bluuebunny/crossref_metadata_2025 huggingface dataset:
Testing a Heavy Oil Well in Ultra Deep Waters: Challenges Overcome by the State of Art Technology in Atlanta Project, Santos Basin, Brazil
Authors: Pedroso Carlos A. , Monteiro Gabriel Goes , Marsili Marcelo D. , Libório Fernando , Pessoa Rui , Farias Marcelo
Published: September 2015

Testing heavy oil in offshore wells is, by itself, a challenge. But testing heavy oil, highly viscous (220 cP at the reservoir temperature), in ultradeep waters (1550 m), in a horizontal well equipped with a long open hole horizontal gravel pack (800m), using an electrical submersible pump (ESP) deployed in a slant section at 75 degrees is really a big challenge.

Atlanta is a post-salt oil field located 185 km off the coast of Rio de Janeiro. The field was discovered in 2001. The appraisal plan, started at the same year, included a deviated well to test the eocenic sandstones. A cased hole gravel pack was installed. The 90m interval tested, showed an unconsolidated sandstone, with high porosity (35%) and high permeability (5D). However, the oil is heavy and viscous (14° API and 228 cP in reservoir conditions), very acidic (TAN=9.8).

In 2006, a long horizontal well was drilled to validate the field development concept and evaluate the potential of this kind of well construction. However, crucial problems were faced in the drilling and completion phase, which included, directional control problems, massive fluid loss in the reservoir section, use of a LCM pill, premature screen during the open hole gravel pack operation, leaving a SAS completion. Even after these problems, it was decided to maintain the well test. An ESP was run in the DST string. After some flow (approximately 20 h), the screens were plugged resulting in their failure and therefore sand/solid production. The ESP locked with the produced solids and overheated, getting burned. The partially conclusive DST showed a severe damaged well, with high skin of 40. The well was abandoned without carrying out its objectives, and the horizontal completion was not fully evaluated.

The bad experience compromised the reliability of the project. However, in 2012, another operator decided to revisit the lower completion and testing procedures. After considering technology improvements and the lessons learned in the past operations, an extensive testing program was stablished and carefully executed. In 2013 a well was drilled, completed and successfully tested, with the ESP near the top of the reservoir. The zero skin completion and high productivity of the well encouraged the operator to drill and test the second well, this time using the ESP above the sea bed, inside the drilling riser, which included more difficulties due to the low temperature at that position.

This paper presents the main challenges and details on how they were overcome by the successful completion and testing of the first two production wells encouraging to move on to the next phase.
Assessing Field Development Plan for Green Fields Using an Integrated Asset Approach, an Angolan Case Study
Authors: Mora Jose Alberto , Khor Siew Hiang , Mason David , Nistor Mariana Laura , Willans Tim
Published: September 2015

Field development planning for an asset requires close interaction between different domains and departments, to reduce any potential uncertainties within the studied asset. Reducing uncertainties is crucial in investment preparation for a new green field development. By adopting an integrated asset approach, such cross-department interactions can be further improved by breaking down the barriers and assembling an integrated asset team with a common goal. This paper summarizes the construction of an integrated asset study for an offshore green field and compares the study against those obtained from the standalone-domain models. In this study, a reservoir simulation model was coupled to the wells and network models, which were further integrated to the processing facilities models and the asset economics evaluation model.

The aim of the study was to evaluate an existing field development plan (based on the traditional standalone approach) with an integrated asset approach to identify any possible constraints and potential deviations, enabling proactive actions to be taken on the asset management for future operations. The work presented here encompasses the use of various numerical simulation software applications working together in a single simulation environment, which allowed sensitivity analysis on different elements of the asset and evaluation of any possible impacts among the studied elements, such as manifold choke sizing and gas lifting parameters.

