bluuebunny/crossref_metadata_2025 huggingface dataset:
Pipe-Conveyed Microfrac Testing and Acoustic/Image Logs Enables Gas Depleted Formation Stress Calibration in Carbonate Reservoirs
Authors: Franquet Javier A. , Jaiyeola Abiodun I. , Al Beshr Huda , El-Hamawi Mohamed , Elarouci Fethi
Published: September 2016

Development plans in largely depleted carbonate gas bearing reservoirs are dependent upon having a complete understanding of reservoir mechanical behavior under change of in-situ stress state. The accuracy of 3D geomechanical models relies highly upon proper tectonic strain and stress calibration using in situ straddle packer microfrac testing conducted in vertical pilot wellbores. Pipe-conveyed straddle packer microfrac tests have become an important technology to measure in-situ fracture closure stress in depleted and non-depleted reservoir layers in order to quantify the stress contrast among multiple intervals with different reservoir pressure regimes.

This case study describes the use of microfrac tests to validate and calibrate the horizontal stress profile in various reservoir intervals of a carbonate formation that had been developed to a substantially depleted condition. Well-injection plans, cap-rock integrity assessment, stress contrast, hydraulic fracture containment, and minimum horizontal stress estimations can all be quantified from multiple microfrac tests recorded at various depths of the reservoir formation. The fracture closure analysis was conducted using three different methods: (i) square-root of time, (ii) G-function and (iii) Log-Log plot. The final fracture closure measurement was obtained after consolidating the three fracture closure identification methods in all injecting cycles conducted on each microfrac station.

The integrated post job microfrac analysis includes borehole acoustic processing and resistivity imaging. The borehole acoustic response is used to estimate not only formation mechanical properties but also log-derived stress profiles while borehole Imaging is used to select the microfrac points and to confirm the induced borehole fracture created during the pressurization of the straddle packer tool. Formation breakdown, fracture reopening, propagation and closure at multiple reservoir layers provide the necessary in situ measurements to calibrate the stresses change due to pore pressure depletion. This information provides a better understanding of the in situ stress state in depleted formations that reduce risk in designing future gas development strategies in the field.
Enhanced Heavy Oil Recovery by Liquid CO2 Injection under Different Injection Strategies
Authors: Farzaneh Seyed Amir , Seyyedsar Seyyed Mehdi , Sohrabi Mehran
Published: September 2016

There are vast resources of heavy oil located in reservoirs in which the reservoir temperature is lower than or in the vicinity of the critical temperature of CO2 (31.1 °C). A good example of that are the huge resources of heavy oil in the Alaska North Slope. In these reservoirs, CO2 would be in liquid state and would exhibit higher viscosity and solvent power compared to gaseous or supercritical CO2. The objective of this study is to experimentally assess the potential of liquid CO2 injection for enhancing recovery from these reservoirs. A positive outcome could bring significant economic and environmental benefit by improving oil recovery and at the same time managing produced CO2 from neighboring reservoirs.

A comprehensive series of coreflood experiments were performed using a heavy crude oil under the conditions of a heavy oil reservoir in the North Slope, Alaska. Different injection scenarios were experimentally simulated including water flood, CO2 flood, as well as combined water and CO2 injection in the form of WAG and SWAG injection. In order to investigate the impact of an initial depletion stage on the performance of CO2 injection, the impact of the amount of dissolved hydrocarbon gas in crude oil was also investigated and the results of the different injection scenarios were compared with each other and with the base case (waterflood).

The coreflood results show a very good performance for liquid CO2 injection in the heavy oil system tested in this work. Dissolution of CO2 in heavy oil and the consequent significant reduction in the oil viscosity leads to a prolonged period of oil recovery during CO2 injection. This is different from waterflood whereby oil recovery almost ceases as soon as water breaks through. Combining CO2 and water and injecting CO2SWAG (simultaneous injection of water and CO2) increased oil recovery more than water or CO2 injection alone. CO2WAG injection (alternating injection of water and CO2) brought about an ultimate oil recovery of 74 % IOIP. This was a staggering 30% higher than the ultimate oil recovery by waterflood under the same conditions.
Dynamic Reservoir Characterization from Microbuildups with Formation Tester
Authors: Azari Mehdi , Khan Waqar , Jambunathan Venkat , Hadibeik Hamid , Iskander Fady , Malik Mayank , Nash Derek , Kurniawan Bobby
Published: September 2016

Historically, drillstem tests (DSTs) have been considered the standard for establishing the productive capacity of oil and gas reservoirs, providing measurements, such as formation pressure, permeability, and skin factor. In a recent study, the possibility of obtaining similar results was investigated by using wireline formation testing tool.

