novel technique in the Vaca Muerta shale and presents a case history evaluating the potential production benefits of this methodology.

Starting with a calibrated geomechanical model, an index profile was created using the ratio between the young's modulus and closure stress to determine if channel fracturing is applicable in the Vaca Muerta. The technique is compared to conventional hydraulic fracturing case to identify the differences in the created fracture properties. Based on the created channel fracturing index profile, the gross Vaca Muerta shale interval was divided into three intervals (lower, middle, and upper) and the process was repeated across each section to determine the incremental production impact across interval.

The result of this study shows that the channel fracturing technique is applicably in the Vaca Muerta shale and can potentially increase the production performance. The analysis also shows that this technique is more favorable primarily across the upper and middle Vaca Muerta intervals than the lower Vaca Muerta interval due to the high organics, low rock moduli, and high stress. Also, permeability degradation of the proppant pack does not negatively impact the overall conductivity in a Channel fracture system. Instead, loss of aperture reduces the conductivity by orders of magnitude.
Cyclic Water Injection in San Jorge Gulf Basin, Argentina
Authors: Perez Diego , Salicioni Federico , Ucan Sezai
Published: June 2014

Historical production operations in San Jorge Gulf Basin have shown that production loss of down time, due to operational problems or any strikes can be recovered in the same production period of the year without changing any operational conditions. The study of the physical processes involved in this phenomenon has motivated the investigation on cyclic water injection.

There is an extensive list of international references on cyclic water injection that can be traced back to the early 1960’ showing encouraging results on laboratory, simulation and field developments. Nevertheless, recently it has received renewed attention since for mature fields (i.e. after a long history of water injection) cyclic water injection now appears to be a very appealing option to conventional water flooding for it may lead to additional oil recovery at virtually zero additional cost.

Many thin fluvial sands saturated with viscous heavy oil, high area-thickness ratio, long history of secondary flooding, high water cut, and low recovery factor reservoirs were the selected candidates for cyclic water injection. The main reasons for the improved oil recovery were found to be that cyclic injection schemes increase the sweep efficiency through oil migration on the high saturation gradient around swept zones, reducing water channeling and fingering by means of stabilization of the displacement front. In addition, by keeping injected water in the reservoir, its energy is raised, oil production is increased and water cut is reduced.

In this paper, an alternative theoretical interpretation of the process is presented as well as simple simulation models of the heterogeneous and anisotropic sands distributions. Here we demonstrate that high oil incremental from cyclic injection is achieved even in total absence of capillary forces or heterogeneity. Besides, an exhaustive analysis of the main rock and fluid properties, cycle length and pressure conditions is performed.

The on-going cyclic water injection project in Las Mesetas field in San Jorge gulf basin western flank makes use of the maximum injection capacity by distributing the cyclic injection vertically by mandrels and per wells in a fashion that keeps stable the total water injection rate from the water plant and maximizes cyclic injection potential. Simulation history match in a small region of the project area is used to exemplify the different possible responses.

The field results proved the effectiveness of this process producing 11000 m3 of incremental oil in the firsts 18 months.
Porosity and Density Estimation from Seismic Inversion in Tight Gas Sandstones
Authors: Castillo F. , Aguilera R. , Lawton D.
Published: June 2014

A post stack seismic inversion has been applied to 2D and 3D seismic data in order to obtain a quantitative assessment of rock properties including density, compressional velocities and porosity in a tight gas sandstone. To achieve this objective, the study develops a new relationship between Acoustic Impedance (AI) and porosity.

This study focuses on a post stack seismic inversion through a band limit technique that involves three major steps: 1) Derive a low frequency velocity model using sonic logs, 2) Invert the seismic traces using a recursive inversion procedure giving as a result the middle frequency model band of the AI, and 3) Combine the previous models in order to obtain the full band limit inversion product.

The methodology is demonstrated using data from a tight gas reservoir formation chracterized with low porosity and permeability located at approximately 2, 000 meters (TVDSS) in the study area. From the model inversion, the acoustic impedance (AI) is compared with variations in porosity resulting in a reasonable correlation for the stratigraphic interval studied.

