bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect Of OBM Contamination On PVT Properties And Its Impact On Field Development
Authors: Sharma Shivam , Elssa Moustafa , Agarwal Ankit , Deshpande Vaibhav , Batshas Siddhanta 
Published: September 2015

Abstract
PVT properties are undoubtedly one of the key inputs to any field development planning. Almost all the modeling workflows need reliable PVT properties. Having these reliable PVT properties require collection of good quality fluid samples which can truly represent the PVT behavior of the reservoir fluid. But, often the question comes up about the importance of collecting representative PVT sample because of the effort and money that goes in the process. We, therefore, in this study primarily aim to answer this question by clarifying the impact of using unrepresentative sample in the various modeling exercises.
Generally, classifying any sample as representative PVT sample requires two conditions – to be single phase and to have low miscible contamination. The focus of this paper is to study the miscible contamination and its effect on the hydrocarbon PVT properties.
While water based mud filtrate are immiscible with the hydrocarbon and do not create much problem, same thing cannot be said for Oil Based Mud (OBM) filtrate. OBM filtrate on account of their miscibility with the hydrocarbon can alter the PVT behavior of the sample.
In this paper an attempt has been made to find the errors induced by OBM in the PVT properties at various levels of contamination. Since, it is not possible to standardize these errors for all types of hydrocarbons as the trend varies greatly from fluid to fluid, we focused our work on low GOR and medium API black oil. Another objective of this paper is to find the acceptably low OBM contamination level for this fluid type. Additionally, impact of OBM contamination on field development planning and various modeling exercises have been scaled. The workflow discussed in this paper can be applied for other types of reservoir fluids as well.
Comparing Openhole Packer Systems with Cemented Liner Completions in the Northern Montney Gas Resource Play: Results From Microseismic Monitoring and Production
Authors: Reimer James , Ng Matthew , Dusterhoft Bryan , Birkelo Brad , Hlidek Barry 
Published: September 2015

Abstract
This study compares the performance of openhole packer to cemented liner completion systems across 30 single-lateral horizontal wells by one operator in the northern Montney gas resource play. With up to 5,400 Tcf of initial gas in place, the Montney Formation rivals the Marcellus play both in size and scope of future development. Our data demonstrates that the benefits of openhole completions relative to cemented liner completions include an average 25% increase in IP30 rates, an average increase from 7 to 10 Bcf in expected ultimate raw gas recovery per well, an average 13% decrease in stimulation period costs, plus an average 36% decrease in stimulation operating time (days), all on an unadjusted basis. When adjusted for total proppant placed or total fluid pumped on average per completion, the relative benefit of openhole systems ranges from 6% to 31% depending on the test metric selected.
Surface-array microseismic monitoring was conducted over two of the study wells, one involving a cemented liner system and one involving an openhole system, with the goal of understanding the stimulation patterns relating to each completion style. Focal mechanism solutions were calculated for individual microseismic events and displayed on a series of failure plane crossplots segmented by lateral distance from the stimulation stage mid-point. Our evaluation focuses on event counts and magnitudes, plus event clustering relating to failure style. This paper presents the first published case study to apply this new method of hydraulic fracturing analysis.
The openhole stimulation in our study area is characterized by a large event population, exhibiting a moderate cluster of high-angle failure initiating in the near-well region. Event clustering strengthens as lateral distance from the wellbore increases. The cemented liner stimulation is characterized by fewer events which exhibit weak clustering at moderate angles of failure across all distances, but particularly in the critical near-well region. Together with the observed magnitude histograms, these patterns clearly indicate different styles of rock stimulation. We infer that the openhole completion benefited from constructive interference during fracturing due to direct pumping access to multiple random initiation points afforded by the open annulus. In contrast, the cemented liner completion fails to develop a comparable complexity because the limited entry perforation spacing restricts constructive interference during the stimulation process.
Debate continues regarding the advantages of openhole vs. cemented liner completions. This paper presents an example of another technique to evaluate and compare stimulation patterns during hydraulic fracturing. The results from this study support the continued application of openhole completion systems to the Montney play in northeastern British Columbia.
Modeling of Perforation Erosion for Hydraulic Fracturing Applications
Authors: Long Gongbo , Liu Songxia , Xu Guanshui , Wong Sau-Wai 
Published: September 2015