The pressure-transient data obtained during the fluid-sampling cleanout operation was used to obtain reservoir properties. Of particular interest, spherical and radial flow models were successfully fit to very short buildup times (on the order of a few minutes) after pumpouts. To obtain similar formation properties from the shorter duration buildup times associated with flowline surging to clean debris (on the order of seconds), a process referred to as "sneezing" was investigated, yielding comparable results. Sneezing is performed several times during the fluid pumpout and sampling operation. Repetitive analyses of these microbuildups along with other pressure buildup periods in one pumpout location can help reduce uncertainty with respect to the estimation of formation properties.

This paper presents three examples, including both oil- and gas-bearing formations, ranging in terms of lithology, permeability, and pressure. Formation permeability, skin damage, and reservoir-pressure values were evaluated from pressure-transient analyses during pumpouts. Results clearly demonstrate that zonal thickness, permeability, and anisotropy are key contributors to microbuildup analysis. Evaluation of reservoir properties is performed in real time with this approach to help optimize field-development plans. Analyzing these microbuildups is a unique method for supplementing/replacing the standard longer-duration pressure-transient analysis at the lowest-possible cost to the operator.
Specific Procedure for an Offshore Chemical EOR One Spot Pilot in a High Salinity High Temperature Environment
Authors: Morel Danielle , Al-Amrie Omar , Delattre Eric , Cordelier Philippe , Greder Hugues , Rivero Mayela , Romero Carolina , Bursaux Romain , Peltier Sophie , Levitt David
Published: September 2016

In 2014, Total performed a surfactant-polymer one spot pilot offshore to test the effectiveness of inhouse developed surfactant molecules to mobilize trapped oil. This paper describes the deployment of this pilot, as a key step of the derisking roadmap of chemical EOR under the harsh salinity and temperature conditions of Middle East carbonates. During several years of R&D and focused studies on this field of the Emirates, a surfactant polymer formulation has been developed able to achieve very low residual oil saturation at core level. The question of testing the formulation in the field has been addressed in parallel to the laboratory work, through extensive surface and subsurface integrated studies, in order to define which type of pilot would be the more suitable.

The paper addresses several aspects: –Pilot type selection from a geosciences point of view and versus objectives and information provided: where, how many wells, time response, cost–Monitoring needs: base line establishment, injection and production follow up,–Surface issues related to the pilot in this offshore context: injection and production top side facilities–Chemical logistics when part of the formulation is a R&D chemical, to be manufactured on purpose, and imported in due time, including the choice of premix versus on line mixing products–Management of a pilot as a project but still with the specificities of derisking and qualifying a technology on a mature field (from preliminary study to project execution)–Offshore concerns, with the added difficulty of a H2S environment

After a cautious analysis of the pros and cons, a one spot pilot has been sanctioned. The design of the pilot versus effective realization is provided, together with the decision tree that was constructed in order to face any operational issue. The paper emphasizes how a strong project management, and headquarters/operational team collaboration allowed completing a safe and successful pilot, ultimately achieving ultra low residual oil at the one spot scale.

The success of a pilot project is conditioned to the strict application of a rigorous methodology of study, validation, and execution, like any development project
Implementing Various Tactics to Overcome the Effects of the Big Crew Change
Authors: Kamble P. D. , Bagga P. S. , Kakade R.
Published: September 2016

Intelligently said by Albert Einstein, "The only source of knowledge is experience" is the basis of the imminent crisis faced in the industry unless proper steps are taken. Born during 1946-1964, baby boomers make up a major portion of the oil and gas industry who will be retiring in the next 5 years. This will change the entire demographic profile of industry leading to a change in the experience profile. Hence, once again reminding us to equip younger generation with skills from older fleet. At an age where development and advancement of technology such as hydraulic fracturing, casing while drilling and gas hydrates research is going on, technical talent is a treasure. Especially now when there is a threat of losing potentially talented amateurs due to lack of jobs, there is a need of knowledge transfer between these retiring veterans and young professionals in a company, within a restricted amount of time. If harnessed in the right way, the two generations can complement each other in creating the perfect team and work better in a multifaceted approach.