The methodology can probably be extended to other regions around the world, which possess tight gas formations with similar characteristics to the ones described in this work.
Applications of Formation Sigma While Drilling
Authors: Peternell A. , Hebert J. , Cao Minh C. , Fisher J. , Dupuis J. , Hobbs B.
Published: June 2014

Pulsed neutron generator (PNG) tools have been used historically in cased hole environments to provide formation sigma and carbon/oxygen (C/O) ratios to characterize reservoir depletion, gas/oil/water contacts, and waterflood sweep efficiency. However, one of the main challenges has always been planning the right acquisition time for the first sigma measurement. The implementation of a ruggedized PNG source in the multifunction logging-while-drilling (LWD) formation evaluation platform has allowed reservoir saturation determination using capture sigma measurements in open hole environments.

Comparisons of LWD sigma with wireline cased hole sigma has helped cross-validate the reliability and shortcomings of both measurements. On the other hand, and going beyond the historical application, new methodologies to apply sigma-while-drilling in formation evaluation have been developed. Through the integration of LWD resistivity and sigma measurements, which are collocated in the multifunction LWD platform, both formation water salinity and water saturationcan be simultaneously determined. New developments in Multi Depth of Investigation (MDOI) sigma help ensure that a noninvaded or true formation sigma value is determined. This paper demonstrates a unique application of sigma-while-drilling to determine water saturation where the water salinity is unknown.

The implementation of sigma-while-drilling technology has opened new frontiers that go beyond the common application as a baseline for monitoring logs. With the integration of collocated, pre-invasion measurements, it is possible to determine formation water salinity, key information in enhanced oil recovery (EOR) projects or exploration wells.
A Hybrid Approach to Closed-Loop Directional Drilling Control Using Rotary Steerable Systems
Authors: Matheus J. , Ignova M. , Hornblower P.
Published: June 2014

Traditionally, trajectory control in the drilling industry has been performed by experienced directional drillers, using drilling tools such as mud motors, these tools are just iron components, that limits the efficiency of the drilling process and rate of penetration (ROP). The introduction of Rotary Steerable Systems (RSS) enabled faster and efficient well bore delivery. This tested the limits of human operators to assimilate the MWD data, compare the actual well trajectory with the planned and take corrective actions to get back to the desire well plan.

A hybrid approach consisting of two levels is proposed to perform the trajectory control in the oil drilling industry using RSS. Level 1, attitude control, regulates inclination and azimuth downhole. Level 2, the outer loop, monitors the performance of the inner loop and controls the directional drilling commands issued to the tool to follow a predefined plan.

A next generation nonlinear trajectory control algorithm was developed and tested. This algorithm can hold inclination and azimuth downhole, run below mud motors, and perform an automatic turn, while holding inclination with the ability to control the gains while drilling ahead. This novel algorithm has been applied in various locations worldwide to control inclination and azimuth and keep true vertical depth (TVD) within tight tolerances. Conclusions and lessons learned from the analysis will aid future applications of the hybrid approach and the new algorithm.
Estimation for Representative Element Area of a Coquinas Analogue Using Statistical and Numerical Methods
Authors: Oliveira R. , Pepin A. H. , Carvalho M. S.
Published: June 2014

The Itapema formation consists fairly of a limestone reservoir section with coquinas (shell fragments) deposited under high salinity lacustrine conditions. The environment in which this deposits accumulated along with the diagenetic processes subsequently undertaken created reservoir rocks with high heterogeneity in several scales of investigation. The representative elementary length plays a major role to characterize such reservoirs. The present work describes a quantitative approach to determine the size of a representative elementary area (REA) using both numerical and statistical methods defined for a Coquinas analogue. Two effective properties are determined for the REA: Porosity and Permeability. The porosity is defined here as the visible porosity from a micro tomography slice and the permeability estimated from a virtual Darcy's experiment using a finite element implementation of Brinkman's equation. Brinkman's equation is deemed necessary to properly model the flow within the vugs and porous matrix. The REA is subject to periodic boundary conditions with a pressure gradient on each boundary face. The variance is estimated and used as a statistical instrument to guide the REA size and later compared to the results obtained from the porosity and permeability estimations. The laboratory routine core analysis (RCA) provides a bulk measurement for porosity and permeability of the whole Coquinas sample. The RCA is used to constraint the obtained results for the simulations and statistical estimation and delineate the asymptotic behavior.
Evaluation of Multiple Component Induction Logging in a Deltaic Environment: A case study
Authors: Aguilar C. , Govea H. , Jimenez J. , Salazar F. , Barboza J.
Published: June 2014