Abstract
Predicting perforation erosion and its consequence on the pressure drop and fluid distribution can be an essential part of successful design of hydraulic fracturing treatments, especially for massive treatments along the horizontal wells when limited entry techniques are practiced. Both the perforation discharge coefficient and diameter change dynamically as proppant-laden slurries are pumped through perforations, making it necessary to consider the changes of these two variables in terms of time in order to predict the fluid distribution along multiple-perforation injection sites. In this paper we propose a practical model to calculate the rate changes of these two variables based on the abrasion mechanisms that have been experimentally verified. An example is presented to illustrate how the specific erosion parameters for both perforation discharge coefficient and diameter can be inferred from the field and experiment data. Our model shows that it is inaccurate to treat the change of the discharge coefficient and diameter alternately as assumed in some previous correlations. We emphasize that the new model can be conveniently incorporated in a typical hydraulic fracturing simulation to calculate the geometry change of the perforations and its consequent influence on the bottom-hole pressure and fluid distribution.
New Insights About Acid Fracture Conductivity at Laboratory Scale
Authors: Nino-Penaloza A. , Al-Momin A. , Zhu D. , Hill A. D. 
Published: September 2015

Abstract
Recent studies suggest that the fracture face texture affects the acid etching patterns and fracture conductivity of acid fracturing at laboratory scale. This paper presents a systematic study to clarify the effect of fracture topographic features on acid fracture conductivity. The importance is that most of the industry correlations to predict acid fracture conductivity are based on experimental measurements of acid conductivity at laboratory scale.
We conducted acid injection tests with fractured cores from the Austin Chalk and San Andres dolomite formations to investigate the effect of injection temperature, pumping time and acid type on fracture conductivity. We also studied the influence of the core fracture surface texture before the injection of acid. Two types of fracture surface textures were used—rough surface and smooth surface—to quantify the effect of surface texture. After the acid injection, we analyzed how conductivity was created by examining the computer-generated profiles of the fracture surfaces. For the smooth fractures, the uneven etching of the rock was responsible for creating roughness on the surfaces and the resulting in conductivity. For rough surfaces, acid conductivity was more related to the deepening of initial features on the sample surface than to creating more roughness. These results suggest that acid conductivity may be created by a combination of both mechanisms, from which deepening may be dominant in homogenous formations. Therefore, it is not correct to disregard the contribution of uneven etching to acid conductivity as suggested by previous publications.
Additionally, we found that it is acceptable to perform conductivity tests with either rough or smooth surfaces for soft formations such as the Austin Chalk. The props that kept the fracture open deformed the same for both textures; therefore the conductivity results did not differ significantly. For San Andres dolomite, the conductivity results were different due to the high rock embedment strength of this formation. These results serve as guidelines for performing acid conductivity tests.
Stress Profiling with Microfracturing and Sonic Logs in Antelope Shale
Authors: Malik Mayank , Singh Amit , Lal Manish K. 
Published: September 2015

Abstract
In shale development, picking optimum lateral landing points, and accurately predicting the height to which a hydraulic fracture will grow, requires knowledge of the vertical stress profile for both the target reservoir and the bounding layers. Stress profiles can be estimated using modern sonic logs in conjunction with geomechanical models but they require calibration with direct measurement of stresses from diagnostic testing, such as micro-fracture testing.
The organic-rich middle Miocene to lower Pliocene Monterey Formation is the main producing reservoir rock in the Southern California Offshore area. The most desirable reservoir rocks are the lower calcareous and massive chert zones due to the abundant presence of natural fractures which are necessary for these zones to be economically productive. The Antelope shale, the Monterey equivalent in the San Joaquin valley, may hold the same production potential. However, due to low permeability and less natural fracture density, the economic development of the Antelope shale will require stimulated completions.
This paper discusses the first case study on microfracture testing in the Antelope Shale. Results show that direct stress measurements can be successfully acquired at multiple intervals in a few hours and the vertical resolution nearly corresponds to log scale. Therefore, microfracture testing is an appropriate choice for calibrating log derived geomechanical models and obtaining a complete, accurate, and precise vertical stress profile. Further, these calibrated models helped to identify potential fracture boundaries across wellbore and evaluate fracture growth using 3D frac simulator. This resulted in optimized perforation and frac placement in multi-stage frac completion.
Microfracture tests were compared with leak off tests across adjacent wells to give more confidence in mud weight window for safe drilling. The closure stress calculated from calibrated sonic logs served as a yardstick for comparing with Leak off Test (LOT) and Formation Integrity Test (FIT) data. The closure stress along with corresponding formation pressure was used to adjust upper and lower boundaries of mud weight window for safe drilling. The case study demonstrates the effective integration of microfracture testing with sonic logs in the Antelope shale.
An Empirical Extended Exponential Decline Curve for Shale Reservoirs
Authors: Zhang He , Cocco Martin , Rietz Dean , Cagle Adam , Lee John 
Published: September 2015

