bluuebunny/crossref_metadata_2025 huggingface dataset:
Underreamer with Real-time Communications and Optimal Bit Design Achieves Successful Lateral Well Placement - A Case Study
Authors: Chiniwala Barzin , Radford Steven , Bacon Robert , Fuller Tom , Badru Ola
Published: October 2014

As long as underreamers have existed in the oil field, operators have wanted a clearer understanding of how these tools are operating in real time. A new integrated underreamer that provides real-time communication via the same mud pulse telemetry system as the familiar MWD/LWD/RSS (Measurement While Drilling/Logging While Drilling/Rotary Steerable System) tools and allows the placement of the underreamer closer to the bit (to aid vibration management and minimize rat hole length), has been used. This advanced underreamer system reveals the current condition of the tool and the position of the blades (implied hole caliper) to the operator, additionally, it uses internal hydraulic oil pumped-pressure activation (and deactivation) of the blades. This integrated underreamer was used to simultaneously drill and underream an 8½-in. × 9⅞-in. pilot hole section interval and then side-track to drill an 8½-in. × 9⅞-in. mainbore lateral section to the top reservoir horizon.

A case study in the UK North Sea Harding field is included as part of this paper describing the critical challenges of simultaneously drilling and underreaming a development well, including the equivalent circulating density (ECD) management within narrow pressure margins. Underreaming an 8½-in. × 9⅞-in. wellbore all the way to TD was viewed as the most acceptable method to manage ECD and be able to get the production liner to bottom. Other ECD control methods used on this well, and detailed in this paper, include a combination of adjustments of rate of penetration (ROP) and rotations per minute (RPM), drilling fluid rheology management and pumping of sweeps at different stages of drilling to aid hole cleaning. The PDC (polycrystalline diamond compact) bit design was matched to that of the reamer with a proprietary technology to optimize the drilling assembly and minimize stick-slip or coupled lateral vibrations.

The reaming system was used to drill and underream 6,645 ft. in two runs totalling 288 hours on-bottom drilling, with minimal vibrations. The well was drilled with an inclined trajectory of up to 90° with as much as 5°/100 ft. dog leg severity. The reamer appeared to provide an in-gauge borehole allowing for successful running, rotation and cementing of approximately 4,300 ft. of 7-5/8″ liner without any issues, demonstrating superior borehole quality.

This paper outlines the problems anticipated in this challenging well, the thinking behind the unusual reamer selection, the method for proper synchronization with the pilot bit, and the keys to overall success.
Correlations to Estimate Key Gas Condensate Properties through Field Measurement of Gas Condensate Ratio
Authors: Paredes J. E. , Perez R. , Perera L. M. , Larez C. J.
Published: October 2014

When a hydrocarbon reservoir is discovered it is important to know the type of fluids that are present as well as their main physicochemical characteristics, this is normally obtained by performing a PVT analysis to a representative fluid sample of the reservoir. In most cases, having a PVT analysis can take several months, which limits the number and type of reservoir studies that can be carried out during this period.

The only parameter that can be measured almost immediately after a well is completed, are conventional production measurements. In some cases this production measurement can be obtained before completing the well by using special testing or measuring equipment such as a DST (Drill Stem Test, acronym in English).

It is important to obtain preliminary values of properties such as: molar percentage of heptane and heavier components (% mole of C7+), molecular weight of the original fluid (MW), maximum retrograde condensation (MRC) and dew point pressure (Pd). Most of these properties are very important for exploitation of gas condensate reservoir and their early early availability will allow engineers to carry out reservoir studies that will ensure an efficient exploitation and maximize the final recovery of the liquids present in the reservoir.

This work proposes a series of correlations, obtained from analyses of several PVT studies collected mainly from reservoirs of Mexico and other regions of Latin America. These correlations can be used to estimate reservoir properties for gas condensate such as: % mole of C7+, MW, MRC, Pd and Z-factor at Pd.

The only parameter needed to use these correlations is the value of the gas condensate ratio (GCR) of the fluid during the early stage of production. These empirical equations should be valid for any gas condensate reservoir worldwide; although a range of usability is proposed for a better performance of the correlations.
Interpretation of Cleanup Data in Gas-Well Testing From Derived Rates
Authors: Hashmi G. M. , Kabir C. S. , Hasan A. R.
Published: October 2014

In drillstem testing (DST), analyses of transient data are generally restricted to the post-cleanup period because rates often go unmonitored at early times during the cleanup phase, unless aided by multiphase flow metering. The value of early-time production data monitoring may be overlooked for two reasons: first, transients may be difficult to interpret because of two-phase flow in the formation; second, two-phase flow metering becomes a requirement.