The Lower Eocene C Misoa Formation was deposited on a tidally-influenced low deltaic plain in the Bloque 8 Field, Lake Maracaibo Basin. As a result of the environment deposition usually sand layer thickness is below of tool's resolution, resulting in petrophysical properties being averaged across the shale and sand lamina. One of the measurements affected is resistivity hence is common to find low net pay reservoir. These low resistivity pays, characterized by electric anisotropy, are often overlooked or mistaken as water-bearing sands when conventional resistivity measurements are used for calculating their water saturation, especially when an oil based mud and traditional induction logs are acquired. More accurate and reliable petrophysical quantification is crucial for the economic decision to explore, develop, and produce these reservoirs. Klein et al. (1995) note that pronounced electrical anisotropy in porous sediments could be a good indicator of hydrocarbon pay.

The Multi-Component Induction (MCI) tool is comprised of three pairs of mutually orthogonal transmitter-receivers measuring all nine magnetic field components at 10 different frequencies. The main objective in this paper is to show how information of seven wells with MCI logs was incorporated into the petrophysical model in order to reduce uncertainties about water saturation calculation. Using tensor resistivity equations, true sandstone resistivity and the volume of laminar shale were computed. Water saturation estimation using traditional resistivity measurements in the reservoir have predicted initial water production; meanwhile MCI predicts that some intervals should not have it. All Production data available was used to determine which log derived saturation match with the real reservoir production behavior. Finally, we summarized how the lack of core and image logs information may cancel the benefits of having vertical resistivity, because N/G and porosity has a great impact in calculations.
New Work Flows for Well Interventions Using Production Data Center Solutions
Authors: Sosa J. , Bello Y. , Sahmkow R. , Marcano O.
Published: June 2014

To support the work of maintaining production levels in PEMEX E&P in Mexico, several workflows were created using a production integrated data center solutions. These workflows were applied to wells candidates to interventions (workovers, side track, stimulations, new locations, etc.) in the region.

Specific workflows were created depending of the problem, for example: positions in relations to the oil water contact and injection wells. These workflows consolidated and use all the different information analysis available in the production data center solutions, including: ▪ Plot: production and injection data, bottom hole pressure, wells interferences, salinity, percent mole of N2, etc.▪ Bubble and grid maps: production and injection cumulative, percent mole of N2 and water salinity.▪ Forecast: oil, water cut, GOR, WOR, etc.▪ Yortsos and Chan diagnostic plots.▪ Heterogeneity index.▪ Scatter plot: productions rate cumulative or any variable of interest.▪ Normalize plots.

Applying theses workflows, engineers can perform an accurate well analysis of exploitation conditions and its neighbor in order to technically support workovers and ensure the success of these. In fields where the methodology was applied success rate for well intervention was very good. Additionally, engineers can have a better way of planning rig schedule for their fields and optimize reservoir management times.
Strategy for the Development of Shale Gas in Peruvian Fields
Authors: Porlles J. W.
Published: June 2014

Currently, few shale gas fields have been discovered in Peru. These fields require technical and economic strategies for optimal development. The main aim of this paper is to show the location of sedimentary basins and stratigraphic columns of the main basins, where we can see the source rocks, which are likely to be candidates for exploration for shale gas and shale oil. On the basis of a comprehensive analysis, it will show different fields and their possible development techniques.
A Feasibility Study of Tar Sands Exploitation in Trinidad and Tobago
Authors: Ransome Godfrey
Published: June 2014

The continuous decline in Trinidad and Tobago's crude oil production has accelerated the drive to boost oil production from unconventional sources. One such source is a tar sands deposit with estimates of original volume in-place between 400 million and 2,000 million barrels of bitumen. To corroborate the volumetric estimates or determine the correct and acceptable volumes of bitumen resources, geostatistical analysis was performed. This was considered a critical first step towards assessing the feasibility of exploiting the tar sands.