This assessment consists of a study from reservoir to economics, taking into account of wells, pipelines, surface equipment, production networks and downstream process facilities. The study demonstrated any components of the production network system and topside operating condition could impose constraints on the reservoir deliverability. Apart from evaluating various operating scenarios to best utilize the emerging capacity and to investigate back-out efforts and other challenges during the field development, it also provided guidance on how to further optimize the production system in terms of finding choke sizes over time and adjusting gas lift injection according to gas availability and operating pressure constraint. With its integrated asset approach, this study also presented a base case that could be extended with inclusion of gas lift distribution system to enable a more comprehensive analysis and asset field development study.
Using Data Analytics to Analyze Reservoir Databases
Authors: Lee Brian B. , Lake Larry W.
Published: September 2015

There are many public and private databases of oil field properties the analysis of which could lead to insights in several areas. Recent trend of Big Data has given rise to novel analytic methods to effectively handle multidimensional data, and to visualize them to discover new patterns. Using a commercial reservoir properties database, we created and tested four data analytic models to predict ultimate oil and gas recovery efficiencies, using the following methods borrowed from data analytics: linear regression, linear regression with feature selection, Bayesian network, and artificial neural network. The accuracy of result and robustness of each approach is presented and discussed.
New Electronics Ensure Increased Operational Efficiency in Highly Deviated, High Temperature Gas Well
Authors: Sagr Hani , Al-Sadoon Khalid
Published: September 2015

This paper describes a case story from Saudi Arabia where an extreme downhole environment required new developments in electric line intervention technology. This operation was the first time the new DC electronics package was used in the Middle East.

A major operator needed to test casing integrity and perform a perforation on a high pressure/high temperature well (310°F, 91° horizontal well). Standard wireline conveyance was not an option, pump down logging wasn’t available, and coiled tubing was too time consuming. New technology had to be considered. Multiple feasibility studies, including heat studies, were performed to verify that an e-line tractor equipped with newly developed DC electronics equipment would be able to execute the job under the extreme well conditions.

The job consisted of two runs; the first conveyed a cement bond log and a multi calliper imaging tool to 18,725 ft. while the second run conveyed a 3 3/8" gun to perforate the desired zone at 18,725 ft. The e-line tractor worked as planned despite the high temperatures and the 18,725 ft. extended reach section.

Using an e-line solution provided better data quality by having access to more advanced depth determination tools. Costs were reduced and the operational efficiency was increased by saving time. The environmental impact and risks were also reduced as the e-line solution eliminated mobilizing a rig.
Advanced Drilling Induced Fracture Modeling for Wellbore Integrity Prediction
Authors: Kostov Nikolay , Ning Jing , Gosavi Shekhar V. , Gupta Piyush , Kulkarni Kaustubh , Sanz Pablo
Published: September 2015

We present a method for modeling drilling induced fractures dynamic growth through a porous medium in the near wellbore region. Understanding the early time fracture growth behavior, and related near wellbore stress state, can provide an effective tool to improve the treatment selection through parameters such as particle size distribution and ideal drilling fluid rheology. Also, it will help with field diagnostics for various lost circulation treatments and lost return events.

ExxonMobil Upstream Research Company and SIMULIA® co-developed fully-coupled hydraulic fracturing modeling capabilities. The method is based on Cohesive Zone Modeling (CZM) elements, with pore pressure degrees of freedom, which were recently implemented into SIMULIA® Abaqus finite element package. The model was benchmarked with known solutions to analytical fracture growth regimes and validated with a laboratory scale experimental setup of hydraulic fracturing. The model allows for fluid leak-off from the wellbore and fracture faces into the porous medium, as well as an arbitrary injection schedule. Additionally, the physics of dynamic fracture growth and a variety of material properties and constitutive models for both the solid and liquid, are also captured in the model. The time-dependent fracture growth and interaction between the stress concentration region near the fracture tip and the wellbore result in a non-linear behavior of the near-wellbore stress state during early time fracture propagation, which was not possible to capture with static models. The model generation, execution, and post-processing are part of an automated workflow which requires minimal user time.