The objective of this study is two-fold: to estimate rate from distributed-temperature sensor (DTS) data available for downhole telemetry with a rigorous transient analytical model, and to use the computed rates to perform transient analysis for both the pre- and post-cleanup periods. Comparing and contrasting permeability estimates from the two periods provides guidance on the suitability of this approach. To that end, this study compares and contrasts rate computation with analytical methods. The new methods entail transient-temperature modeling with and without superposition effects. Two field examples strengthened the new rate-computation methods introduced here, and simulated examples probed the possibility of extracting meaningful information from the cleanup data.
Resolving the Mixed Salinity Challenges with a Methodology Developed from Pulsed Neutron Capture Gamma Ray Spectral Measurements
Authors: Ma S. Mark , Pfutzner Harold , Al-Hajari A. A. , Musharfi Nedhal M. , Saldungaray Pablo , Azam Hisham
Published: October 2014

The mixed-salinity environment poses a challenge in petrophysics. Many efforts have been made, but the industry still lacks a workable solution for accurate formation measurements in the presence of variable or unknown water salinity, especially in reservoir surveillance when well completion restrictions require running slim logging tools.

A pulsed-neutron (PN) spectroscopy tool was characterized using laboratory limestone formations and with data generated through Monte Carlo simulation. Seventy-six measurements were conducted with conditions of openhole (OH) and cased-hole (CH) completion, porosities of 15.4 and 42.9%, borehole fluids of water and oil, and borehole and formation water salinities of 0, 20, 50, 100, and 200 ppk. These were supplemented with 88 modeled points to better define the porosity (extending down to 0%) and salinity dependence of the tool response. Twenty additional measurements were taken in a dolomite formation to investigate lithology dependence and ten additional measurements were taken with oil in a 43.9% porosity formation to investigate fluid saturation dependence.

Salinity is derived from data obtained with a PN tool operated in the carbon/oxygen (C/O) mode. Ratios of the elemental yield of chlorine (Cl) to that of hydrogen (H) are computed from the near- and far-detector capture gamma-ray spectra. Using a scheme similar to C/O log interpretation for oil saturation, crossplots of the near- and far-detector Cl to H ratios were generated. A quadrilateral is formed on this crossplot by separately varying the borehole and formation water salinities. The established quadrilaterals, a newly developed algorithm to handle intermediate values of near and far ratios and of porosity, and independently obtained borehole water holdup (Yw) and reservoir water saturation (Sw) are then used to compute the borehole and formation water salinities that produced the measured Cl to H ratios.

Results obtained were compared with values determined from formation tester samples, demonstrating that a solution for accurate formation water salinity determination is established, thus resolving the challenge of mixed salinity in formation evaluation and reservoir surveillance.
Lease Fuel, Fuel Gas or Fuel Consumed in Operations- Is it Reserves?
Authors: Morales E. , Lee W. John
Published: October 2014

Lease fuel (also called fuel gas, fuel consumed in operations or lease-used gas) is defined by the SPE/WPC/AAPG/SEG/SPEE-Petroleum Resource Management System (SPE-PRMS) as "that portion of produced natural gas, crude oil, or condensate consumed as fuel in production and lease plant operations." Reporting this "fuel" as reserves, usually with a clear reference to the reserves attributed to these volumes, has been a practice commonly used by many companies, but not by all. Differences exist within a country and between countries regarding the application and interpretation of the existing standards and regulations concerning the reporting of lease fuel as reserves, resulting in a lack of consistency and comparability between oil and gas companies in the reserves externally disclosed.

Annual reports, 10-K and 20-F forms of oil and gas companies indicate that, during the last few years, significant volumes of additional reserves are still being added as a result of including, for the first time, the fuel Consumed in Operations (CiO) in the disclosed reserves. These volumes can be material.

Based on the companies reviewed, these volumes can represent up to 12% of the company's total proved reserves, depending on the amount of produced hydrocarbon products consumed as fuel, the type of processes used (e.g., normal production of oil and gas, LNG processing, electricity generation, compression needs, etc.) and the location of the terminal point (SEC terminology) or reference point (SPE-PRMS terminology).

A review of definitions, apparent misaligned standards (e.g., SPE-PRMS, Canadian Oil and Gas Evaluation Handbook (COGEH)) and requirements from regulatory bodies (Canadian Securities Administrators (CSA), US Securities and Exchange Commission (SEC), UK London Stock Exchange (LSE-AIM), European Securities and Market Authority (ESMA), Australian (ASX), Hong Kong (HKEx) and Singapore (SGX) Stock Exchanges) are discussed in this paper. Examples are also presented with the rationale of why these "lease fuel" volumes should be part of the reported reserves and should include proper narrative on these volumes. Updates of the lease fuel definition and references to lease fuel in the SPE-PRMS are also suggested in this paper, in order to reflect that, during the last few years, many countries and/or regulators have adopted the SPE-PRMS as the estimation and classification standard for reserves and resources, as well as the increasing amount of large integrated energy intensive projects (some of them presently in the undeveloped reserves category), and the increased relevance of unconventional resources and their role in lease fuel.