Methods for converting bitumen from tar sands to synthetic crude oil (SCO) were analysed and a dry-retorting technique was selected to circumvent the environmental hazards associated with the traditional Clarke's hot-water process. Additionally, a socio-environmental survey was conducted with residents and workers in the area in order to estimate their mean perceived impacts of various aspects of bitumen extraction techniques and to have them weigh in on various possible proposed mitigation/remedial/compensation solutions.

The paper showed volumes of bitumen in place to average approximately 500 million barrels for a major tar sands reservoir. Capital costs, crude price, and environmental concerns impact significantly on the profitably of producing SCO from tar sands. The quantum of Government's take would be decisive in deciding investor participation since inclusion of royalty and corporate tax has resulted in a mere breakeven position for the base case scenario. Exploiting tar sands can be considered viable and could assist in boosting declining crude oil production in the country. Environmental mitigation and continuous prolonged remediation coupled with tax incentives would be necessary to quiet public outcry and attract investor interest.
Original Gas in Place Probabilistic Assessment Using Design of Experiments on Material Balance Models in the Dolphin Field
Authors: Guerrero A. , Gomez G. , Lerza A. , Dolan J.
Published: June 2014

Dolphin field is a mature gas field located in the East Coast Marine Area, offshore Trinidad. One of the methods to estimate gas initially in place (GIIP) of the field is material balance; however, this approach presents some particular challenges which include: sands are not well consolidated and exhibit very high rock compressibilities, communicating reservoir compartmentalization and wells are produced at very high rates. These three factors don't allow for a straight-forward understanding of the aquifer size, normally assessed with a deterministic Cole Plot analysis. As a result of these complexities, analysis demands a more in-depth understanding of the uncertainties of the reservoirs and their implications on fluid in place estimation to avoid bias and anchoring. This paper presents a case study of the workflow used in determining probabilistic material balance models for one sand in the Dolphin Field.

Initially, an uncertainty analysis was conducted to determine the appropriate ranges of petrophysical data and aquifer properties that were used as input information for the material balance models. Experimental Design was then successfully applied to generate probabilistic material balance models: Placket-Burman design of experiment was used to identify the key uncertainties in a linear model. Monte Carlo simulation was used with the resultant response surface equation to determine probabilistic volumes of the field.

This project successfully achieved a probabilistic GIIP range for a single method testing sand of the field, ultimately yielding a better understanding of the significant uncertainties and their implications. The resulting probabilistic material balance models also enable the use of an integrated asset model to generate fit for purpose forecasts and a provides a more rigorous quality checking method on reservoir simulation results.

This paper will discuss a simple workflow used in probabilistically determining GIIP for one producing horizon in Dolphin field. Given the high confidence results encountered on the single sand, this approach will be applied to all Dolphin sand horizons to provide higher confidence GIIP estimates for the entire portfolio.
Successful Polymer Gels Application in a Highly Channeled Peripheral Injection Well: Tello Field Pilot
Authors: Maya G. , Castro R. , Sandoval J. , Pachon Z. , Jimenez R. , Pinto K. , Diaz V. , Zapata J. , Perdomo L. , Muñoz S.
Published: June 2014

Tello Field is operated by ECOPETROL S.A. and located in the Upper Magdalena Valley Basin, Colombia. It began production in 1972 and reached a maximum primary rate of 11, 200 BOPD in 1980. A peripheral water injection process started in 1997, reaching a maximum secondary production of 15, 552 BOPD in 2000. From this date, water production has increased due to an unfavorable mobility ratio (M > 3.5) and a high permeability contrast (Dykstra-Parson coefficient: 0.8 - 0.9). The current recovery factor is 22% and water cut is 92%.

This paper summarizes from the laboratory to the field evaluation of a successful polymer gel project for controlling water thief zones, implemented as a strategy to reduce the phenomenon of channeling identified between the injection well Te-49 and the producer well Te-46. The design includes laboratory test (fluid – fluid, fluid – rock and cinetic reaction) to determine the right polymer and the necessary polymer and crosslinker concentration to obtain consistency of the gel at the reservoir conditions.

