bluuebunny/crossref_metadata_2025 huggingface dataset:
Successful Application of Electric Line Tractor Assisted Logging and Perforating Technology Saved Significant Time and Associated Rig Costs, and Set Two New Regional Records in Latin America: A Case Study
Authors: Nunez-Garcia Walter , Arciniegas Jaime , Alvarez Ricardo , Valencia Brian , Villamizar Carlos , Goksal Mehmet , Parra Elba , Salom Ramon
Published: October 2012

A new well logging/perforating challenge arose from a High Slanted (HS) exploratory well that was drilled in Colombia. The HS exploration well (75 degrees inclination) was drilled in the "Llanos Area" to 18,040 ft MD. Available logging and perforating technologies were reviewed. Tubing Conveyed Perforating (TCP), using a combination of Drill Pipe (DP) / tubing string, and Coiled Tubing (CT) perforating technologies, was considered as part of the evaluation, but the selected method was an electric line well tractor to deploy the logging tool and perforating assembly. Using tractor conveyance saved significant time and associated rig costs over pipe conveyance to perforate a new well, and set two Latin American regional records for tractor-conveyed tools in one well.

Based on site-specific experience, the operator concluded that each well intervention with drill pipe would require 48 hours per trip. In August 2011, after a formal risk analysis and systems integration testing (SIT), the operator mobilized a down-hole robotics-solutions provider and successfully tractored a cement evaluation log to 11,079 ft. A regional record was set for longest tractor-conveyance during the first perforating run of 12,095 ft. A second perforating run of 11,037 ft was successful and set a regional record for longest cumulative tractor-conveyed distance in a single well at 34,211 ft. The cement evaluation and perforating runs were completed in less than 40 hours versus more than 96 hours, which was the estimate with pipe conveyance. The results of operations in the HS Llanos well are presented. Lessons learnt from these operations are part of this study.
Benchmarking, Asset Potential and Digital Energy
Authors: Reid Laurence , Szatny Michael , Johnson William D. , Lochmann Mark
Published: October 2012

Because digital-energy (DE) projects are intended to improve performance, both a normalized baseline describing existing conditions and targets (generally set by management) for future improvement are necessary. Today, only a few assets capture enough data to fully understand the status of operational activities or to quantify optimum reservoir behavior. A benchmark, or baseline, provides a way for companies to identify "where they are" and helps justify DE investments by tracking improvement. To optimize returns, asset potential should be established before appropriate targets are set. DE business impact (the difference between baseline and potential) may then be adequately evaluated.

Deviation from ideal performance may be a result of equipment limitations, facility availability and uptime, administrative or operational bottlenecks, fluid behavior, weather, employee skill set, and numerous other factors. Differences between assets may be attributed to artificial-lift cost variations, local economic conditions, onshore/offshore, lifecycle stage, asset type (shale, waterflood, deep water, coalbed methane, etc.), produced fluid, and many others.

Refining faces equally diverse problems and has taken the necessary steps to address this challenge by applying benchmarking with commercial tools, such as the Solomon Associates Indices, for ranking and comparing different refineries. For E&P, an initial external benchmarking framework based on public data (annual reports, EIA, 10Ks, IHS, etc.) will be discussed so that high-level performance metrics can be evaluated.

By developing a similar approach using proprietary and internal data, companies can begin to understand asset performance in detail and rank assets not only within an organization but also across company boundaries based on operational efficiency and effectiveness. Prioritizing DE projects based on their contribution also becomes possible. As DE projects are deployed, the benchmarks can be refined and updated for greater accuracy.

If the framework is properly designed, a company can see where gains are possible and adapt future programs to concentrate on areas where the most value can be derived, regardless of asset type, which will permit a company to forecast benefits and predict how effective a DE initiative could be.
Downhole Fluid Analysis and Asphaltene Nanoscience Coupled with VIT for Risk Reduction in Black Oil Production
Authors: Mishra Vinay K. , Skinner Carla , MacDonald Dennis , Hammou Nasr-eddine , Lehne Eric , Wu Jiehui , Zuo Julian Y. , Dong Chengli , Mullins Oliver C.
Published: October 2012

It has long been recognized that condensates can exhibit large compositional gradients. It is increasingly recognized that black oil columns can also exhibit substantial gradients. Moreover, significant advances in asphaltene science have provided the framework for modeling these gradients. For effective field development planning, it is important to understand possible variations in the oil column. These developments in petroleum science are being coupled with the new technology of downhole fluid analysis (DFA) to mitigate risk in oil production.