Inconsistencies in the approach to report (or not) the "lease fuel" as reserves are addressed, highlighting the need for clarity in the standards and disclosures being applied to ensure proper transparency, consistent valuation and reporting within the industry in the area of lease fuel, allowing proper comparability.
Evaluating the Risk of Casing Failure Due to High-Density Perforation: A 3D FEM Case Study from a Deep Water Reservoir, GOM
Authors: Guo Y. , Blanford M. , Candella J. D.
Published: October 2014

For a deviated well planned in a highly compressible deep water reservoir in the Gulf of Mexico, a typical perforation strategy of 140° phasing with 16 shots per foot (spf) is unlikely to meet flux requirements at the anticipated production rate. Perforating the production casing twice to double the flow area is one option to avoid exceeding the maximum flux limit. But will the high-density perforations impact the casing strength enough to cause casing failure as the reservoir compacts, given the reservoir operating limits? This cannot be assessed either by using existing analytical or numerical models, or from available empirical or experimental data.

To evaluate the feasibility of using a double perforation approach, a 3D finite element (FEM) model has been developed to determine the effect of the additional holes on casing failure. The model considers variations in both casing thickness and perforation pattern under expected wellbore and reservoir conditions. Both perforated and unperforated casings were analyzed to compare casing deformation characteristics and to determine the effect of the perforation on critical depletion pressures.

The FEM model shows that casing deformation is not uniform, resulting from nonuniform strain loading across reservoir boundaries and nonuniform distribution of casing strength as a result of the perforation. For the unperforated casing, the maximum strain is associated with bending near the reservoir boundaries. In contrast, the maximum distortion of the perforated casing is concentrated around the perforation holes at the ends of the perforated intervals. Allowing for a critical strain of 6% in the casing, the depletion limit would have to be reduced from 3500 psi to 2600 psi if the second set of perforations could be applied uniformly relative to the first set. A nonuniform distribution of the second set could further reduce the casing strength and lower the critical depletion pressure to 2200 psi. Finally, the study also shows that increasing the casing thickness by 0.0625 inches would have almost no effect on casing deformation or the attendant reservoir operating limit.

The study quantifies how much casing strain to expect in the scenario described – and that is critical for evaluating the risk of casing failure in expensive deep water wells. The results suggest that models like the one described here in fact offer a feasible way to assess casing deformation in highly compressible reservoirs where high density perforation may lead to casing failure.
A New Approach to Perform a Probabilistic and Multi-Objective History Matching
Authors: Almeida Forlan La , Davolio Alessandra , Schiozer Denis José
Published: October 2014

Assisted history matching procedures are usually implemented within an optimization procedure, where the goal is to minimize the object function, which is written in terms of the error between observed and simulated data. One of the problems of the process is that the objective function represented by a single value is not sufficient to express the complexity of the problem. The errors that are normally measured for each well and for all production rates and pressure are converted to a single value; usually the norm of all error vectors. If the problem is well behaved and the objective function quickly converges within a desired tolerance, this would not be a problem, but this is usually not the case for complex history matching processes, since it is very difficult to find a model (or a set of them) that matches with a reasonable tolerance the production profiles for every wells. This work proposes a new approach to deal simultaneously with several objective functions (for instance, well rates and pressure). The methodology follows a probabilistic approach where several simulation models are handled during the entire procedure. The initial step is to generate several simulation models by combining the most important uncertainties of the reservoir. Then, an iterative procedure is performed to iteratively change the reservoir attributes and filter the models that are closer to history data. This procedure encompass a re-characterization step, where the probability of the attributes are updated, global multipliers are applied and local changes are made around problematic wells in order to provide a set of model that yield production and pressure curves with better dispersion compared to history data for every well. The key point of the methodology is that for every iteration the errors of each model, well and objective function can be visualized in a very concise plot that is based on the normalized quadratic error of each curve. The plot clearly shows global and local problems of the set of simulation models, so it is a good indicator of the changes to be made in the next iteration. Another point to highlight is that the same type of iterative procedure is performed to integrate 4D seismic into the process. Thus, after selecting a set of models with a good representation of well history data the same iterative process is repeated to generate a new set of models that match 4D seismic data as well. Thus, the proposed methodology integrates 4D seismic and well history data to reduce uncertainties with a probabilistic approach. To validate the methodology an application is shown where it can be seen the gradual improvement achieved for the models along the iterations.
Microseismic-Derived Correlations to Production in the Horn River Basin
Authors: Snelling Paige , Rahimi-Zeynal Asal , de Groot Michael , Hwang Kyubum
Published: October 2014

Production from two multilateral pads in the Horn River Basin is compared to microseismic-derived parameters. Microseismic was recorded on a near-surface array in both cases. The number of events recorded on each well tends to have a positive correlation to that well's initial production, while the magnitude of those events does not tend to be a good indicator of production in all zones. Fracture models created from located microseismic events also tend to correlate well to production: modeled fracture area, fracture volume and stimulated reservoir volume all show positive correlations.