Polymer gel injection began in October 2009, reaching 43, 400 bbl of solution injected (13% of channel volume) and being the largest Latinoamerican polymer gel treatment until now. Injection strategy considered a maximal polymer concentration of 7000 ppm and a fixed polymer/crosslinker ratio ranging from 40:1 to control maximum injection pressure. Field results showed an important increase in oil recoveries (oil production up to 300%) and a reduction in water cut (3%). Comparing these results to what is normal obtained with this technology this is one of the most efficient process until now, this is more relevant when taking into account the peripheral condition of the water injection.

This work led to design and implement processes for water injection channeling control to improve the efficiency of water injection into other areas of the Tello field and other Colombian fields.
Material Balance Analysis of Naturally or Artificially Fractured Shale Gas Reservoirs to Maximize Final Recovery
Authors: Duarte J. Cabrapán , Viñas E. Cáliz , Ciancaglini M.
Published: June 2014

Unconventional shale gas reservoirs are acquiring more relevance nowadays, so the industry should focus on the optimization and development of unconventional exploitation techniques. In order to produce shale gas, the reservoir needs to be naturally fractured or, otherwise, stimulated by artificial procedures.

The purpose of this study is to present an analytical tool based on the Material Balance Equation ignoring water influx (Aguilera 2008) and adapted for this kind of reservoirs, by doing a sensitivity analysis through the variation of ω, the original gas in place stored within the fracture system. Applying a plot of p/Z (pressure and deviation factor ratio) vs. Gp (Cumulative Gas Production), it can be determined when the matrix's contribution begins to manifest, and this point represents a critical moment since the fracture is closing and, consequently, the production's decay rate intensifies. By knowing the critical Gp, a relation can be made with the corresponding reservoir pressure and an estimation on the production of adsorbed gas by applying Langmuir Isotherm can be done as well. It is noteworthy that this method may be used both for natural and artificial fractures systems, considering that they behave likewise when the latter has a fracture system not propped correctly.

Therefore, to maximize final recovery and to avoid a premature closing of the fractures, the critical Gp and the adsorbed gas must be considered.

This work presents a new Material Balance Equation, which takes into account dual porosity system and desorption mechanisms to calculate OGIP. Considering the production rate, the critical time can be estimated to anticipate a proper moment for a re-stimulation.
Predicting Long-term Production Behavior of the Marcellus Shale
Authors: Nelson B. , Belyadi F. , Mashayekhi A. , Aminian K. , Ameri S.
Published: June 2014

The production behavior of horizontal wells producing from Marcellus shale has not been well established due to limited production history. As a result a simple method for predicting the long-term production would be of interest to the industry. Several DCA models have been proposed specifically for unconventional gas reservoirs. However, their reliability to predict the long-term production for Marcellus shale horizontal wells has not been established. In this study, production and completion data from a number of horizontal wells completed in Marcellus shale were collected. In addition, the properties of Marcellus shale were measured in laboratory with precision equipment designed for unconventional formations. The field data as well the laboratory measured properties were utilized in conjunction with a commercial numerical simulator to predict the long-term production behavior of horizontal wells producing from Marcellus shale. The numerical model allowed for inclusion of adsorbed gas, multiple hydraulic fracture stages, as well as dual porosity behavior. The predicted production profiles were then utilized to evaluate the applicability of the various DCA models. Subsequently, a technique was developed to estimate the parameters of the DCA model to predict the long-term production based on the early production history as well as the key reservoir parameters. Finally, the results of the DCA model predictions were compared to the history-matched simulation model predictions for confirmation.
Identifying Hydrocarbon Zones in Unconventional Formations by Discerning Simpson's Paradox
Authors: Ma Y. Zee , Moore William , Kaufman Peter , Wang Yating , Gurpinar Omer , Luneau Barbara , Gomez Ernest
Published: June 2014

This article is concerned with the identification of hydrocarbon zones in unconventional plays through lithofacies classification using wireline logs. Identification of hydrocarbon zones in unconventional formations is often different than in conventional formations. For example, in conventional reservoirs, the fractional volume of clay (Vclay) is generally correlated strongly and positively with gamma ray (GR); high GR values commonly indicate low hydrocarbon potential. In unconventional reservoirs, however, Vclay is often correlated weakly with GR, and sometime even negatively. There are several possible explanations for this change of correlation. In source-rock reservoirs, high GR often indicates high total organic carbon (TOC), kerogen, and gas or oil concentrations. In some tight-gas sandstone reservoirs, hydrocarbon-bearing sandstones have abnormally high GR.