Abstract
Over the last few years, the hydrocarbon production from shale plays has grown dramatically around the world. These unconventional resources have presented many challenges to the oil and gas industry. One of the biggest challenges for evaluators is to predict long-term shale production performance, especially in a timely and reliable manner.
For traditional reservoirs, the most common practice of reserve evaluation is Decline Curve Analysis (DCA), a method with decided advantages; it is not only the simplest and least time-consuming method, but it also accommodates the historical field uncertainties by honoring observed performance trends. However, applying the traditional DCA method to shale wells, engineers commonly encounter the difficulties of simultaneously matching the high initial production rate, the extremely sharp decline rate in the transient flow period, and the shallow decline resulting from boundary-dominated flow (BDF) in late-life. This suggests that traditional DCA may not be suitable for evaluating shale reservoirs. As a result, numerical simulation seems to be the best solution to provide reliable results but at the expense of extensive manpower, cost, time, and data requirements.
We propose an alternate DCA approach, which overcomes the shortcomings of traditional DCA or numerical simulation, to estimate the recoverable hydrocarbons. We suggest that a mechanism of "growing drainage volume" is an excellent way to conceptualize and model the performance of shale wells. This paper presents a new extended exponential form of the production decline analytical equation. Three empirical depletion terms, βe, βl, and n, have been used in the equation. The parameter βe represents the early, sharp decline in the transient period immediately after the well is put on production; the βl parameter represents the comparatively shallow decline in late-life when the progress of "growing drainage volume" plays the dominant role on the production performance; the parameter n is an empirical exponent. The overall decline rate can be calculated by a relationship involving, βe, βl, n, and time t. Even though the new method is not always more accurate than peer models, it is likely as accurate, and does not require the analyst to guess when to switch to a boundary-dominated flow model nor to force a switch to exponential decline.
We have tested and verified this new empirical DCA by both extensive field data and detailed numerical simulation results for seven wells. For each of these data sets, the comparisons between traditional DCA methods, and in some cases simulations, indicate the relative advantages of this new approach. Later, we applied this method to over 2,000 wells in the Eagle Ford shale. The analysis resulted in a relatively symmetric distribution for the empirical parameter n.
Interpretation of Real-Time Pressure Measurements to Detect CO2 Leakage
Authors: Haghighat S. Alireza , Mohaghegh Shahab D. 
Published: September 2015

Abstract
Carbon Capture and Storage (CCS) has been gaining support and popularity as one of the most viable CO2 emission mitigation methods. In order to assure underground CO2 storage safety and reduce leakage risk, different CO2 Monitoring techniques must be utilized. In-zone reservoir pressure, which is transmitted by Permanent Down-hole Gauges (PDG), is a widely used monitoring parameter that can provide important indications when CO2 migration/leakage occurs. As part of a monitoring package, a Real-Time Intelligent CO2 Leakage Detection System (RT-ILDS) was developed for CO2 storage project at Citronelle Dome, Alabama. This system, which is designed based on Pattern Recognition Technology and Smart Wells, is able to identify the location and amount of the CO2 leakage at the reservoir level using real-time pressure data from PDGs.
In this work, history matched reservoir simulation model (based on 11 months of actual injection/pressure data) was used for CO2 leakage modeling study. High frequency real time pressure streams were processed with a novel technique to form a new data driven RT-ILDS which was able to detect leakage characteristics in a short time(less than a day). RT- ILDS also demonstrated high precision in quantifying leakage characteristics subject to complex rate behaviors. Finally the performance of RT- ILDS was examined under different conditions as multiple well leakage, availability of additional monitoring well, uncertainty in the reservoir model, CO2 leakage through the cap rock and multi-well leakage.
The objective of this study was to proof the concept and feasibility of using real time pressure data from PDGs in order to notice occurrence of leakage and identify its characteristics as location and rate in a real CO2 storage project by utilizing data mining techniques.
Correlations Between Nano-Scale Geology and Porosity Logs of Vaca Muerta Shales
Authors: Hu Dandan , Garcia Mariano , Chen Cheng , Wyatt Douglas , Martysevich Vladimir 
Published: September 2015