In this case study, DFA measurements revealed a large (10×) gradient of asphaltenes in a 100-m black oil column, with a corresponding large viscosity gradient. This asphaltene gradient was traced to the colloidal description of the asphaltenes, which yielded two conclusions: the asphaltenes are vertically equilibrated, consequently vertical connectivity is indicated, and the asphaltenes are partially destabilized. Vertical interference testing (VIT) was performed at several depths and confirmed the vertical connectivity of the oil column, with four of the five tests showing unambiguous vertical connectivity consistent with the overall connectivity implied by DFA. Geochemical analysis indicates that the instability was due to some late gas and condensate entry into the reservoir. For mitigation of production risk, flow assurance studies were performed and showed that while the asphaltenes are indeed partially destabilized, there is no significant associated problem. Moreover, thin sections of core were analyzed to detect possible bitumen. A very small quantity of bitumen was found, again confirming the asphaltene analysis; however, geochemical studies and flow assurance studies confirmed that this small amount of bitumen is not expected to create any reservoir issues.

Using new science and new technology to identify and minimize risk in oil production in combination with pressure transients addressed reservoir connectivity and provided a robust, positive assessment.
New Wireline Formation Tester Development Makes Sampling and Pressure Testing Possible in Extra-Heavy Oils in Mexico
Authors: Flores de Dios Tania , Aguilar Maria Guadalupe , Herrera Rafael Perez , Garcia German , Peyret Emilie , Ramirez Edher , Arias Abraham , Corre Pierre-Yves , Slapal Miroslav , Ayan Cosan
Published: October 2012

Accurate fluid description in the Tertiary sediments of Mexico is important for PEMEX operating assets because large variations in viscosity over very short intervals have a major impact on well productivity. Well placement and selection of the completion strategy in this kind of reservoirs strongly depend on the characterization of the fluid distribution. This is because the efficiency of steam injection and the artificial lift system can be severely impaired if a preferential path, following high mobility section (k/μ) exists over the producing intervals. Such is the case for the Samaria-Neogeno project, which has fluids with viscosity values up to 40,000 centipoise (cP) at standard conditions.

Wireline openhole formation testing and sampling in this environment is not short of challenges and hence is rarely done in the field. The poorly consolidated formations and the high viscosity of the fluids mean that the pressure differential generated during sampling operations almost invariably causes failure of the wellbore wall, sanding out the tool or breaking the seal needed. Other experiences in the world with straddle packers in similar formations have been mostly unsuccessful because the formation collapses in the unsupported interval between the packers once the pressure differential is applied.

This paper summarizes the recent successful application of the newest wireline formation tester (WFT) module for testing and sampling extra-heavy oils in the Tertiary sandstone formations of South Mexico. This is the world's first application of such technology in unconsolidated sandstones. The new WFT module provides mechanical support to the formation while allowing the application of the needed pressure differentials to mobilize formation fluid into the tool's flowline and sample containers. The case presented shows how ~8° API fluid samples with viscosities in the order of few thousands centipoises at downhole conditions were acquired using this new device. Other applications reviewed are pressure profiling and pressure transient tests for permeability evaluation.
Lessons Learned from an ESP Development of a Naturally Fractured Carbonate Reservoir Offshore Gabon
Authors: Camilleri L. , Hamza L. , Yucel O. , Rodet V. , Breton B.
Published: October 2012

The Ompoyi and Orindi fields are located 5 km offshore Gabon in a water depth of 20 m. The high oil density (23° API) and high produced water salinity (150 kppm) combined with reservoir pressure depletion meant that primary production of the Ozouri reservoir required artificial lift. Initially, progressing cavity pumps (PCPs) were selected, however, following failures of the elastomers, electric submersible pumps (ESPs) were deployed to produce at higher rates with high gas/oil ratios (GORs). The production instability associated with the dual-porosity reservoir behaviour and high free-gas content in both the inflow and outflow of the wells presented the main challenge to ESP design and operation. Additionally, most of the wells were remote from the main production facility and were produced via multiphase subsea flowlines, which made well testing difficult due to the phase segregation in the flowlines.

To achieve economically viable production utilizing ESPs, innovative use was made of a range of existing technology. Operationally, however, real-time monitoring was essential to setting wellhead pressures and pump speed to maximize drawdowns. Key technology elements were monopods to minimize the offshore structure cost, fit-for-purpose subsea power cable and helicoaxial downhole pumps for high gas void fraction operation. Key lessons were learned following the trial of several completion architectures to find the optimal combination of gas venting, reservoir access, and a dual barrier mechanism.

The first well was put on production in 2002. Since then a further 10 wells have been drilled to reach a total liquid production of 8,000 B/D with a 60% water cut. Production has been economical and thus confirmed ESPs as being the right solution for this reservoir. The lessons learned prove that the application of ESPs is not limited to traditional waterfloods and that it is feasible to produce challenging reservoirs with ESPs.
A Decade Monitoring Shale Gas Plays Using Microseismicity: Advances in the Understanding of Hydraulic Fracturing
Authors: Wuestefeld Andreas , Urbancic Thedor I. , Baig Adam , Prince Marc
Published: October 2012

Over the past decade, microsesimic monitoring has become the approach most often used to gain an in-situ understanding of the rock's response during hydraulic fracture stimulations. From initial monitoring performed in the Barnett Shale to monitoring currently being carried out for example in the Horn River and Marcellus formations, we review the evolution of microseismic monitoring from data collection (single versus multi-well array configurations, utilization of long lateral stimulation wells), to data analysis and the incorporation of microseismic parameters to constrain and validate reservoir models. Furthermore, we discuss the variations in microseismic activity for different stimulation programs (e.g. zipper-fracs) and stimulation fluids.