As mentioned, in today's scenario of hiring-firing cycles in the industry, the baby boomers might leave the industry facing with the problem of skill set gap. This issue is amalgamated by low representation of mid career employees, again owing to the firing tendencies of the volatile industry. Although the impending doom of Big Crew Change has been known for quite some time, no proper solution has been found. The authors of this paper have identified few effective methods to strategize production and future growth. These strategies are synched with Oil and Gas industry and proposes to help in the following ways: To bridge skill set gapTo scrap outdated and complex technologiesTo transfer knowledge, digitize it and strengthen middle-career crewTo learn, capture and duplicate the knowledge before it is lost

Complementing each other's working styles and various kinds of knowledge, together, the various generations can bridge every gap in the long run. The paper will talk about all the steps that can be taken by companies in the next 3-5 years to deal with the big crew change and being a one of a kind industry what we can do to retain the unique and brilliant expertise. Authors provide a "Knowledge Security" triangle which will benefit all companies to solve this issue. The scenario based case study of India and USA has also been discussed.
Characterizing and Predicting Reservoir Quality in Argillaceous Sandstone Reservoirs, Offshore Brunei
Authors: Saha Sourav , Espejo Irene , Gelinsky Stephan , Keym Matthias , Naeth Jochen , Jäger Günter
Published: September 2016

Prospects near existing infrastructure can be economically attractive; however, reservoir quality prediction is crucial to de-risk opportunities further from infrastructure including deeper, high pressure and high temperature (HPHT) opportunities. Understanding shallow reservoir properties is important and needs to be translated to predict the deeper reservoir quality where compaction and cementation often have a negative impact on reservoir quality.

The Baram and the Champion river systems deposited sediments offshore Brunei in various depositional environments, with multiple pairs of sandstone-siltstone reservoirs and bounding mudrock facies. The observed variation in the composition of reservoirs is an indication of a slight difference in provenance between the two river systems; however, the different is texture is an indication of length of sediment transport.

Qualitative and quantitative petrographic information was collected from a large number of thin sections from eight representative wells. Based on the overall sedimentary structures and textures observed in thin section, four (4) sandstone and three (3) siltstone petrofacies were described. Detailed point-count (300 counts per thin section) data was collected from these sandstones and siltstones for compaction and diagenetic modelling. Present day intergranular volume (IGV), macroporosity and cement types were quantified from thin sections. These parameters were subsequently calibrated for forward-modelling, using burial histories at each well location. The model was then blind-tested in order to verify the expected present day prospect porosity and permeability ranges. The resulting model was correlated with petrophysical well log data, to allow connecting rock properties to prospect seismic responses.

For the first time, a comprehensive offshore Brunei sedimentary petrology database was assembled covering major depositional environments from both dominant river systems. This database was compiled in a reservoir quality modelling software, which will allow for burial history-based reservoir quality predictions, both regionally and at prospect locations.
Petrophysical Characterization of Tight Sands in Granite Wash, Anadarko Basin
Authors: Agarwal Aditya , Rai Chandra S. , Sondergeld Carl H. , Truax Jerome
Published: September 2016

The Granite Wash formation is made up of arkosic detrital material and is deposited as a series of overlapping submarine fans. These tight gas sands have very low porosity (<8%) and permeability (<.001 md). The Granite Wash contains upto ten discrete production zones. The recent drilling activity in Granite Wash play has increased substantially in the oil and condensate rich zones. These formations are highly complex and heterogeneous which poses a major challenge in characterizing them. Identification of best reservoir rocks in the Granite Wash has long been a piece of puzzle.

Petrophysical measurements (porosity, mineralogy, mercury injection capillary pressure, permeability, NMR) have been performed on 115 ft of core from a well located in the Wheeler County. The core has been recovered from the Carr formation. The porosity in the formation ranges from 1.2% to 7.4% with an average porosity of 4.3±1.3%. The porosity of the samples increases with an increase in grain size. The mineralogy in the formation shows a wide variation and consists of quartz (24±8%), feldspars (50±13%), clays (23±14%) and carbonates (3±6%). The rock quality is severely affected by the pore filling chlorite (~20%) in the formation. The MICP and NMR data shows bimodal distribution of pore throat size and T2 distribution, indicating presence of two types of pore system.

We utilized principal component analysis and K means clustering technique to identify different clusters of similar petrophysical properties. Based on our clustering analysis we identified three rock types in the Carr formation. A unique mercury injection capillary pressure curve was observed for each cluster. The thin sections support the different rock types in the Carr formation.

The variable grain density (2.62 gm/cc to 2.78 gm/cc) and presence of chlorite (~20%) complicates the estimation of porosity from neutron and density logs. Also, the presence of K feldspar (0 to 12%) forbids the use of gamma ray log in estimation of clay content in these formations. Based on the results of the core analysis, a method to identify the best reservoir rocks from conventional well logs is suggested.
Source Parameters of Repeating Microseismic Events During Hydraulic Fracturing Operations
Authors: Chao Kevin , Prieto German A. , Du Jing
Published: September 2016