This analysis allows for recommendation of optimum fracture width for maximum increase in wellbore integrity in the target formation. This is done by selecting the fracture width at the mouth, at which a necessary increase in the near-wellbore tangential stresses has been achieved as to prevent initialization of further fractures.
Aluminum Alloy Enhanced Drill String Saves Over $500,000 by Increasing Small Rig Depth Capacity in Marcellus
Authors: Lehner Jeffry K. , Garcia Joe
Published: September 2015

An operator, seeking economies in constructing horizontal wells on pads, used a portable rig to air drill vertical holes and tangent sections to target depths of up to 8,000 ft TD, before using a larger rig to drill the curve and lateral well sections. With a 200,000 lb hookload rating, the portable rig had a depth capacity of approximately 6,000 ft using steel drill pipe (SDP). To increase the rig's depth capacity, the operator used up to 3,000 ft of aluminum alloy drill pipe (ADP) in a mixed SDP/ADP string, reducing weight and drag. Taking this approach, the operator has successfully achieved drilling objectives on 12 wells, for total savings of over $500,000 in spread cost.
Performance Evaluation of Automatically Generated Statistical Type Curves
Authors: Kuzma Heidi Anderson , Conradson Janette D.
Published: September 2015

Predicting the future production of Proved UnDeveloped (PUD) reserves is an important part of the evaluation of any asset. In the absence of production history, the most reliable way to make a PUD forecast is by analogy with production histories from similar nearby completions. This is most often done using a type curve. A traditional type curve is generated by normalizing to one the production histories of analogous wells and finding the shape of a curve which best fits their average decline. This is a tedious process when done by hand, and results are so difficult to test that in practice they rarely are. Our study introduces a methodology for testing statistical type curves based on 5-fold cross validation (5FXV), which rigorously evaluates the ability of an algorithm to produce accurate type curves, giving confidence that those type curves can be used to make careful and informed decisions. We offer two case studies to demonstrate the strength of the method and introduce a useful extension of the method.

A physio-statistical algorithm named BetaZi (BZ) automatically generates type curves which are considerably richer than a simple shape. They include information about actual production ranges abstracted as percentiles (90% of the time, actual production from a new well is expected to exceed the BZ p90 bound; 50% of the time it should exceed the p50, and so on.) 5-fold cross validation (5FXV) is used to test the performance of the algorithm. In 5FXV, a random 10% of the data from analogous wells is held out for testing and the remaining 90% is used to generate a type curve. A quantile-quantile (Q-Q) evaluation is made which compares the number of times the test data exceeded the bounds predicted by the type curve. The process is repeated 5 times on different subsets of data.

For this paper, we use 5FXV to estimate type curves for several plays in the Bakken and Kansas. The results show that excellent performance can be achieved if enough analogous wells are available to generate the type curve. Type curves that are made with wells that are not analogous can lead to overinflated estimations of value, as is shown with the Kansas wells. Finally, a p-score is computed for each well using the type curve, allowing production from wells of different histories to be conveniently plotted on one map or cross-plotted with other parameters.
Autonomous Marine Vehicle: A Cost Effective Technology to Manage Risk in Exploration and Production
Authors: Pai Sudhir
Published: September 2015

This abstract discusses the development of a multimission, autonomous sensor platform and describes applications ranging from measuring metocean parameters to detecting oil seeps in a cost effective manner with full Service Quality and HSE compliance. Examples from Gulf of Mexico and other offshore areas of the world demonstrate how persistent, unmanned mobile monitoring platforms have proved beneficial and effective to offshore exploration and production efforts, moving this technology from a state of infancy towards maturity.

Accurate meteorological and oceanographic data are essential for developing climate models and weather forecasts used in planning offshore exploration and production operations. A new remotely controlled, autonomous marine vehicle (AMV) supports a variety of sensors for conducting detailed metocean surveys across vast distances and under extreme conditions. To gather this data we use a wave powered AMV that harnesses kinetic energy from wave action to produce locomotion in the ocean, while remaining environmentally friendly and fuel-free; the vehicle is completely self-sustaining using solar panels to power its payloads. The platform includes navigational and control systems with communication to an operations center via satellite.