Generally, we have observed that overall fracture height, width and length, orientation, and growth vary from formation to formation and within each formation, thereby highlighting the ongoing necessity for microseismic monitoring. Additionally, through the use of advanced microseismic analysis techniques, such as Seismic Moment Tensor Inversion (SMTI), details on failure mechanisms have been used to assess stimulation effectiveness and define complex Discrete Fracture Networks (DFN). This information provides estimates of Enhanced Fluid Flow (EFF), which assist in calibrating and validating reservoir models. Utilizing spatial and temporal distributions in DFN and EFF, along with estimates of fracture interconnectivity and complexity, the role of pre-existing fractures and fault structures in the rock matrix can be established and used to provide more realistic estimates of stimulation parameters such as Stimulated Reservoir Volume (SRV).
Criticality Testing of Drilling Fluid Solids Control Equipment
Authors: Aase Bodil , Omland Tor Henry , Jensen Ellen Katrine , Vestbakke Anne Turid , Knudsen Bjarte Sivert , Haldorsen Frode , Nysted Arvid , Storslett Eystein Ove , Steinnes Iren , Eliassen Einar Knut , Enger Jørund , Lie Øyvind , Peikli Vegard
Published: October 2012

Correct selection and use of solids control equipment is essential to maintain drilling fluid at its desired properties. It has also shown to be essential to avoid generation of unnecessary waste streams during drilling.

Since the early 1930s shale shakers has been the dominant device for primary solids removal. Additional equipment like desilters, desanders and centrifuges were often used in the past to maintain proper solids control, but recent years have demonstrated that although dependent on correct operational procedures, several types of shale shakers have sufficient performance to be able to act as the sole solids control device without the use of desanders and desilters.

Despite often being the only measure for solids removal, selection of shale shakers, screen and establishment of operational procedures are often based on biased information (Dahl, B. et al, 2006). In addition it has been recognized that methods and criteria for verification of shale shakers has not been sufficiently qualified and standardized. To address this, a multidisciplinary verification test of various solids control concepts has been conducted. The objective of the test has been to verify equipment performance in a standardized onshore test facility related to:

Oil mist and vapour emission. Ventilation (to obtain satisfactory working environment). Flow handling capacity using various drilling fluids. Leakage rate, i.e. the volume of fluid bypassing the filtration screen Lost circulation material feature Noise and vibration level. Maintenance and equipment robustness. Feature for running lost circulation material reclamation.

The tests were all planned and run in close co-operation with the equipment suppliers to ensure test objective alignment. Several findings were made throughout the test period providing vital information for design improvements and increasing the industry's competence with respect to solids control.
Impact of Completion Design on Fracture Complexity in Horizontal Wells
Authors: Manchanda Ripudaman , Sharma Mukul M.
Published: October 2012

A proppant-filled fracture induces mechanical stresses in the surrounding rock causing a reduction in the stress contrast and stress re-orientation around the open fracture. A three-dimensional geo-mechanical model is used to simulate the stress reorientation due to open fractures and generate the stress contrast contour maps. The reduction in stress contrast can lead to increased fracture complexity. This paper describes how fracture complexity can be increased by varying the completion design.

In this paper, we identify the impact of operator-controllable variables in a completion design on fracture complexity. This can lead to more effective completion designs that improve well productivity, reservoir drainage and ultimately EUR.

The possibility of greater fracture complexity and reduced effective fracture spacing and hence higher drainage area is demonstrated for an alternate fracturing sequence in comparison to the conventional fracturing sequence. The Young's modulus value of the shale and the in-situ horizontal stress contrast are shown to be significant factors controlling the extent of fracture complexity generated in a given reservoir. In addition, the effect of proppant mass injected per stage and the fluid rheology is also shown to significantly impact fracture complexity. We provide optimum ranges of fracture spacing, proppant volume and fluid rheologythe various formations analyzed. The use of these guidelines should result in more fracture complexity than would otherwise be observed.

The results presented in the paper allow an operator to design completions and fracture treatments (rates, fluids, fracture spacing and sequencing) to maximize reservoir drainage and increase EURs. This will lead to more effective completion designs.
A Comparison of Core and Well Log Data to Evaluate Porosity, TOC, and Hydrocarbon Volume in the Eagle Ford Shale
Authors: Quirein John , Murphy Eric , Praznik Greg , Witkowsky Jim , Shannon Scott , Buller Dan
Published: October 2012

The Eagle Ford Shale hydrocarbon-fluid properties depend on the source rock maturity and, within the formation, occur in varying degrees of gas, gas condensate, and oil. Using conventional logs and pyrolysis data, several log-core regressions, such as delta log R, density, and uranium, can be derived to predict total organic carbon (TOC). The TOC can be used in conjunction with geochemical elemental measurements for a more accurate assessment of the formation kerogen and mineralogy, as well as hydrocarbon volumes. Nuclear magnetic resonance (NMR) porosity measures an apparent total porosity in the organic shale plays, measuring only the fluids present and excludes the kerogen. The complex refractive index method (CRIM) in conjunction with the mineralogy log data can be used to compute accurate dielectric porosities, which exclude both kerogen and hydrocarbon. Integrating the core TOC, predicted TOC, mineral analysis, NMR, and dielectric information, a final verification of the kerogen volume, hydrocarbon content, and mineral analysis can be assessed.