The change of the correlation between commonly used wireline logs in conventional formations to a different correlation between those same logs in unconventional formations is, in fact, a manifestation of the Simpson's paradox—a counterintuitive phenomenon in probability and statistical data analysis. Here we show how to classify lithofacies and identify high-potential hydrocarbon zones in unconventional resources by discerning the Simpson's paradox when analyzing relationships between wireline logs. We present examples from a tight-gas sandstone reservoir and a shale-gas reservoir.
Analyzing Variable-Rate Flow in Volumetric Oil Reservoirs
Authors: Elgmati A. R. , Flori R. E. , Kabir C. S.
Published: June 2014

Estimating average-reservoir pressure (pav) and its evolution with time is critical to analyzing and optimizing reservoir performance. Conventionally, selected wells are shut in periodically for buildup tests to determine pav over time. Unfortunately, shutting-in wells leads to loss of production. Today, however, real-time surveillance—the continuous measurement of flowing pressures and rate data from the oil and gas wells—offers an attractive alternative technique to obtain average-reservoir pressure while avoiding revenue loss.

A direct method for estimating pav from flowing pressures and rate data is available. However, the method is for an idealized case that assumes constant production rate during pseudosteady-state (PSS) flow, which is not generally true for real wells. This paper extends that approach so that it can be used to analyze field data with variable rates/variable pressure during PSS flow. This approach is based on a combination of rate-normalized pressure and superposition-time function. The mathematical basis is presented in support of this approach, and the method is validated with synthetic examples and verified with field data.

This modified approach is used to make direct estimation of average-reservoir pressure that uses flowing pressures and production rates during PSS flow, allowing the classical material balance calculations to be performed. These calculations, in turn help determine the reserves, recovery factor, and reservoir drive mechanisms, allowing the reservoir performance and management to be properly evaluated. Furthermore, this method can be used to calculate both connected oil volume and reservoir drainage area as a function of time. Finally, this approach provides a reasonable estimation of the reservoir's shape factor.
Artificial Intelligence (AI) Assisted History Matching
Authors: Shahkarami Alireza , Mohaghegh Shahab D. , Gholami Vida , Haghighat Sayed Alireza
Published: June 2014

History matching is the process of adjusting uncertain reservoir parameters until an acceptable match with the measured production data is obtained. Complexity and insufficient knowledge of reservoir characteristics makes this process time-consuming with high computational cost. In the recent years, many efforts mainly referred as assisted history matching have attempted to make this process faster; nevertheless, the degree of success of these techniques continues to be a subject for debate.

This study aims to examine the application of a unique pattern recognition technology to improve the time and efforts required for completing a successful history matching project. The pattern recognition capabilities of Artificial Intelligence and Data Mining (AI&DM) are used to develop Surrogate Reservoir Model (SRM) for utilization as the engine to drive the history matching process. SRM is an intelligent prototype of the full-field reservoir simulation model that runs in fractions of a second. SRM is built using a handful of geological realizations.

In this study, a synthetic reservoir model of a heterogeneous oilfield with 24 production wells and 30 years of production history was used as the ground truth (the subject and the goal of the history match). An SRM was created to accurately represent this reservoir model. The history matching process for this field was performed using the SRM and by tuning static data (Permeability). The result of this study demonstrates the capabilities of SRM for fast track and accurate reproduction of the numerical model results. Speed and accuracy make SRM a fast and effective tool for assisted history matching.
Proper Inclusion of Hydraulic Fracture and Unpropped Zone Conductivity and Fracturing Fluid Flowback in Single Shale Oil Well Simulation
Authors: Zanganeh Behnam , Ahmadi Mohabbat , Hanks Catherine , Awoleke Obadare
Published: June 2014

Horizontal drilling and multi-stage hydraulic fracturing have made the commercial development of nano-darcy shale resources a success. Although current production volumes are promising but currently published simulation results show single-digit recovery factors under depletion. Such low recovery factors highlight the importance of accurate modeling of fluid flow and well performance for wells draining such resources. In this study, explicit hydraulic fracture modeling based on data from Eagle Ford shale oil window was performed by linking hydraulic fracture design and reservoir simulation softwares. Simulated production profiles of a homogenous simplified profile and an actual conductivity profile generated by hydraulic fracture design software were compared. The amount of fracturing fluid flowback during the first year of production was examined. The effect of unpropped zone conductivity on production performance was also investigated.