The method in which the rock fractures can also be an indicator of initial production. Wells with higher percentages of dip-slip type rock failures, which can be associated with hydraulic fractures, tend to have higher initial production. In contrast, wells with a larger proportion of strike-slip events, which are typical of fault reactivations in this zone, tend to have diminished production compared to neighboring wells with fewer reactivation events.

By understanding what microseismic parameters positively and negatively impact initial production, operators can optimize well production. This can be done in real-time or in installments during lengthy completions programs through the identification of failure type, fracture geometry, and the relative number of events being recorded.
Diffusion and Dispersion Dominated Solvent Injection Processes in Oil Saturated Porous Media: 3-D Visualization Experiments Using Laser Technology
Authors: Fang F. , Babadagli T.
Published: October 2014

A technique to visualize miscible displacement in porous media is introduced in this paper. After saturating the model made of different sized glass beads with oil, solvent was introduced to mix and displace it. The refractive indices of saturated and injected fluids were made the same by mixing them with lower and higher indices of refraction. This method, called refractive index matching, made the model transparent. Fluorescent dyes that were only visible with excitation of laser were dissolved in the solvent. A laser sheet scanned the model while synchronous pictures were taken by two high speed cameras from two sides of the model. Two groups of models were worked on: (1) Solvent diffusion under purely static conditions, and (2) injection/production through a pair of horizontal wells (VAPEX type).

From the diffusion experiment, it was found that the solvent fronts were always higher close the surface of the model. It was more obvious as the model size became larger. The total diffusion time was proportional to the length of the side of the models. In the VAPEX scaled model experiment, a dome shaped solvent chamber was observed. The size of the solvent chamber decreased as distance of the injection port increased due to pressure decrease. The solvent had to spread along the top of the model before starting to displace the oil down. It is hoped that the visual observation will help in understanding the processes in the reservoir to optimize the design of solvent injection for oil recovery.
Should we Assign Different Well Performances for Low-Best Technical-High Cases in Prospect Evaluation?
Authors: Harrison Bob , Quinn Patrick
Published: October 2014

When creating production forecasts in order to evaluate a prospect, is it more realistic to vary the estimated well performance parameters to reflect the likelihood of the prospective resource case being modeled? For example, should wells in the high case perform better than wells in the best technical case (BTC), which in turn outperform those in the low case? If one subscribes to this school of thought, what is the most appropriate way of assigning such variation in expected well performance?

The initial rate of a well is not exclusively a function of rock and fluid properties, it also depends on completion type, formation damage, clean up practices, cement bond quality, sand control requirements, artificial lift design, coning rate constraints, to name but a few. It is regularly observed that initial well rates rarely match those suggested by theoretical calculations.

Office sweepstakes for guessing the headline flow rate from a new discovery always reveal a large range of expected initial rates and, possibly more worryingly, the reservoir engineers rarely win. Bearing this in mind, the paper goes on to ask whether it is better to simply use the same ‘average’ well performance throughout all of one's prospect analysis?

Another approach is to use the assumed geological model to divide up the prospect into good, average and poor areas and assign an appropriate well performance to each of them, based on what one believes is the reservoir quality and fluids in each prospect area.

The paper discusses the various issues confronting the reservoir engineer engaged in prospect evaluation, weighing up the arguments for changing well performance in the different cases and the arguments for leaving the well performance the same for all cases. The impact on the expected value of an exploration portfolio is discussed, depending on which approach is chosen.
Deepwater Cementing: Key Decision Process and Successful Techniques for Addressing Production Liners
Authors: Fuller George A. , Edwards Joseph , Mercado Steven , Szymanski Michael , Mead Christopher , Nguyen Cecilia , Febbraro Anthony
Published: October 2014

A multitude of challenges exist when cementing production liners for deepwater operations. In many platform operations, cutting windows to sidetrack and drill highly deviated well paths to intersect reservoir targets result in difficulty obtaining adequate casing standoff due to tight inside diameter (ID) restrictions from previous casing architecture. Many of the zones near the target interval may have significant pressure depletion which can lead to expensive Synthetic Based Mud (SBM) losses and associated non-productive time (NPT). The size of the production liner is dependent on the wellbore architecture and completion plan. Thus in most cases, the borehole must be under-reamed in order to provide for adequate cement sheath thickness. In these cases, centralizer selection and placement can be challenging or all together impractical. Cementing in SBM environments has also been traditionally more challenging because special considerations for spacer/surfactant/mud design and testing are required to effectively displace the mud and "water-wet" the formation/casing for good quality cement-bonding. Technology improvements in spacer and surfactant package formulations provide a more qualitative method for optimum surfactant design to maximize mud removal and provide a bonding surface to the formation. Liner hanger selection may not always provide the capability for pipe rotation which has shown to be very effective for mud removal and increased circumferential cement coverage. Without pipe rotation, additional key techniques for successful cementation must be prioritized. A process driven decision matrix is presented along with a recent selection of successful production liners to support the design concept.
A New Methodology of Selecting Sand Control Technique in Open Hole Completions
Authors: Parlar M. , Tibbies R. J. , Gadiyar B. , Stamm B.
Published: October 2014