A complete microseismic event catalog with accurate source parameters can lead to a more thorough understanding of the temporal and spatial variation of stress during hydraulic fracturing operations. We detect, locate, and characterize repeating microseismic events by determining their source parameters such as magnitude, stress drop, and rupture size, and analyze the continuous microseismic data recorded by one borehole array during a hydraulic injection process. With an existing microseismic event catalog, we first re-calculate accurate moment magnitude and stress drop using estimated source spectra for all events. In addition, we detect and locate smaller events that show only clear S-wave arrivals using a template-matching and waveform cross-correlation technique to identify repeating microseismic activities. We obtain the template waveforms by stacking similar waveforms from repeating microseismic families. Among the ~1300 re-computed events, the moment magnitude calculated from the P- and S-waves spectra analysis ranges between Mw −1.5 and −3.5. These events are located within a 700m by 200m area as much as 250m deep. Our results indicate a fault radius on the order of one to six meters and fault slip between 10−5 to 10−3 cm around the fracturing region. In addition, using a matching-filter technique, we detect and locate low signal-to-noise ratio events that we consider repeating microseismic events. Our observations indicate that most repeating families occur at later times in shallower layers. Also, we observe a strong magnitude dependence of the stress drop, with larger magnitude events exhibiting significantly greater stress drops than smaller ones, in contrast to tectonic events in California or Japan. Our estimations of source parameters provide a key to a more in-depth understanding of the relationship between hydraulic fracturing and microseismic activity.
Development of a Chemical Flood Simulator Based on Predictive HLD-NAC Equation of State for Surfactant
Authors: Jin Luchao , Li Zhitao , Jamili Ahmad , Luo Haishan , Delshad Mojdeh , Lu Jun , Shiau Ben , Harwell Jeffrey H. , Rui Zhenhua
Published: September 2016

Chemical flood reservoir simulators developed based on component partitioning model or empirical phase behavior model lack the effects of physical properties such as surfactant structure and oil properties i.e. equivalent alkane carbon number (EACN) on microemulsion phase behavior. Hence, these simulators have limited function in helping formulation design. A typical empirical microemulsion phase behavior model is the Hand's model that is used in UTCHEM, a benchmark chemical flood compositional simulator. However, it needs several matching parameters to fit phase behavior experiments and requires iterative calculations to solve phase compositions. Therefore, it is desirable to develop a chemical flood simulator with a more efficient and physics-based phase behavior model.

This work incorporates a physics based HLD-NAC equation of state (EOS) into UTCHEM. A non-iterative flash calculation algorithm based on HLD-NAC microemulsion EOS is developed, which uses simple equations to represent plait point, binodal curve, and tie-lines. Input model parameters include quantitatively characterized physical properties, such as oil EACN, reservoir temperature, surfactant structure properties (head area and tail length), and optimum solubilization ratio. Therefore, the effects of these parameters on oil recovery can be systemically studied. Coreflood simulation results are validated against the Hand's model.

Compared to the Hand's model which requires at least 5 matching parameters and with limited predictability, the HLD-NAC EOS can reproduce microemulsion phase behavior with surfactant tail length as the only fitting parameter. Comparing coreflood simulations using the HLD-NAC model and the Hand's model shows that the same oil recovery curves are obtained when slug at optimum salinity is injected. However, for corefloods using a salinity gradient design, HLD-NAC model predicts higher oil recovery than the Hand's model. The reasons for the differences are analyzed by examining the simulated solubilization ratios and ternary phase diagrams at different salinities. Moreover, numerical experiments show that the HLD-NAC model improves the phase behavior computational efficiency by approximately 65%. The effect of live oil at reservoir pressure is also investigated. Results indicate shifted optimal salinity and solubilization ratio due to solution gas and pressure lead to larger microemulsion bank.

Owing to the physical significance, simplicity, and computational efficiency of the HLD-NAC EOS, this novel chemical flooding simulator proves to be a fast and promising tool to speed up surfactant screening process and helping chemical formulation development and injection designs.
First Ever 14 ¾ X 17 ½-in Rathole Elimination in Gullfaks Satellite Using Downhole Drilling Mechanics and Dynamics Tool and Latest Features on PDC Design
Authors: Khalil Haitham , Blackburn Jason , Harmer Richard , Skofteby Geir , Kallestad Richard
Published: September 2016

The objective of this paper is to share the results obtained from in-depth analysis using a down hole mechanics and dynamics monitoring sub, which lead to the first successful Gullfaks Satellite 14 ¾ x 17 ½ -in Rathole elimination operation through challenging lithology.

Shallow gas is encountered in the Gullfaks South area at a true vertical depth of between 335-339m (from MSL), and a casing design incorporating a 16-in liner is utilized to isolate this interval. A 14 ¾ x 17 ½ -in section is then drilled to isolate weak and unstable formations, and in all previous wells this section was drilled with a two run strategy. The first run to drill to section target depth (TD) while hole opening, followed by a dedicated second run to open the rathole. An opportunity was identified to improve well construction performance by eliminating the dedicated run to open the rat-hole, and tailoring the bit design to overcome the challenging lithology and high levels of shock and vibration seen on offset wells.