Once deployed the AMV uses no crew, requires no fuel and produces no emissions, thus eliminating both risk to personnel and impact on the environment. For less than the cost of a moored buoy or a vessel and crew, the vehicle provides mobility and long-range endurance for extended ocean monitoring missions. The propulsion system allows it to hold station in tidal or eddy currents. It simply steers to a designated waypoint—a programmed set of geographic coordinates. When it approaches the limits of a predefined watch circle, it turns around and heads back to the same point repeatedly. The AMV can maintain station for long durations with a watch circle of 25 to 50 m [82 to 164 ft], depending on currents and sea state. By contrast, the mooring systems of deep-ocean buoys employ ground tackle that produces a much wider watch circle the AMV can accommodate a broad range of off-the-shelf or custom sensors to fit the needs of the mission. A GPS receiver not only determines vehicle position, it provides a precise time stamp for all data recorded on the mission. Photovoltaic panels keep lithium-ion batteries charged to support WiFi, cellular or satellite communications systems, onboard data processing and various payloads.

This technology can and has assisted clients in providing early warning signs from a meteorological and oceanographic perspective for better managing risks and making critical decisions in protecting personnel and assets on installations both manned and unmanned. Value is enhanced when a number of these sensors are deployed on a swarm of vehicles to conduct pre-site baseline surveys for risk and insurance management.
Extra-Deep Azimuthal Resistivity for Enhanced Reservoir Navigation in a Complex Reservoir in the Barents Sea
Authors: Larsen David Selvåg , Hartmann Andreas , Luxey Pascal , Martakov Sergey , Skillings Jon , Tosi Gianbattista , Zappalorto Luigi
Published: September 2015

Goliat is an ENI Norge-operated oil field located in the Arctic Barents Sea, 85 km NW of the city Hammerfest (Fig. 1). The Goliat reservoirs have a complex structural setting characterized by a large number of faults and a relative high structural dip towards the flank of the structure. This challenging combination calls for horizontal production wells for effective drainage.

The Goliat field consists of several proven hydrocarbon reservoir units, but as of the date of this abstract, only Kobbe producers have been drilled. The Kobbe Formation is of Middle Triassic age and is divided into two main subgroups; the Upper Kobbe represents essentially a prograding deltaic system with mouth bars and tidal influenced lobes. In the Lower Kobbe, the system shifts into a more proximal, heterogeneous fluvial setting where sand bodies have limited lateral continuity.

One particular challenge is that the well design requires the 8½-in. reservoir section to be initiated in the overlaying Snadd shale. To minimize shale exposure in the landing section aggressive build-up rates are employed, decreasing the length needed in shale. However, a steep approach may lead to deeper penetration in upper Kobbe sandstone, which can result in unwanted intra-shale drilling. Therefore, the key to successful well placement is the early detection of the reservoir top and the accurate mapping of the reservoir sand architecture remote to the wellbore.

One way to successfully navigate a complex reservoir like Goliat is to use extra-deep azimuthal resistivity (EDAR) which can detect stratigraphic boundaries up 30m away from the wellbore in optimal resistivity environments (Hartmann, 2014). The development of advanced multi-component inversion modelling techniques (Sviridov, 2014) enhances the interpretations of resistivity data and can accurately provide real-time information regarding reservoir geometry.

On Goliat, the EDAR service provided the capability to detect the top of the reservoir at about 20 m true vertical depth (TVD) and nearly 100 m MD before entering the reservoir, enhancing accurate wellbore landing. Extra-deep measurements also helped reduced the uncertainty in fault detection, where related throw can be estimated based on the displacement of boundaries.

The use of a measurement with increased depth of detection (DOD), combined with advanced multi-component inversion while drilling techniques and real-time 3D visualization of data and reservoir model were vital to ensure the successful placement of the well. Real-time mapping of the reservoir geometry was key to optimize reservoir exposure.
The Effect of Reservoir Layering on Downhole Microdeformation Hydraulic Fracture Height Measurements
Authors: Sepehri Jay , Agarwal Karn , Davis Eric
Published: September 2015

The key strength of downhole microdeformation (i.e. tiltmeter measurements) is its ability to measure fracture height accurately by resolving the induced deformation pattern created by hydraulic fractures. The measurement provides additional insight into the actual hydraulic fracture height that might not be obtainable from microseismic data alone. The recent availability of combined downhole microseismic and microdeformation mapping in a single observation well has resulted in renewed interest in this technology.