Sand control technique selection in open holes has been a topic of interest since the late 90s and discussed in many papers, most comprehensively by Price-Smith et al. (SPE 85504) who proposed guidelines for selection between standalone screens, α/β packing and shunt tube packing. Proposed guidelines were based on formation characteristics (formation strength, particle size distribution, mineralogy across the well path, etc.) as well as risk (execution, reliability/longevity, etc.) and cost considerations. From a particle size distribution standpoint, their guidelines were based on the criteria proposed earlier in SPE 39437 (Tiffin et al. 1998), while risk evaluation was based on the technologies available at that time.

In this paper, we begin with a critical review of the current sand control technique selection methodologies for open-hole completions, including the way some of the risk factors are being evaluated to eliminate a given completion technique. Based on the technologies developed in the last decade, we propose a new selection methodology along with techniques/tools for proper evaluation of the risk factors. The proposed methodology significantly extends the application limits of standalone screens and α/β packing compared to what was proposed in SPE 85504 (Price-Smith et al. 2003).
Screening Criteria and Methodology for Quality Check and PVT Selection for Reservoir Studies
Authors: Paredes J. E. , Perez R. , Perera L. M. , Larez C. J.
Published: October 2014

In the literature, there isn't a unified criterion to establish a methodology for quality assessment of PVT analysis. Worldwide, engineers have proposed the use of well-known validation methodologies but these validation methodologies not necessarily encompasses the whole consistency of a PVT study or its representativeness of the reservoir fluids. It is well known that a PVT study might have a great consistency after it's validated but when it's used in a reservoir characterization it didn't reproduce the measured behavior of the fluid present in the reservoir. These types of inconsistencies are common and could cause very important errors in analysis such as: Original volume, reserves estimation, surface facilities planning and exploitation strategies. The impact on the results and decisions taken based on the information present in a PVT study can be crucial and therefore every PVT analysis should include a level of uncertainty index that could allow to know beforehand the cost of using such information.

The versatility and complexity of most the experiments conducted during a PVT study makes the task of creating a unique methodology of quality quantification difficult. The present paper proposes a methodology for quality control and uncertainty assessment. This methodology considers each of the stages involved in the process of obtaining a PVT analysis: from the fluid sampling to the experiments results. According to previous work and field experience, the most important parameters or conditions were selected at each stage. These parameters are called Critical Points; each Critical Point has and associated impact level (high, medium and low.) and weight that reflects directly in the overall quality index of the PVT study.

Critical points were subsequently grouped into 6 Control Categories: Sampling conditions, reservoir conditions, experiments control, measured properties control, fluid type validation and validation of experiment consistency. An ideal value of 10.0 was established for a report PVT that has excellent condition, very low uncertainty and meets all the conditions proposed in this paper. Additionally, a Quality Index (QI) and Validation Index (VI) were proposed as two indicative values of the level of uncertainty of any PVT study. Using a proposed Nomograph, engineers can evaluate and categorize the quality results from any PVT study. The results from applying this methodology to 50 PVT studies are presented and a Material Balance and numerical simulation study were carried out to exemplify the impact of using for the same reservoir, PVT from different level of quality.

The goal of this work is to have a practical methodology that can give engineers a "Quality Index" of any PVT study. This quality index could be an indicative of the level of uncertainty and the degree of reliability of the PVT study before it's subsequently used in any reservoir or well analysis. This methodology could be used worldwide without limitations
Fracture Characterization of a Carbonate Reservoir by DFN Modeling: A Case Study
Authors: Turkmen Melike Ozkaya , Gozel Mustafa Erkin
Published: October 2014

One of the main challenges in development of the fractured reservoirs is the identification of "sweet spots" which are the most intensely fractured areas of a field, maintaining a long term production with minimized risks in drilling. This paper presents a multi-disciplinary approach including G&G (geology & geophysics), petrophysics and reservoir engineering perspective to overcome this difficulty in a particular oil reservoir by defining the fracture systems that mainly contributes to the hydrocarbon storage capacity and flow dynamics.

Şambayat Field is one of the most important naturally fractured carbonate reservoirs located in the Southeast Turkey. Reservoir zones in the field include a number of reverse, synthetic and antithetic faults and related fracture sets which are hydraulically in contact with each other. In this context, characterizing the fracture network becomes the most critical issue in the analysis of production and the development strategy of the field.