The modeling results highlight the pitfalls of misrepresenting the hydraulic fracture with a constant conductivity profile. It also emphasizes the importance of appropriately modeling the amount of recovered fracturing fluid by correctly incorporating fracture propagation predicted by hydraulic fracture design software into the flow simulation model.

Oil and water production trends for a single hydraulic fracture stage were observed with and without considering fracturing fluid flowback. Results of a single stage hydraulic fracture simulation showed that ignoring flowback overestimated oil recovery by about 17%. Assuming a constant permeability in the hydraulic fracture plane resulted in overestimation of oil recovery by almost 25%. The conductivity of the unpropped zone affects the recovery factor predictions by as high as 10%. For the case investigated, about 25% of the fracturing fluid was recovered during the first 2 months of production. Increasing the shut in time after fracture stimulation from 6 hours to 24 hours resulted in an increase of flowback volume by 5%.

This paper addresses the importance of proper modeling hydraulic fracture conductivity in simulation of hydraulically fractured shale wells. It also highlights the importance of the amount and duration of fracturing fluid flowback, and explains how fracturing and fluid flow modeling softwares can be linked for better well performance predictions.
Surfactant Preflood to Improve Waterflooding Performance in Shale Formations
Authors: Morsy Samiha , Sheng J. J.
Published: June 2014

The lower primary oil recovery from shale formations accelerated the application of waterflooding technology as a secondary recovery mechanism at earlier time compared with conventional reservoirs. This situation suggests the EOR surfactant technology designed to promote additional oil recovery from fractured carbonate formations is a fit for these shale formations that are characterized by complex fractured lithology. The presented study investigates the idea to incorporate appropriate surfactant formulations at a low dosage as a preflood to waterflooding in shale formations. If properly designed, such surfactant in the preflood fluid will penetrate into the high oil saturation matrix or natural fracture region and accelerate the extraction of the oil in place by rapid imbibition. This extracted oil can readily move from the matrix, into the propped fracture system, and then is produced. Another benefit of the preflood surfactant is engineered in such that it leaves the matrix or natural fracture face water wet to facilitate oil movement during production.

This paper presents a study of a series of surfactant additives developed for extracting additional oil. Over 10 of special customized product blends were evaluated in laboratory for their effectiveness in increasing oil recovery of Bakken formation. Only one surfactant (Stim aid A) that was compatible with Bakken formation brine and crude oil, so it was the only one used for spontaneous imbibition experiments. The average porosity of the used Bakken reservoir samples was 5.8% with an average bulk density of 2.75 g/cc. The Bakken rock samples were pre-treated with different surfactant solutions and then used for water spontaneous imbibition experiments. During the spontaneous imbibition, the maximum oil recovery was from the samples that were pre-treated with 2 wt% of (Stim aid A) surfactant. The measured contact angles on Bakken samples showed an alteration in rock wettability that interpreted the improvement of Bakken higher recovery factors from spontaneous imbibition in surfactant solutions compared with brine solutions only.
Potential Pitfalls in Exploration and Production Applications of Machine Learning
Authors: Harris Cole
Published: June 2014

Exploration and production applications of machine learning algorithms are varied and numerous. However less attention has been given to the underlying assumptions critical to the application of such techniques. As the breadth of applications increases, it is critical to understand those characteristics of the problem and data that may impact the results.

Independent of the particulars of any specific algorithm, the standard model development and evaluation process may be described as follows. From a set of data points consisting of features and a response, a machine learning algorithm produces a model that may then be used to compute predicted responses on new data. This model can be applied to additional data for which the response is available, and performance estimated by comparing the predicted and actual response. However the reliability of this estimate may be strongly dependent on the statistical characteristics of the data. If the observations are not independent, then the results may not reflect performance in application.