Analysis of microdeformation data has typically been based on simple analytical models for fracture deformation in homogenous mediums, which might have limitations when rock layers with strong contrast in mechanical properties are present. This paper investigates the effects of layering on the deformation response induced by hydraulic fractures and the conditions under which using a homogenous model is justified.

A semi-analytic moduli perturbation method is used to calculate the deformation response caused by hydraulic fractures in a layered medium. The model can be used to estimate the deformation field attributed to finite rectangular dislocations up to the second order accuracy in a medium containing horizontal isotropic layers with different shear moduli. Effects of moduli contrast, distance of fracture tip to a layer interface, fracture crossing multiple layers, and tool spacing on estimation of fracture height and depth using downhole microdeformation are investigated.

Results indicate that, under most field conditions, the assumption of a homogenous medium is valid when inverting for fracture height using downhole microdeformation data. This is because the estimation of fracture height is dominated by the relative positioning of peaks in tilt response, rather than the absolute tilt magnitude, which can be affected by the elastic layer properties. Layering was observed to cause localized changes in tilt response near the layer interface without masking the overall fracture deformation response in most cases. The only scenario where layering was observed to have a significant effect on fracture height estimation was where fractures are contained within a relatively thick and uniform layer having strong contrasts in elastic properties from adjacent layers. Out of zone fracture growth into adjacent layers was observed to mitigate the impact of layering on the modeled tilt response, even in the presence of high moduli contrasts.
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

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

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

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

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

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

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

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

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

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.
Reservoir Modeling of a Structurally Complex Deepwater Field: A Gulf of Mexico Case History
Authors: Fontana S. , Atmajasetiadi N. A. , Brega F. , Villacres J. , Aliyev K. , Catalani C.
Published: September 2015

Reservoir modeling of structurally complex fields is particularly challenging when dealing with reverse or Y-shaped faults. In such cases, the modeling approaches usually tend to incorrectly reproduce or to simplify the actual geological situation. The scope of this contribution is to describe a case history where reservoir modeling activities are effectively performed for a field having high structural complexity, including Y faults.

The novel structural modeling approach has been applied for a deepwater oilfield located in the Gulf of Mexico. The Miocene-Pliocene reservoir consists of a series of stacked turbidite sandstone layers, which were deposited in a small basin against a salt ridge. A main set of WNW-ESE trending normal faults, as well as the allochtonous salt presence in the southwestern part, are responsible for the high compartmentalization of the field. Because of the complex fault framework, especially the Y faults geometry, a particular type of stair-step grid was adopted for the static modeling.

In presence of complex geological structures, such as reverse faults and/or Y faults, the use of the common pillar gridding modeling approach would lead to difficulties to build an effective geological model and, consequently, reliable dynamic reservoir simulations. In the current case, the adopted approach allowed building a static reservoir model accounting for its high structural complexity. The resulting grid (structural grid) is a corner point grid having specific characteristics that differentiate it from a conventional pillar grid. The main difference is the existence of apparent duplicated i, j, k indices in the structural grid. The apparent layer index (Geological Layer) property correctly reproduces the geological situation from a reservoir static standpoint. However, the flow simulators use the real grid layer index (Grid Layer), which may not correspond to the Geological Layer property, especially for complex fault patterns. Then, if such situation is well-known and handled with a proper strategy, the dynamic model will run effectively.

The positive results achieved with the described approach, despite the complicated nature of the studied field, must be highlighted. In fact, in the previous 3D grid models the field history match was never achieved, while the current structural reconstruction allowed a successful reproduction of the field history and, consequently, a more robust definition of the future activities to optimize the field production.