This paper will describe the integration of conventional logs, a geochemical log, an NMR log, and dielectric to predict TOC, kerogen volume, and hydrocarbon volume, as well as, total porosity and mineralogy. The data is compared to the actual core data from three Eagle Ford wells, and it will be shown how the proposed approach will eliminate some coring operations. Finally, it will be shown how these interpretation results can be rolled up to make decisions on where to drill the lateral.
Experimental Investigation of Wellhead Twin-Screw Pump for Gas Well Deliquification
Authors: Morrison Gerald L. , Kroupa Ryan , Patil Abhay , Xu Jun , Scott Stuart , Olsen Sven
Published: October 2012

Onshore gas developments are often characterized by drilling, fracturing and production of wells before low-pressure gas gathering systems are in place. As well production declines, liquid loading issues begin to appear. Gas well deliquification (GWD) can be accomplished using compression or in-well artificial lift methods, or both. Wellhead wet-gas compression is desirable in that it does not require well intervention to provide GWD and is especially useful to maintain well production in the interim period before field-wide compression is available. Also, even when field-wide compression is available local wellhead compression is desirable at various locations in a field as high-rate wells are added or for wells located at peripheral locations. The use of a twin-screw pump to provide boost for high Gas Volume Fraction (GVF) multiphase flow was experimentally investigated. Tests were conducted with pressure rises ranging up to 250 psi for GVF's above 90%. Water and air were used as the working fluid. The pumping system is a commercially available 230 gpm twin-screw pump (60 hp) with a design speed of 3600 rpm used in conjunction with a knock out tank used to re-circulate liquid from the pump exit to provide seal flush. The electrical power required to operate the pump, liquid and gas inlet flow rates, pressure rise, and inlet and exit temperatures were recorded. From these data, the volumetric efficiency, pump effectiveness, and mechanical efficiency were calculated. Since there is a fixed clearance between the rotating screws and the pump housing, there is a leakage from the high to low pressure regions of the pump which will reduce the pump's volumetric efficiency. It was found that the volumetric efficiency decreased significantly with decreasing pump speed and decreasing GVF. At full speed the volumetric efficiency was between 70 and 88% at DP=50 psi. Increasing DP to 250 psi decreased these values to 55 and 81% respectively. The mechanical efficiency was relatively constant over the pressure rise range varying from a high of 48% at the lowest inlet pressure and 100% GVF to a low of 14% 14% for both inlet pressures at 100% GVF. Overall, the testing demonstrated the ability of a surface twin-screw pump to provide wet-gas compression and to tolerate 100% gas input, which may results from slugging or periodic flow, for relatively large periods of time.
Extended Finite Element Modeling of Multi-scale Flow in Fractured Shale Gas Reservoirs
Authors: Sheng M. , Li G. , Shah S. N. , Jin X.
Published: October 2012

An economic production scheme for gas shale demands a better understanding of gas flow behavior and a proper reservoir simulator. The complex fracture network and multi-scale flow channel intensify the complexity of gas flow behavior. This paper integrated an improved shale-gas transport model with the extended finite element method (XFEM) to characterize the main flow mechanisms and discrete fracture network. The gas shale was viewed as the dual permeability porous media with discrete fractures. The discrete fractures are not required to be meshed, which can be placed anywhere with given location, length, and orientation. Rock deformation is implicitly coupled with gas flow to reflect stress sensitivity of gas shale. Furthermore, the displacement and matrix pore pressure across fractures are treated as discontinuous by using enrichment approximation functions. The computer coding of proposed model was developed. Terzaghi's problem for dual permeability media was considered to validate the code. The results show that pressure field is disturbed by the discrete fractures obviously, which is compared with regular pressure field obtained from the continuous fracture model. Therefore, it is important to account for discrete fractures for the fractured porous media. One case study of shale gas reservoir was presented to improve the model application. Two patterns of fracture networks were simulated in the rectangular reservoir. It is evident that the orthogonal fracture network is an ideal pattern contrast to the oblique fractures, since the former makes the pore pressure field depleted symmetrically. Furthermore, the stimulated area is the main factor to control the pressure depletion. The results confirm that the presented model and code is capable and flexible to simulate shale gas reservoir with discrete fracture network. This work provides an alternative workflow for parameter designs of hydraulic fracture and production scheme.
Optimized Cased and Perforated Completion Designs Through the Use of API RP-19B Laboratory Testing to Maximize Well Productivity
Authors: Procyk Alexander D. , Burton Robert C. , Atwood David C. , Grove Brenden M.
Published: October 2012

A detailed perforating study was conducted for a high pressure and high temperature (HPHT) reservoir which provided challenging conditions for conventional perforating. To maximize productivity, a series of API RP-19B Section 2 and Section 4 experiments was conducted to optimize perforation conditions. These results were integrated with mud testing and operational considerations to create an overall completion design for the field.