To explore the impact of the violation of the assumption of independence on predictive model development and evaluation, standard machine learning algorithms were used to develop models from synthetic time series data and real monthly oil production data from the Wolfcamp play in the Midland basin. For both, standard approaches to model evaluation fail. For the oil production data, an alternative approach to model development and evaluation is shown to produce both more reliable estimates of model performance and improved model performance.
A Step Ahead Of 4D: The Integration Of Basic And Analytical Techniques To Drive The Changes In The Reservoir Simulation Model History Match: Case Study
Authors: Gomez Alonso Hector , Avila Runer , Peppard Bret , Gee Vicki , Baima Joao , Simone Alessandra , Tejera-Cuesta Pablo
Published: June 2014

This paper describes how the integration of basic, analytical and numerical reservoir engineering techniques in the Salema Field, and to really "understand reservoir dynamics". Because Salema is a mature field with a water injector, it was even more important to determine the presence of additional opportunities.

The application of traditional techniques such as conventional production analysis, diagnostic and Chan plots, material balance, Build-ups/Fall-off tests allowed the confirmation of different key events and water production mechanisms, to characterize the basic description of reservoir dynamics. The understanding gained was incorporated into the simulation model.

The methodology helped to minimize the number of uncertainties, narrowing down the variables that had a considerable impact on the history match, diminishing the number of potential realizations, and more importantly ended up in a more consistent and better understanding of the production behavior of the field.

Previous models were not able to reproduce the water production/reservoir pressure observed in some of the existing wells, clearly suggesting that the injected water volumes were not represented correctly in the reservoir.

The methodology can be considered as an integrated workflow towards the construction of any 3D reservoir simulation model, as it is simple and easy to follow. The 4D results obtained six months later, confirmed the results obtained from what the model predicted.

This case study is another example that success in subsurface disciplines depends more on the correct understanding of the reservoir than the degree of complexity with which it is modeled, using reservoir simulation to confirm the achieved understanding rather than just getting a history match.

All the integrated work resulted in the identification of two additional opportunities that will increase the final RF to close to 40% and contributed to extend the field life until 2022. Such opportunities have later been confirmed by the 4D seismic interpretation.

Due to Brazilian regulations the original well names are omitted in this document, instead generic well names have been used.
The Role of Boundary Conditions And Characteristic Length On Imbibition in Both Sandstones And Limestones
Authors: Kim Tae Wook , Kovscek A. R.
Published: June 2014

Spontaneous imbibition is generally defined as the displacement of a non-wetting phase by a wetting phase through dominant capillary suction forces in porous media. Spontaneous imbibition is a critical phenomenon in oil recovery from strongly water-wet and highly fractured reservoirs. The rate of spontaneous imbibition depends on permeabilities, relative permeability curves, block shapes, boundary conditions, fluid viscosity, interfacial tension, and wettability. The purpose of this study was to investigate the effect of characteristic length, boundary conditions, mobility ratios, and initial water saturation (Swi) conditions on the rate of spontaneous imbibition. We conducted spontaneous countercurrent and co-current water imbibition into cylindrical Berea sandstone (water-wet), Indiana limestone (mixed-wet), Texas Creme limestone (mixed-wet) with different boundary conditions, characteristic length, and Swi from 0 to 0.5. Brine (1 wt% NaCl) is used as the wetting fluid. Also, air, n-decane (n-C10), and Blandol are used as non-wetting fluids, respectively, to compare the effect of mobility ratio. To measure the rate of imbibition and oil production from each core, we used an X-ray computerized tomography (CT) scanner and an imbibition cell. The different mobility ratios show different oil production histories within the same time-scale. The observed 2-D and 3-D in-situ saturation profile histories of each rock clearly show different imbibition patterns for each boundary condition. Generally, low permeability limestones have more heterogeneous features than sandstones. We used three different boundary conditions including (1) all faces open (AFO), (2) two ends open (TEO, i.e., inlet and outlet face), and (3) one end open (OEO, i.e., one face of the core) systems. Characteristic length had an inverse effect on the rate of spontaneous imbibition. Experiments exploring the role of boundary conditions showed the effect of total open surface area for the oil production with different Swi. Finally, a scaling exercise to reduce data using various definitions of dimensionless time was introduced to reduce all experimental data. Further study is needed, however, to suggest an improved scaling group.