Detailed pre-job planning and BHA design analysis was combined with new downhole technologies to overcome these challenges. Dual reamers were used within a Rotary Steerable System (RSS) BHA to drill the 14 ¾ x 17 ½ -in section and eliminate the rat-hole in one run. This innovative approach involved drilling to section target depth (TD) using an upper ball drop reamer, tool positioned 45 meters behind the bit for hole enlargement while drilling, and then pulling back to position the bit at rat-hole shoulder. At this point the upper reamer was de-activated and a lower on demand hydraulically activated reamer, mounted directly above the RSS was opened to eliminate the rat-hole. Due to excessive shocks & vibrations experienced on offset wells, a down hole drilling mechanics & dynamics sub was utilized to provide real-time information about downhole forces and BHA motions, combined with a tailored bit design to control depth of cut in sandy intervals. This unprecedented approach resulted in 2.5 days saving.
Evaluating and Optimizing Refracs - What the Diagnostics Are Telling Us
Authors: Leonard R. S. , Woodroof R. A. , Senters C. W. , Wood T. M. , Drylie S. W.
Published: September 2016

Refracturing continues to provide operators with the opportunity to add production at a fraction of the cost to drill and complete a new well. Various re-stimulation designs and diversion techniques are currently being utilized to maximize contact with previously un-stimulated rock. Optimizing this process involves evaluating all available diagnostic, pressure and production data and determining the optimum design that maximizes recovery. This paper describes how these diagnostic technologies have been employed to evaluate and optimize refracs in four major North American basins.

The process of refracturing and recompleting wells continues to improve. Much of this improvement comes from the optimization of techniques through completion diagnostics. Diagnostics provide data that can quantify the amount of the lateral treated and the effectiveness of diversion. Operators are focused on bridging the gap between the completion methods commonly used at the time the well was originally completed and the methods of today. Application of completion diagnostics also assists in identifying opportunities to further reduce the cost of the project while achieving similar results. In this study, proppant tracing followed by spectral gamma ray logging was employed to evaluate the effectiveness of the refracs, the extent of new rock contacted, the benefits of reperforating, and various diversion methodologies.

Diagnostic results from 121 vertical (34) and horizontal (87) refracs covering 16 different formations and 26 different operators were analyzed and compared based on stimulation effectiveness and performance. The wells were then grouped by well type, formation and the basic refracturing technique that was utilized. In addition to the macroscopic data interpretation; four case histories are presented from the Barnett Shale, Permian Basin, Eagle Ford, and Haynesville. These case histories include before and after reservoir production matching with fracture half-length and effective conductivity calculations along with the diagnostic analysis of new and existing perforation coverage, diversion effectiveness, and ultimately the % incremental estimated ultimate recovery (EUR).
Wolfcamp Completions: Lessons Learned through the Implementation of Completion Diagnostics to Optimize Existing Drilling and Stimulation Practices
Authors: Warren Mark N. , Dempsey Christopher J. , Woodroof Robert A.
Published: September 2016

The lessons learned in the Wolfcamp formation from utilizing completion diagnostics have greatly increased productivity over the years. By employing proppant tracers and subsequent spectral gamma ray logging, along with water-based and oil-based chemical tracers and subsequent produced fluid analysis, trends have been observed, and, where appropriate, changes have been made to the wellbore design, landing interval and subsequent frac design. Throughout the changes, completion diagnostics were utilized and referenced to hydraulic fracturing characteristics, drainage patterns, wellbore spacing, geologic identifiers and overall completion effectiveness, as measured by post-stimulation well performance.

This paper reviews many of the insights that have been developed through the use of completion diagnostics in the Wolfcamp formation, as revealed by an extensive database of completed wells. These insights have led to completion optimization, improved well architectures, production enhancements and field-wide cost reductions. The lessons learned should prove useful for both established Wolfcamp operators as well as those new to this play.
A SMART Framework for Contextualization of Drilling Data for Supporting Drilling Workflows
Authors: Arumugam Sethupathi , Gupta Sanjay , Rajan Shebi , Ranjan Rajeev
Published: September 2016

Realtime operations generate huge amount of data that are stored as chunks in the WITSML data standard. Current WITSML model (version 1.4.1 or prior versions) does not provide enough flexibility to categorize channels. It is a challenging feat for users to dig through WITSML log object from a specific hole section or from a specific rig activity to zero in on any specific time frame in the aftermath of a NPT. This paper proposes the framework for a smart framework that organizes drilling data based on the rig activity within appropriate hole section without making any changes to the WITSML standard. This framework identifies rig activity, macro states and well events.