Section 4 tests were performed at static overbalance, static underbalance and dynamic underbalance conditions scaled to field conditions using either mud or base oil as the completion fluid. The core flow efficiency and perforation geometry were evaluated to determine the optimum perforation method to achieve the target skin. The Section 4 apparatus could not achieve absolute field pressure and temperature conditions, therefore to ensure the required perforation geometry could be achieved downhole, Section 2 tests were conducted at the HPHT field conditions of reservoir overburden stress (13,000 psi), reservoir pressure (>11,000 psi) and temperature (>300 F).

The results showed that dynamic underbalance removed significant portions of the perforation crushed zone and resulted in high productivity flow even when perforating in mud. Static underbalance was significantly less effective in removing crushed zone damage and overbalanced perforating in mud yielded poor results. Perforation geometry was radically altered upon going from relatively low stress conditions to full HPHT reservoir conditions when the cores were saturated in a light mineral oil. This change in perforation geometry was not observed when the cores were saturated in water, indicating that the fluid compressibility may have a significant impact on perforation geometry under high stress conditions. These results point to the value of conducting Section 2 and Section 4 experiments early in a project's timeline so that the best completion designs can be pursued and ultimately used in the field to maximize well productivity.
A Petrophysical Model to Estimate Relative and Effective Permeabilities in Hydrocarbon Systems and to Predict Ratios of Water to Hydrocarbon Productivity
Authors: Holmes Michael , Holmes Antony , Holmes Dominic
Published: October 2012

Permeability estimates from petrophysical interpretations rely mostly on relations between porosity and irreducible water saturation, for example using the approach developed by Timur (1968). If core data are available for calibration, it is common that the transform used can be quite reliable. However, relative permeability estimates require quantification of water saturation greater than irreducible saturation.

In a previous publication by the authors (Holmes, et al, 2009), methodology was presented to distinguish rocks at irreducible saturation from those that contain mobile water. The technique involves a modified interpretation of porosity/saturation cross plots to identify levels at irreducible water saturation using a Buckles (1965) relationship. Once this data trend has been identified, water saturation at any given data point can be compared with theoretical irreducible saturation. Values of water saturation above irreducible water saturation indicate the presence of mobile water.

Using a representative relative permeability curve, or a reservoir-specific relative permeability curve, relations can be established between water saturations above irreducible and the accompanying relative permeability, both to hydrocarbons and water. Once this is available, effective permeabilities to each phase can be calculated level-by-level. The procedure involves comparing differences between water saturation and irreducible water saturation with measured relative permeabilities to both wetting and non-wetting phases, expressed as exponential equations. Effective permeabilities are then available as the product of relative permeability and log-estimated permeability. By factoring in mobility ratios of hydrocarbons and water, it is then possible to estimate profiles of water cuts in oil/water systems, or barrels of water per million cubic feet of gas (Bbl/MMCFG) in gas/water systems.

Examples are presented for both oil/water and gas/water systems, showing good correlation with fluid production from well tests.
Using Equipment Simulators for Effective Training, Increasing Competence in Well Services Operations
Authors: Celano Anthony , Kersey George , LeBlanc Aladain , Fiffick William
Published: October 2012

Learning on-the-job has been considered as among the most practical and effective methods to train Engineers and Technical Operations personnel. Lessons learned and best practices can be modeled and taught to less experienced employees. The new learners are provided with the benefit of hands-on operations under supervised conditions where proper behaviors could be modeled and mistakes corrected. But that model of training is changing. Technological advances have resulted in enhanced automation, control and feedback but with greater operational complexities. The modern equipment provides great gains in efficiency and control, but may require a higher degree of skill on the part of the operators and engineers. Unfortunately, as a result of the "Great Crew Changei", fewer competent mentors and trainers remain in the field to pass along those lessons learned and best practices. To compound the training challenges, it is often impractical (or impossible) to allow those learners to "practice" without compromising either operational or job safety concerns.

Fortunately, by leveraging technologies and with some investment in equipment, the "field" can now be brought to classroom. By working with competent instructors, in a controlled environment, many of the benefits of hands-on field experience can be achieved.