For this purpose; besides the conventional open-hole log analyses, image log interpretations have also been performed in order to evaluate the properties of the fractures. To honor these interpretations; dynamic (drill stem test & production) and static (outcrop & core) data have been evaluated together. Distributions of the petrophysical properties and the fractures have been done by using stochastic methods in full-field scale. At the end of the modeling study, a dual porosity geological model has been generated by using the Discrete Fracture Network (DFN) approach with respect to the estimated fracture characteristics.

As the result of the previous characterization study, new well locations and their optimized orientations had been determined and the results coincided with the expected types of fractures estimated in the DFN model. After updating the model with the new well data and the enhanced functionalities in the modeling software, additional well locations have been proposed which will play a role in one step further of the study; simulation.

This study has contributed to our knowledge about the characteristics of a naturally fractured carbonate reservoir which is similar to the ones explored in Southeast Turkey and to some extend in Middle East. It should also be noted that, our approach in this particular study is a newly developing technique and could be used for the promising "previously overlooked" unconventional reservoirs.
Acoustical and Geomechanical Characterization of Eagle Ford Shale - Anisotropy, Heterogeneity and Measurement Scale
Authors: Mokhtari M. , Honarpour M. M. , Tutuncu A. N. , Boitnott G. N.
Published: October 2014

In this study, the acoustical and geomechanical properties of preserved cores and the associated well logs from the lower Eagle Ford shale in La Salle County, Texas are presented. Anisotropy is evaluated using measurements at various scales: at the pore scale by scanning electron microscopy (SEM), at the lamination scale by compressional velocity scanning and x-ray computed tomography (CT) imaging and at the core scale via static/dynamic measurements on both 1-inch and 3-inch diameter cores. Finally, correlations from core data are applied to sonic log interpretation to improve the estimation of minimum horizontal stress in a vertical transverse isotropic media.

Three sets of horizontal and vertical 3-inch core samples were prepared from conventional cores in the light oil-bearing section of the lower Eagle Ford shale. Compressional velocities were measured every 0.5 mm to examine vertical heterogeneity at the lamination scale on 3-inch horizontal cores. In one of the samples, frequent thin layers with higher velocity (+15%) were detected. The high velocity layers correspond to foraminifera rich layers detected in the SEM analysis. These layers are source of vertical heterogeneity which can affect the anisotropic analysis.

Dynamic testing on the 3-inch cores was conducted followed by dynamic testing on 1-inch plugs (horizontal, vertical and 45°) drilled from each of the 3-inch cores and a comparative study between the 1-inch anisotropic results with their 3-inch counterparts was conducted. Shear and compressive anisotropy was similar between the 3-inch and 1-inch samples detected homogenous by velocity scanning. On the other hand, there was significant difference between the anisotropic parameters in the heterogeneous sample containing frequent foraminifera rich layers.

Using core data, correlations for the two unknowns of sonic logs (C13 and C12) and the dynamic to static correlations were obtained and applied in the calculation of elastic properties from logs. Consequently, the conventional minimum horizontal stress with isotropic media assumptions was modified by the core-derived correlations and anisotropic Biot's coefficient.

The results of this study determine how the heterogeneity due to lamination and scale can significantly affect anisotropic analysis. Finally, we discuss how to use more accurate experimental data to estimate the minimum horizontal stress from sonic logs using transverse isotropic modeling in the Eagle Ford shale.
Innovative Concentric 4×1 Design for Multi-Path Gravel Pack System Extends Effective Packable Length and Eliminates Additional Make-up Time
Authors: Fisher B. , Nguyen H. , Snitkoff J.
Published: October 2014

A common problem for modern horizontal gravel pack operations is the development of an annular bridge that blocks the flow of gravel slurry and prevents formation of a complete pack. Causes of annular bridging include high-rate leakoff zones or swelling shale layers within the reservoir. Secondary flow path technologies enable slurry flow to bypass any annular bridge and complete the packing of an openhole annulus. Current secondary flow path technologies on the market either lack the flow configuration to extend farther than several hundred feet, or they add complicated makeup and running procedures to align and secure a secondary slurry flow path.

A tube configuration has recently been developed to add redundancy to the flow path geometry as well as greatly increase the overall flow area, extending the effective packable length of the system. The 4×1 concentric tube design has been combined with an integral internal cross-coupling communication system, connecting tubes at each joint and adding no additional makeup time to the running procedure of conventional sand screens.

This paper presents the results of full-scale gravel pack simulations with leakoff and an annular barrier. The prototype multi-path system was run horizontally inside a simulated 8½-in. open hole. Slurry flow, prepared using conventional proppant in a viscous carrier gel or with ultra-low density proppant, successfully bypassed the sand dune created by the leakoff zone and the solid annular barrier, reaching all void areas and creating a complete pack.