This framework proposes a logical hierarchical tree structure starts with parent node based on hole sections, WITSML objects are aligned with corresponding hole sections. Each hole section is further divided into child nodes based on rig activity. Realtime workflows are aligned to the corresponding rig activity e.g. ROP optimization, wellbore stability workflows are aligned to drilling activity parent node. Based on this parent child relationship user can retrieve any Hookload sequence for any tripping operation, for any hole section without any hassles. Any changes within the framework, updated by the user, for the current activity will be auto adjusted for subsequent activities within the tree structure. Identifying risks and events from the historical wells for future analysis is often viewed as a time consuming task; this solution aligns risks and events for each hole section under individual rig activity making it easier to retrieve it from historical wells during well planning. Along with logical organization of drilling data, this framework also offers an Operational Time Vs Depth plot that provides a Bird's Eye view of the entire well operations.

This solution can be used as a comprehensive logical structure for managing realtime and historical data from configuration to operational execution. Managing of historical and offset wells is simplified at the click of a button compared to the conventional method of data search.

The workflow provides the flexibility for minimizing user intervention by eliminating the need for repetitive configuration activities for each hole section within the wellbore. This workflow can be effectively used by a novice or an expert user.
Duvernay Proppant Intensity Production Case Study and Frac Fluid Selection
Authors: Leshchyshyn Tim , Thomson Jim , Larsen Cory
Published: September 2016

The hundreds of Duvernay wells near Fox Creek, Alberta, Canada are usually fracture stimulated with either slickwater or hybrid slickwater-crosslinked water treatments with a large acid spearhead. There is a 14.6% higher 3-year average cumulative production total for slickwater treated wells versus hybrid fluid system treated wells. Additionally, the slickwater systems have an average 53.8% lower frac chemical cost compared to the 50/50 slickwater-crosslinked water hybrids frac stimulation systems. There is a very linear trend between the total volume of fluid pumped to the total 2 year BOE production; the higher the treatment fluid volume, the greater the stimulated reservoir volume (SRV) and the higher the resulting production. The production case study shows that wells treated with an average of 25,000 m3 of water have an 80% higher average 2-year cumulative production result compared to wells that only use an average of 13,000 m3.

The average proppant tonnage per stage varies with 140 tonnes per stage outperforming 100 tonnes per stage by 31.6% cumulative BOE production per stage at 2 years. However larger tonnes per stage showing a diminishing benefit when looking at the 2 year BOE production totals. The total production versus total proppant used (1000 tonnes to 3500 tonnes per well) is also examined showing an overall total well production benefit. Comparing the total proppant placed versus cumulative BOE is shows a positive. It does appear that the more proppant that is placed the higher the production rate and total long term production.
Complementary Surveillance Microseismic and Flowback Data Analysis: An Approach to Evaluate Complex Fracture Networks
Authors: Xu Yanmin , Ezulike Obinna Daniel , Zolfaghari Ashkan , Dehghanpour Hassan , Virues Claudio
Published: September 2016

This paper presents an integrated workflow which complementarily utilizes flowback data analysis and surveillance microseismic analysis to characterize fracture networks and stimulated reservoir volume (SRV). The workflow helps to 1) differentiate !"effective" and "ineffective" SRV and fracture half-length (ye) respectively, 2) understand how effective fracture volume (Vf) changes during flowback, and 3) explore the effects of key operational parameters on the fracture network created after well stimulation. The workflow comprises four main steps: 1) estimating SRV and fracture parameters from surveillance microseismic interpretation and flowback data analysis; 2) comparative analysis of estimated SRV, ye and Vf values; 3) Calculating volumetric ratios (e.g. flowback load recovery) to evaluate the effectiveness of fracturing and flowback operations; and 4) investigating possible relationships between operational designs and estimated reservoir and fracture parameters.

The application of this workflow on an eight-well pad completed in the Horn River Basin (HRB) shows that the SRV and ye from microseismic interpretation are generally several times larger than those from flowback data analysis. This indicates that over half of the stimulated rock does not contribute to gas production. Besides, a large percentage of the effective fracture network closes during early-time (the first 200 hrs) flowback. The results show that SRV increases as total perforation clusters increases, and this relationship appears to be formation-dependent. Also, the estimated Vf seems to be smaller for wells that are opened later for flowback. This observation might be due to inter-well communication and wellbore storage effects.
Compositional Rate Transient Analysis in Liquid Rich Shale Reservoirs
Authors: Alharthy Najeeb , Teklu Tadesse , Kazemi Hossein , Graves Ramona
Published: September 2016