This is a case study of how a major oil field services company is employing modern simulation technology to meet (or exceed) technical training and competency requirements. Details about the rationale and the concept of simulation training, learning theory, logistical concerns, development of simulators and results are discussed.
A Case for Oil-Based Fracturing Fluids in Canadian Montney Unconventional Gas Development
Authors: Hlidek Barry T , Meyer Russell K , Yule Keri , Wittenberg Joerg
Published: October 2012

This paper presents a fracturing case study from the Montney gas play in the Western Canadian Sedimentary Basin. There is a long history of debate regarding the use of oil-based fracturing fluids; the debate is centered on the argument that the benefits of oil-base fracturing fluids do not justify the increased cost of supplying and using oil as a base fluid. The economics are substantially different not only because of the cost of fracturing oil itself, but also because of the associated environmental, safety, and disposal costs. From an environmental sustainability point of view, 100% of the frac oil is recovered; the oil is cleaned and recycled at least twice before being sold into the market. In contrast, water used in fracturing—typically surface water—is completely removed from the hydrological cycle: Flowback water is treated as effluent and disposed.

The case study analyzed in this paper demonstrates the benefits of using oil-based fluids over water-based fluids in the Karr region of the Montney play. The Montney in this area is best described as an undersaturated, fine-grained, siliciclastic reservoir. All wells are horizontal and completed using multistage isolation techniques. The characteristics and petrology of the reservoir are examined, along with fracture geometry simulations. Laboratory data is presented to support the use of oil-based systems. Treatment summaries and flowback data are presented. Finally, long-term production data from the field provides a direct comparison between oil- and water-based fracturing fluid treatments, allowing economic analysis of the two options. Beyond improved production profiles, some common misconceptions regarding the environmental and economic impact of oil-based fluids are addressed.
Analysis of Unsteady Responses of Natural Gas Reservoirs via a Universal Natural Gas Type-Curve Formulation
Authors: Ayala H. , Luis F. , Ye Peng
Published: October 2012

Gas decline curve analysis has traditionally relied on the use of liquid (oil) type curves along with the concepts of pseudopressure and pseudo-time and/or empirical curve fitting of rate-time production data using Fetkovich type curves for gas well performance and reserve estimations. In this work, we show that a single-line, universal type curve can instead be derived for the analysis of unsteady state of natural gas wells under boundary dominated flow (BDF). The proposed decline equation is presented in its analytical, closed functional form and is shown to model production from any gas well producing at constant bottomhole pressure under BDF. On the basis of this decline model, a universal type-curve is formulated for type curve matching of natural gas well producing under BDF, for any constant drawdown condition, and regardless of intrinsic reservoir and fluid properties. New-generation analytical procedures for gas well performance analysis are presented, which does not necessitate the calculation of pseudo-pressure or pseudo-time. Explicit OGIP predictions are thus enabled from the proposed universal type curve matching. The importance of conducting unambiguous reserve estimations based on rate-time data and reliably predicting future well performance cannot be overstated. The proposed single-line type curve is demonstrated to do so by successfully matching rate-time production BDF data and reliably estimating fluid in place for a number of numerical simulations and field cases. It is finally shown that the proposed formulation can be alternatively implemented in terms of straight-line analysis of 1/qgscb versus time data plots.
A Procedure for Integrating Geologic Concepts into History Matching
Authors: Lun Lisa , Dunn Paul , Stern Dave , Oyerinde Adedayo , Chorneyko Dave , Stewart Jonathan , Fowler Kenneth , Nollet Sofie
Published: October 2012

This paper describes a history match study carried out on a deep water reservoir with roughly a year of production history, consisting of flowing bottom hole pressure (FBHP) and oil rate measurements. This study demonstrates a procedure that can be used to integrate geologic concepts with the history match process to find a range of geologically realistic reservoir descriptions that are all consistent with production history to date for evaluating uncertainty in predictions. The process has three steps: 1) determine, based on geologic and engineering data, what model inputs will be tested in history matching; 2) develop an experimental design(s) and use it(them) to test the impact of those inputs on reservoir performance; and 3) select models for further history match work or prediction of future performance. Two geologic features were selected for study:

The degree to which the boundaries between stratigraphic elements seal. Analysis of seismic data identified three levels of stratigraphic elements - channel complex sets, channel complexes, and channel complex remnants. Degree of sealing represents the presence of sub-seismic shale drapes at each level. The degree to which faults are sealed, which depends on the net-to-gross ratio and the throw of each fault. The degree to which a given fault seals is uncertain because it depends on the detailed spatial arrangement of sand and shale in the fault zone, which is not measured directly.

The impact of shale drapes was evaluated first. Four shale drape scenarios were chosen to represent a range of behavior including the best match, and seven fault seal scenarios were used to further evaluate the impact of fault seal. Our analysis in this case revealed that the pressure depends on both fault seal and shale drape continuity, with the best matches observed when either faults or stratigraphic boundaries are partially closed and the other geologic feature is open. This allowed selection of seven reservoir descriptions for use in predictions.
Rock Classification in Carbonate Reservoirs Based on Static and Dynamic Petrophysical Properties Estimated from Conventional Well Logs
Authors: Xu Chicheng , Heidari Zoya , Torres-Verdín Carlos
Published: October 2012

Rock typing in carbonate reservoirs is challenging due to high spatial heterogeneity and complex pore structure. In extreme cases, conventional rock typing methods such as Leverett's J-function, Winland's R35, and flow zone indicator are inadequate to capture the heterogeneity and complexity of carbonate petrofacies. Furthermore, these methods are based on core measurements, hence are not applicable to uncored reservoir zones.