By enabling slurry flow to bypass any annular bridge and reliably complete the packing of longer and longer horizontal intervals, secondary flow path technology promises to provide a reliable, low-cost solution for delivering failure-free gravel pack completions. Emerging technology in this field strives to simplify running procedure, extend functional length of secondary flow paths and reduce relative packing time.
Integrated Analysis for Fracture Identification During Hydraulic Fracturing
Authors: Guest A. , Rebel E. , Bailly S. , Kostadinovic J.
Published: October 2014

In order to improve our understanding of the interaction of the hydraulic fracture with pre-existing structures in reservoirs, we focused on separating microseismicity related to the hydraulic fracture propagation and microseismicity occurring along the pre-existing structures. We analyzed microseismic activity detected during the stimulation job in a horizontal well with ten stages. The microseismicity aligns in two major trends, E-W and NE-SW. The microseismicity in the NE-SW trend is aligned with the maximum horizontal stress and is related to the hydraulic fracture propagation. The E-W trend is related to the interaction of the hydraulic fracture with the pre-existing structures in the area. Some stimulated stages show very clear and distinguished spatial separation of microseismicity related to the two trends while some stages have more complex pattern. We combine several techniques that help to distinguish various types of seismicity: data set separation, geomechanical, magnitude-frequency, and well pressure analyses. The synthesis of the various methods helps to improve our understanding of the well stimulation. Overall, we almost doubled the number of hydrofractures and fault/fracture zones in comparison to the original interpretation based only on the microseismic mapping and we better constrained the half-lengths of the hydraulic fractures. The detailed data analysis strongly suggests that some hydraulic fractures may be aseismic.
Completion Optimization with Ceramics Provides Step Changes in Horizontal Performance for the 2nd Bone Spring Formation – A Southeastern New Mexico Case History
Authors: Jackson Kale , Palisch Terry , Lehman Lyle
Published: October 2014

The Permian Basin is one of the longest producing oil basins in the United States. To the west the Delaware Basin, located in southeastern New Mexico (SE NM) and West Texas, once thought to be extinct, has been revived through horizontal drilling and completion technologies. These tight formations, more importantly the Bone Spring formation, that were once uneconomic through vertical completions, have seen dramatic production and economic improvements with the advancement of horizontal drilling and completion technology lending to different requirements for proppant and fluid rheology for hydraulic fracturing optimization.

The Bone Spring formation in SE NM is a thick sequence of interbedded sandstones, carbonates, and shales with depths ranging from 6,000′ – 13,000′ that gradually deepens toward the southern part of the Delaware Basin. The discovery of an oil rich 1st, 2nd, and 3rd Bone Spring formation amid a much more gas-prone Avalon and Wolfcamp clearly demonstrates the complexity of the Delaware Basin, and does not adhere to either conventional or unconventional expectations of hydrocarbon development.

Due to this complexity, the following paper will describe the reservoir and completion concerns that have arisen from the deeper 2nd Bone Spring formation located in Lea County, NM and how adapting current industry completion techniques have proven to enhance the overall development. Topics that will be discussed in this paper include: Landing interval/lateral target pointStage spacing/perf clusters/perf strategyHydraulic fracture treatment design optimizationThe benefits of employing ceramic proppantIncreased productivity and EUR of 30%Production choke management and proppant flowbackCase history overview based on two re-entry horizontals and nine new-drill laterals

Horizontal drilling along with hydraulic fracturing have become the keys to unlocking potential reserves within the various Bone Spring formations. The successful methodologies and results presented in this paper will spur thought and discussion among engineers and the general SPE community, thereby discouraging simple repetitive designs and encouraging progressive thinking within this complex formation. The methodologies presented in this paper can also be applied to other liquids-rich resource plays that engineers will hopefully employ.
Trapped Gas Saturation Measurements: New Perspectives
Authors: Bona N. , Garofoli L. , Radaelli F. , Zanaboni C. , Bendotti A. , Mezzapesa D.
Published: October 2014

When a gas reservoir is overlying an aquifer, water will imbibe into the gas-saturated zone with the onset of gas production, trapping a certain amount of gas. This mechanism is expected to occur in a super giant field in Mozambique that hosts over 80 TCF of natural gas in place. The observed laboratory variations in trapped gas saturation represent one of the main uncertainties in the recoverable reserves of the field. Two laboratory methods for estimating this quantity are compared: one is the classic test in which core samples are immersed in a liquid and undergo a spontaneous imbibition measurement. The other is a new method that involves a series of forced imbibitions and combines centrifuge and NMR measurements. While the standard method produces countercurrent imbibition data, the new method generates co-current results. These are more representative of the reservoir process and tend to be more optimistic. The data analysis process involves the estimation of two critical Bond numbers: one is the classic value for the mobilization of trapped blobs of residual gas, the other sets the boundary between countercurrent and co-current imbibition regimes. Representative trapped gas saturation results are obtained only for Bond numbers lying between the two critical values. The new method is validated by the log data acquired in the two reservoirs under examination below the gas water contact, where immobile gas saturations are observed. Being caused by the rise of a paleo-contact, the observed saturations are considered to be representative of the trapped saturations that will form in the reservoir when production starts and taken as a reference for the lab measurements.
A Semi-Analytical Forecasting Method for Unconventional Gas and Light Oil Wells: A Hybrid Approach for Addressing the Limitations of Existing Empirical and Analytical Methods
Authors: Clarkson C. R. , Qanbari F.
Published: October 2014