Conventional rate transient analysis (RTA) is based on the solution of single-phase diffusivity equation, derived from mass balance with an assumption that fluid and rock compressibility are small and constant. The conventional technique also provides accurate practical results for gas and black oil reservoirs in engineering applications because (1) the mass balance is conducted at standard conditions of pressure and temperature, and (2) it is assumed that the gas and oil composition remains the same at standard conditions—thus, the viability of volume balance technique. On the other hand, for reservoirs with highly composition-dependent fluids, the invariance of composition at standard conditions is not accurate. For example, oils produced from liquid-rich shale reservoirs exhibit large variation in produced oil and associated gas composition with production time. In this paper we address these issues and present a compositional model for liquid-rich unconventional reservoirs using an improved compositional volume balance technique. Specifically, we reduce the component flow equations to a single pressure equation using partial molar volumes as weighting factors. This pressure equation is the unique feature of this paper and is used to analyze pressure and rate transient tests (RTA) to determine various flow regimes and reservoir properties in liquid-rich shale reservoirs.

In addition, the model is an excellent tool to forecast long-term production. The diagnostic models we have generated include: (1) a numerical model of flow for a well that has been stimulated by multi-stage hydraulic factures, and (2) an analytical composition-dependent model for the rate transient analysis (RTA) of light oils. The numerical model is a 2-D, three-phase, dual-porosity simulator, which uses compositional volume balance method. The algorithm decouples the hydrocarbon and aqueous phases in the matrix and fracture which reveals the clarity of underlying mass transport concepts and ease of coding.

Because of the explicit nature of the phase saturation calculations, we introduce a molar mass balance correction term to minimize the material balance errors of the computation. Furthermore, we validated our partial molar volume algorithm against published experimental data of Wu and Ehrlich (1973) and with the CMG GEM compositional simulator. Finally, unsteady state permeability measurements of several unconventional shale reservoirs were performed. These measurements show that tighter core with abundant micro and nano fractures exhibit a more stress dependent matrix permeability characteristics.
Downhole Fluid Sampling and Analysis in Challenging Reservoirs Using 3D Radial Probe Case Study from Deepwater Gulf of Mexico
Authors: Mishra V. K. , LeCompte B. , Gendur J. , Chen L. , Garcia G. D. , Dumont H. , Cantwell W. , Agarwal A.
Published: September 2016

In order to reduce reservoir uncertainties, downhole fluid analysis (DFA) and the acquisition of highest quality reservoir fluid samples are of utmost importance, especially in deepwater Gulf of Mexico fields. While focused sampling technique has achieved these objectives in the most efficient and cost-effective manner for a wide range of the reservoirs, there are certain conditions where focused probe or conventional probes don't perform the best. Some of these challenging reservoirs include low permeability or laminated reservoirs, highly unconsolidated formations and reservoirs with highly viscous oil. A newly designed 3D radial probe provides sampling and DFA solutions in such challenging reservoirs. Large inlet flow area of the 3D radial probe facilitates efficient pumping and sampling in low mobility or laminated reservoirs. Conventional probe faces challenge of loss seals in unconsolidated reservoir which is overcome by radial probe due to its large sealing surface area.

A case study from deepwater Gulf of Mexico is discussed in which complex reservoirs are tested for DFA and sampling using a 3D radial probe. Formation density, spectral gamma ray and neutron logs determine formation porosity and presence of shale. Triaxial resistivity identifies laminated zones and a laminated sand analysis is performed to add about 35% hydrocarbon pore thickness when compared to conventional, non-laminated analysis. This data was coupled with the latest generation microresistivity imager which allows accurate identification of geologic features, from very thinly-laminated bedding to faults and fractures.

Fluid sampling and downhole fluid analysis are performed with wireline formation tester tool configured with conventional probes as well as 3D radial probe. Several pumping stations are performed, and 3D Radial probe enables sampling in thin low mobility rocks providing low contamination samples confirmed with the laboratory analysis. Insitu fluid analysis data was used for sample optimization, detailed downhole fluid characterization and reservoir connectivity assessment. The 3D radial probe also allows high quality pressure transient data for better permeability estimation. In addition, a vertical interference test (VIT) is performed with sink and observation probe configurations for vertical permeability and connectivity assessment.

Additional inelastic and capture spectroscopy measurements were taken about two weeks after the well was cased, which validated critical petrophysical measurements. The spectral data was also used to further characterize the formation mineralogy.
The Effect of Brine Concentration on Asphaltene Stability
Authors: Demir A. Birkan , Bilgesu Ilkin H. , Hascakir Berna
Published: September 2016