This paper introduces a new method for petrophysical rock classification in carbonate reservoirs that honors multiple well logs and emphasizes the signature of mud-filtrate invasion. The method classifies rocks based on both static and dynamic petrophysical properties. An inversion-based algorithm is implemented to simultaneously estimate mineralogy, porosity, and water saturation from well logs. We numerically simulate the process of mud-filtrate invasion in each rock type and quantify the corresponding effects on nuclear and resistivity measurements to derive invasion-induced well-log attributes, which are subsequently integrated into the rock classification. Under favorable conditions, the interpretation method advanced in this paper can distinguish bimodal from uni-modal behavior in saturation-dependent capillary pressure otherwise only possible with special core analysis.

We successfully apply the new method to a mixed clastic-carbonate sequence in the Hugoton gas field, Kansas. Rock types derived with the new method are in good agreement with lithofacies described from core samples. The distribution of permeability and saturation estimated from well-log-derived rock types agrees with routine core measurements, with the corresponding uncertainty significantly reduced when compared to results obtained with conventional porosity-permeability correlations.
Extending the Range of Gas Lift to Long Perforations
Authors: Polasek Darryl , Frost Chandler
Published: October 2012

Problem being addressed: Operators face many challenges when producing deep vertical wells and long horizontal or deviated well bores. Traditional artificial lift methods can prove inefficient or ineffective when applied to this new breed of wells.

Challenges: In wells with long perforated intervals, insufficient velocities below the packer can cause liquid loading. Many traditional artificial lift methods are limited in their ability to address liquid loading issues in these types of wells.

Solution: If gas can be injected below the packer and deep into the perforated zones, gas lift can be an effective means of deliquification. Advances in gas lift system design now provide several options for effectively recovering liquids from completion intervals below the packer. We will discuss a few of these systems, including Annular Bypass Assembly (ABA), Dip Tube, Enhanced Annular Velocity (EAV), Marathon AVE, and Dead String. Each employs unique techniques that allow for gas injection deep into the perforated zone by passing the lift gas through or around the packer. Using the basic principles of gas lift, the injected gas aerates the liquid in the perforated zone, decreasing the hydrostatic density and flowing gradient and improving inflow from the formation. By also increasing velocity in the production string, these gas lift systems allow operators to more efficiently recover fluids and minimize or prevent liquid loading.

Results: Below-packer gas lift systems are being used successfully to economically produce wells in unconventional plays. We will review the design and mechanics of each of the above-mentioned systems, share our experiences working with operators and discuss the selection criteria in choosing a system.
Hands-on Teaching for Petroleum Engineers in the 21st Century: a Balance between High-Tech and Simple Demonstrators
Authors: Teodoriu Catalin
Published: October 2012

Teaching petroleum engineers requires a balance between mathematics and engineering or in other words between abstract concepts and the real world. Several scientists have shown that visual aids help students to learn better and to retain the knowledge. Furthermore, students pay more attention to gadgets and high-tech systems because they were born in this contemporary era. Teaching using multimedia has become standard practice, but students tend to lose the link to reality.

Several years ago, a new concept of teaching undergraduate and graduate students was introduced at Clausthal University of Technology, based on the implementation of hands-on teaching systems that not only expose the students to physical models, but also require them to build such models or to generate experiments using existing models.

The results from the 3-year experience at Clausthal University of Technology show an improved learning capability of the students, in combination with better knowledge transfer efficiency between teacher and students. This paper presents the results of students’ competitions held at Clausthal University of Technology as part of their studies. For example, a comparison is made between the outcomes of groups that chose to work on high-tech multimedia tasks versus those students who built more conventional tools (e.g. a surge and swab simulator, a hoisting system model and a laminar flow rig).

Finally, the students’ feedback concerning the hands-on teaching concept will be summarized in this paper.
New Generation Magnetic Resonance While Drilling
Authors: Heaton Nicholas , Jain Vikas , Boling Brian , Oliver David , Degrange Jean-Marie , Ferraris Paolo , Hupp Douglas , Prabawa Hendrayadi , Torres Ribeiro Mauro , Vervest Edwin , Stockden Ian
Published: October 2012