The rapid pace of exploitation of unconventional gas and light oil (UG/ULO) plays in North America has necessitated the development of new production forecasting methodologies to aid in reserves assessment, capital planning and field optimization. The generation of defendable forecasts is challenged not only by reservoir complexities but also by the use of multi-fractured horizontal wells (MFHWs) for development.

In this work, we have developed a semi-analytical method that provides a solid theoretical basis for forecasting. The technique is analytical in that it uses the methods of Agarwal (2010) to calculate contacted oil- and gas-in-place (COIP/CGIP) from production rates, flowing pressures and fluid properties. The rate-normalized pressure (for liquids) or pseudopressure (for gas) derivative (RNP') is a key component of the calculation. The technique is also empirical in that an empirical function is fit to the resulting COIP/CGIP curve versus time. Although the method is flexible enough that any equation can be used to represent the COIP/CGIP curve, and hence the sequence of flow-regimes exhibited by MFHWs, the equation must be capable of being integrated to allow extraction of rate-normalized pressure or pseudopressure (RNP). The stabilized COIP/OGIP during boundary-dominated flow must be specified for forecasting – thereafter, the method uses a material balance simulator to model boundary-dominated flow. Hence, if the well is still in transient flow, a range in forecasts may be generated, depending on the assumed stabilized COIP/OGIP.

Our new semi-analytical method addresses some of the current limitations of empirical and fully analytical (modeling) approaches. Empirical methods, which have been adapted to account for long transient and transitional flow periods associated with ultra-low permeability reservoirs, lack a theoretical basis, and therefore input parameters may be difficult to constrain. However, empirical methods are simple to apply and require a minimum amount of data for forecasting. Analytical models, while better representing the physics, nonetheless require additional reservoir and hydraulic fracture data which may not be available on every well in the field. The semi-analytical method proposed herein is intended to bridge the gap between empirical and modeling-based approaches – it is more rigorous than purely empirical methods, while requiring less data than fully analytical techniques.

The new method is tested against simulated and field cases (tight oil and shale gas). Although we have used a simple power-law function to represent COIP/OGIP curve, which appears adequate for the cases studied, we note that wells exhibiting long transitional (e.g. elliptical/radial) will likely require a different functional form.
Field Premiere of Along-String Dynamic Measurements for Automated Drilling Optimization Using Downhole Information
Authors: Veeningen Daan , Pink Tony , McRay Mike , Luthi Melanie
Published: October 2014

The question of what is happening downhole is routinely answered through human interpretation of surface data. While widely available, subsurface data is typically pulsed from near the bit and acquired at low frequencies, resulting in considerable latency issues. Consequently, the majority of acquired subsurface data is memory-stored in drilling tools for post-well analysis, which, while useful for drilling subsequent wells in similar environments, does not allow for early detection and mitigation of unexpected downhole events.

This paper details field deployments of a system that offers real-time downhole measurements from the bottomhole assembly (BHA) and from two additional positions along the string. The system aids wellsite personnel and yields consistent performance through the use of automated closed-loop surface machinery control based on these real-time downhole measurements through an 80Hz downhole data-stream.

The high-frequency data acquisition system provides sufficient sampling resolution to diagnose many drilling dysfunctions in real time, including damaging events such as severe torsional oscillations leading to stick/slip, bit-bounce and whirl-induced vibrations. This allows mitigation strategies to be quickly evaluated and implemented based on adequacy and performance, preventing damage and improving performance. In addition, high-frequency toolface and survey data promoted directional drilling and sliding-drilling efficiency in the build and horizontal lateral.

This field test marks the premiere of along-string dynamic measurements above and beyond the pressure and temperature measurements that were already available to identify, analyze and control events along the wellbore. These include detecting tri-axial vibrations and rotation in real time, allowing drilling phenomena to be identified and quantified while also highlighting the dynamic variability of drillstring rotation and motion. In addition, the system improves the efficiency of hole cleaning and, through equivalent circulating density (ECD), evaluation along the string.

The system provides clarity regarding what is happening subsurface and offers automated rig control based on high-resolution downhole information from along the drillstring. Recommendations are offered, providing useful techniques for automation and drilling optimization projects.