Abstract
The porosity and geological texture of tight oil and shale gas samples have significant effects on reservoir production and oil/gas recovery. Classical measurements, such as porosity logs, alone cannot accurately predict the amount of oil and gas storage and final recovery ability because of aspects, such as the rough resolution of the technique and indirect measurement methods; therefore, the corresponding calibration is a critical step. Additionally, the presence of nanopores and micropores within organic matter or on the boundaries between mineral components affect formation properties, and logs cannot resolve at this scale. This paper presents the internal structure imaging and analysis studies of a series of Vaca Muerta Shale samples from different depths and basin locations. Methods include the nanoscale scanning electron microscope (SEM) imaging, pore size distribution analysis, various imaging based simulations and calculations, and field logging data comparisons. As stated in the literature, the Vaca Muerta Shale is a highly promising continuous tight oil and shale gas reservoir and is an important petroleum source bed for oil production.
The results indicate that the trend of petrophysical properties, such as porosity as a function of depth, is consistent with logs; but, lab measurements suggest a relative shift of log values, which demonstrates the importance of lab calibration. The internal structures of samples have a stable trend as the depth increases in the way most pores exist within the organic matter at deep depths, while the position of pores gradually moves to the boundaries of mineral components at shallow depths. The shape of the pores varies as the depth increases. This is one of the first papers discussing combining novel digital rock imaging techniques with traditional logging methods. Efficient and accurate digital rock studies can help provide a good calibration using logging analysis, which can eventually benefit reservoir evaluation and oil/gas production. Comparison between direct observations/image based calculations and logging data analysis provide explanations of changing trends of pore and organic matter. Other important petrophysical and geological properties, such as permeability, total organic carbon (TOC), and so on, through lab measurements are also discussed. This study provides insight into the development of predictive stratigraphic framework and a conceptual reservoir model for the Vaca Muerta interval and also helps improve the understanding of its storage and flow capacity.
SAGD Performance with Temperature Dependent Properties - An Analytical Approach
Authors: Heidari M. , Hejazi S. H. , Farouq Ali S. M. 
Published: September 2015

Abstract
Steam-Assisted Gravity Drainage (SAGD) is one of the successful in-situ thermal oil recovery methods in Alberta, Canada. There are several tools for design and evaluation of SAGD projects, for instance thermal reservoir simulators and simple analytical models. Although time consuming, reservoir simulators handle reservoir heterogeneities. On the other hand, existing analytical models are limited to simple configurations with constant rock and fluid properties. Therefore, providing a simple and fast analytical model that can accurately analyze a SAGD project with variable properties is very desirable.
In this study, a semi-analytical model is introduced to investigate the effect of temperature dependent properties such as thermal conductivity, heat capacity and rock density on the performance of SAGD process. The semi-analytical model solves transient nonlinear heat transfer equation coupled with the continuity equation in a sequential manner. First, nonlinear, transient partial differential heat transfer equation is transformed to an ordinary differential equation using Kirchhoff's transformation and Heat Integral Method (HIM). The ordinary differential equation is solved by fourth order Runge-Kutta method. Second, the continuity equation is solved using new temperatures and as a result, production rates and shape of steam chamber are determined. The stability of sequential methods is sensitive to the spatial and temporal discretization. A criterion for time step selection is defined based on the Courant number and Peclet number to guarantee the stability of this semi-analytical model. The Courant number depends on the steam temperature and fluid and rock properties of reservoir, i.e. absolute permeability, oil viscosity and porosity. Peclet number depends on the velocity of steam chamber interface, penetration depth of heat and thermal diffusivity at steam temperature.
The results of this study illustrate that the temperature dependent physical properties affect the temperature distribution ahead the steam chamber. The impact on the cumulative oil production and production rate is significant. Moreover, several field scale problems were simulated with both the proposed semi-analytical model and a commercial reservoir simulator. It is revealed that, the locations and shapes of steam chamber as well as production rates predicted from semi-analytical model and reservoir simulators are in an excellent agreement.
The proposed semi-analytical model runs in a small fraction of runtime of the numerical simulator, yet it provides reasonable results. Thus it has the potential to be used as a tool for quick SAGD evaluations. A runtime comparison between this model and the numerical simulator is also provided.