The stability of asphaltenes is a critical parameter which may affect the flow in porous media significantly. This study investigates the change in the stability of asphaltenes after the interaction of asphaltenes originated from five different reservoirs with reservoir components? namely sand, clay, water, and brine. Asphaltenes are polar like water and brine. Hence, the initial lab-scale sensitivity studies were carried out first with asphaltene-water and asphaltene-brine systems. Then, the impact of porous medium has been investigated on asphaltene stability? asphaltenes are mixed with either sand or sand+clay mixture and then exposed to water or brine. Since, both sand and clay show water-wet behavior, the effect of water-wet rock surface on asphaltene stability has been aimed to understand. Moreover, different brine types and concentrations on asphaltene stability have been tested. A divalent and a monovalent salts were used to prepare brine solutions at 2%, 4%, 6%, and 8% concentrations. All laboratory tests were achieved under optical microscope and the interaction has been examined overtime. Our experimental results suggest that asphaltenes from all five crude oil samples are dispersed in water and they aligned themselves within water due to polar nature of asphaltenes and water. In asphaltene-brine systems, the monovalent salt (NaCl) interacts more with asphaltenes than divalent salt (CaCl2). This is due to higher water uptake capacity of CaCl2 than NaCl. The microscopic images revealed that a water layer is formed around CaCl2 inhibits the direct interaction of asphaltene-CaCl2. This behavior is enhanced within the porous media; salt crystals form bridges between the sand grains, clay and asphaltenes contribute to the formation of those bridges. The impact of brine has been observed more significantly at high concentration of the brine solutions. The asphaltenes-brine interaction also shows variations among different asphaltenes. Thus, all asphaltene samples have been analyzed for their elemental compositions to check if cation exchange is possible between the salts and asphaltenes. These experiments revealed that for the asphaltenes rich in calcium and sodium content, their interaction with brine is greater than for the asphaltenes poor in calcium and sodium content. Moreover, this interaction contributes to the formation of bigger asphaltene clusters which decreases the asphaltene stability and promotes more asphaltene precipitation. This study provides some general trends observed in asphaltene-water and asphaltene-brine systems and explains the reasons why some outliers do not fit the trends by examining the differences in the chemical composition of asphaltenes. Hence, this study enriches our knowledge towards asphaltene behavior in porous media.
A Technical Investigation on the Ongoing Evolution of the Market of Offshore Installation Vessels
Authors: Li Rui , Hansen Kevin , Beltrami Francesco
Published: September 2016

The offshore installation market is presently undergoing great changes: new high-performance offshore installation vessels are being delivered while older ones are decommissioned. This paper investigates the current status of installation vessels worldwide, providing reliable and up-to-date information on the vessels effectively available and reporting about their technical capabilities (selected key features only).

There are only a limited number of technical papers that investigate the status of the offshore installation vessels worldwide and discuss their capabilities providing a comprehensive picture of this evolving market. Focusing on the technical capabilities of the offshore installation vessels will benefit future projects in multiple ways: (a) to ensure that field development planning and the design of subsea equipment take into account what installation vessels can do in a given location, and to create components that are reasonably easier to handle and install, thus reducing installation costs; (b) to enable project teams to be more aware of what the installation vessels market is offering now and in the near future, in order to make a more informed decision on the vessels to be selected for a given project.

The main technical contributions offered by this paper are: (a) the systematic gathering of information available, but dispersed, in the public domain; (b) the elaboration and critical discussion of the technical data collected and the identification of the current installation capabilities; and (c) the use of the numerical results obtained to identify opportunities to reduce installation costs. The information presented in this paper may not be completely new, but the way it is presented and discussed is original and novel.
A Model for Optimizing Energy Investments and Policy under Uncertainty
Authors: Al-Ahmadi Hasan A. , McVay Duane A.
Published: September 2016

An energy producer must determine optimal energy investment strategies in order to maximize the value of its energy portfolio. Determining optimal energy investment strategies is challenging. One of the main challenges is the large uncertainty in many of the parameters involved in the optimization process. Most existing large-scale energy models are deterministic and so have limited capability for assessing uncertainty. Modelers usually use scenario analysis to address model input uncertainty.

In this paper, we describe a coarse probabilistic model developed for optimizing energy investments and policies from an energy producer's perspective. The model uses a top-down approach to probabilistically forecast primary energy demand. Distributions rather than static values are used to model uncertainty in the input variables. The model can be applied to a country-level energy system. It maximizes portfolio expected net present value (ENPV) while ensuring energy sustainability. The model is built in MS Excel® using the @RISK add-in, which is capable of modeling uncertain parameters and performing stochastic simulation optimization.

The model was applied to synthetic data for a typical fossil-fuel-dependent country to determine its optimum energy strategy. For this synthetic case, the model suggests that the subject country should increase its oil production capacity slightly higher than its current level, increase its gas production, and meet most of its future power generation (electricity) demand using alternative energy sources—nuclear, solar, and wind.

A primary contribution of this work is rigorously addressing uncertainty quantification in energy modeling. The model could be applied, with minor modification, by either companies or countries to assist in determining optimal energy investment strategies.