In this paper, a new series of Logging-while-drilling (LWD) nuclear magnetic resonance (NMR) tools is introduced. The tools incorporate a magnet arrangement which provides a low field gradient minimizing adverse lateral motion effects. T2 distributions are measured while drilling or sliding in a range

of hole sizes, including large holes previously inaccessible to LWD NMR measurements. Benefits and trade-offs of key tool design features are presented. Emphasis is placed on measurement quality, operational simplicity and log quality control in real time and memory mode through example logs from operator wells. Real-time T2 distributions provided by the new generation LWD NMR tool enable a full range of NMR answers, including lithology-independent total porosity, bound fluid volume and permeability. Real-time log quality controls monitor tool noise, antenna sensitivity, tuning quality and lateral motion. Acquisition sequences are optimized for porosity precision and accuracy in different environments. Drilling data have been acquired in several operator wells and a test well covering diverse ranges of formations and logging conditions. Environmental factors affecting porosity precision and T2 quality are discussed with reference to log quality indicators and comparison with wireline NMR logs is made where available. In general, the LWD tools deliver NMR answers comparable to the analogous wireline logs in terms of precision, accuracy and vertical resolution. With increased industry focus on LWD services and heightened sensitivity to downhole chemical sources, the need for reliable LWD NMR measurements continues to grow. In addition to a sourceless porosity measurement, NMR provides unique quantitative information on the disposition of producible fluids, which is not available from other logs. Real-time producibility information can be used to optimize formation pressure measurements and sampling as well as for timely completions and well placement decisions. The new generation LWD NMR tools introduced here addresses this need.
A Superior, High-performance Enzyme for Breaking Borate Cross-linked Fracturing Fluids under Extreme Well Conditions
Authors: Zhang Bin , Huston Adrienne , Whipple Lawrence , Urbina Hugo , Barrett Ken , Wall Mark , Hutchins Rick , Mirakyan Andrey
Published: October 2012

Enzyme breakers have been previously used for hydrolyzing guar gels at temperatures below 150°F. There is an industry-wide demand for enzyme breakers that can function under higher temperature (200-250°F) and extreme pH (≥10.5) conditions. To fill this gap, Verenium Corporation has developed an exceptionally thermo-stable cellulase enzyme, referred to hereafter as mannanase, that was discovered from a hydrothermal vent sample. This mannanase exhibits well differentiated performance under extreme downhole conditions encountered in gas shales and deeper oil/gas wells.

This superior mannanase can effectively break linear and borate cross-linked guar under broad ranges of temperature (80°F up to at least 225°F as seen by rheology and up to 275°F using residual activity analysis ) and pH (3.0 up to 10.5). The results of rheological tests show that only a small dose is required (100 ppm or less) to achieve the complete break. The enzymatic reaction can be triggered by the changes of temperature and pH during fracturing operations. This mannanase also exhibits a dose response that allows the operator to generate a desirable viscosity/time profile by adjusting enzyme dosage. Even in the presence of fluid additives, such as buffers, salts, stabilizers and cross-linkers, this mannanase is active for effective viscosity reduction.

This mannanase breaker belongs to the glucanase family. It reduces gel viscosity by specifically targeting β -1,4 glycosidic bonds between the mannose units in guar. The carbohydrate profiling tests demonstrate that this enzyme effectively and efficiently breaks the long-guar polymers into small, soluble fragments that will eliminate gel re-healing. The conductivity tests demonstrate extensive cleaving of guar and removal of polymer residues that cause formation damage and reduce fracture conductivity.
One Year of Just-In-Time Perforating as Multi-Stage Fracturing Technique for Horizontal Wells
Authors: Angeles Renzo , Tolman Randy , Gupta Jugal , Benish Tim , Ross Kirk , Cole Stephen , Garner Christopher , Lopez Thomas
Published: October 2012

In order to reduce stimulation costs, most conventional methods incorporate hydraulic fracturing of multiple perf clusters over multiple stages to treat large segments of shale rock in horizontally completed laterals. Under ideal situations, this technique would create equally-stimulated fractures at each perf cluster. However, in practice, such treatments can create overstimulation in some perf clusters and under-stimulation in others with unknown stimulated lengths and volumes. As operators move towards increased number of stages, increasingly larger number of plugs cause additional wireline trips and associated plug drilling time, which increases the total cost and mechanical risk of the completion. In some fields, operators use combinations of ball actuated sleeves and plug-and-perf methods due to technical limitations in drilling out of all the frac plugs. In response to these practical issues, ExxonMobil has implemented its proprietary Just-In-Time Perforating (JITP) technique in multiple horizontal wells over the last year. Prior to this deployment effort, JITP had been extensively used in vertical and S-shaped wells in the Piceance basin, Colorado.

This paper discusses the learnings obtained after one year of multi-stage fracturing using horizontal JITP in unconventional plays. JITP creates multiple single-zone fracture stimulations on a single wireline run using ball-sealer diversion and perforating guns that remain downhole during fracturing. With the unique granularity of single-zone fracturing, much has been learned about the shale and treatment design. Better placement control can be useful in avoiding fracturing into offset wellbores. Field applications have confirmed the use of less horsepower, fewer frac plugs, improved fracture placement control, and added flexibility in water management. This paper also reviews technical considerations for other completion designs and fluid systems as well as opportunities for enhanced operations based on recent field learnings.