bluuebunny/crossref_metadata_2025 huggingface dataset:
A New Method for Fracture Diagnostics Using Low Frequency Electromagnetic Induction
Authors: Basu Saptaswa , Sharma Mukul M.
Published: June 2014

Currently, microseismic monitoring is widely used for fracture diagnosis. Since the method monitors the propagation of shear failure events, it is an indirect measure of the propped fracture geometry. Our primary interest is in estimating the orientation and length of the ‘propped’ fractures (not the created fractures), since this is the primary driver for well productivity. This paper presents a new Low Frequency Electromagnetic Induction (LFEI) method which has the potential to estimate not only the propped length, height and orientation of hydraulic fractures but also the vertical distribution of proppant within the fracture.

The proposed technique involves pumping electrically conductive proppant (which is currently available) into the fracture and then using a specially built logging tool that measures the electromagnetic response of the formation. Results are presented for a proposed logging tool that consists of three sets of tri-directional transmitters and receivers at 6, 30 and 60 feet spacing respectively. The solution of Maxwell's equations shows that it is possible to use the tool to determine both the orientation and the length of the fracture by detecting the location of these particles in the formation after hydraulic fracturing. Results for extensive sensitivity analysis are presented to show the effect of different propped lengths, height and orientation of planar fractures in a shale environment. Multiple numerical simulations, using a leading-edge (FEKO) electromagnetic simulator, indicate that we can detect and map fractures up to 250 feet in length, 0.2 inches wide, and with a 45 degree of inclination with respect to the wellbore. Special cases, such as proppant banking and wells with steel casing in place, were also considered.
Re-fracturing Horizontal Shale Wells: Case History of a Woodford Shale Pilot Project
Authors: French S. , Rodgerson J. , Feik C.
Published: June 2014

Multi-stage horizontal well stimulation treatments have been the key completion approach driving the recent US shale revolution. This approach has transformed the industry, making it possible to economically stimulate reservoirs that were previously deemed uneconomic.

In attempting to deploy such multi-stage fracture treatments, several tools and processes have been employed during the completion phase. Most popular among these approaches, has been the ‘plug and perf’ technique, which permits multiple treatments to be performed along a horizontal wellbore. This widespread completion approach has allowed these fracturing operations to be rapidly executed, but with the short elapsed time between stages and wells, it has become increasingly challenging for the Completion Engineer to effectively close the evaluation cycle.

As many of these shale plays now mature, it is becoming increasingly apparent that the majority of the wells have not been effectively stimulated. Fracture interference and cluster efficiency being among the key concerns with the completion approach, with high efficiency rarely being achieved resulting in only partial coverage. In fulfilling the desire to complete these wells in a timely manner, it is now apparent that there likely remains a significant portion of un-stimulated pay in a typical well post completion.

In this paper we will not attempt to address the "Optimized Completion Design", but instead explore techniques that can be used to recomplete some of these wells and recapture a portion of this bypassed pay. The paper will present the planning, the execution and the results of a five well re-fracturing Pilot programme in the Woodford Shale; including a number of reservoir simulation studies. The discussion will also address the well selection process, the re-fracturing approach and the resulting improved production rates.
Gulf of Mexico Frac-Pack with a 10% Loading of an Intermediate Strength, Chemical-Infused Proppant-Sized Particle Designed to Provide Long Term Inhibition for Barium Sulfate Scale
Authors: Szymczak Stephen , Satya Gupta D. V. , Shen Dong , Steiner William , Langlinais Kevin
Published: June 2014

A new substrate, based on nanotechnology, that has strength greater than an intermediate strength proppant and a high surface area for chemical adsorption has been introduced and applied in deep water well in order to inhibit barium scale deposition for a prolonged period of time and/or a desired cumulative water production.

The subsea oil well in 1700 feet of water in the Gulf of Mexico was completed with a frac-pack using a total of 14,881 pounds of proppant. This includes a 10% (1,488 pounds) loading of the solid scale inhibitor product. The well was put on production following the completion. The field design calls for a sea water flood (containing sulfate). The scale inhibitor is designed to desorb into the connate water (containing barium) and to inhibit the formation of barium sulfate scale.

The solid product placement with the proppant was monitored to assure a homogeneous distribution of solid chemical particle in the proppant bed. Upon the onset of water production samples were analyzed for the presence of residual scale inhibitor. A residual indicates there is still sufficient chemical in the formation to inhibit scale. When the scale inhibitor residual falls below the minimum inhibitor concentration, and if the water still shows a scaling tendency, the operator has two choices. At that point he can initiate surface treatment through a chemical injection mandrel or perform a scale inhibitor squeeze. A squeeze onto this chemical-laden proppant substrate will last longer than a conventional squeeze that is placed onto the native formation rock.

The cost of a well intervention for a deep water sub-sea well can exceed ten million dollars. The cost for an intervention in a deep water dry tree will be less but still significant. By placing a long lasting scale inhibitor into the propped zone, the operator will realize an economic benefit far in excess of the cost of the application. By extending or possibly eliminating the need for a future intervention, the application of this technology can have a significant impact on the well economics.
A New Look on Fracture Injection Test for Shale Gas: Marcellus Case
Authors: Farinas Mauricio , Fonseca Ernesto
Published: June 2014

Fracture injection testing has been used in the Oil & Gas industry for decades. In conventional reservoirs fracture injection testing has been a standard practice since important information related to the fracture job design is directly dependent on the outcome of the test (fluid efficiency & leak off coefficient). In this testing method, commonly known as a MiniFrac, fracturing fluid is pumped at typical treatment rates, with a total injection volume of approximately 200 bbls, and pressures are recorded during injection and after pump shut-in.

This study examines the results of a Minifrac conducted in a vertical well in the Marcellus Shale and illustrates how MiniFrac testing can play a useful role in fracture diagnostics in the Marcellus Shale and possibly in other shale formations. In the test case, a volume of 160 bbls of water was pumped at 10 bbls/min; and fracture height growth was infered using wireline temperature logs. The temperature logs showed fracture height containment and these results were validated using pressure response data generated throughout the test. Closure time was estimated to be 6 min and the onset of radial flow was determined to be 4.6 days using a combination of standard fracture diagnostics plots and the pressure derivative. Moreover, a numerical and analytical match of the test was performed and it was interesting to see how the results showed excellent agreement with the field data. Finally, a sensitivity evaluation to pump rate & job volume was performed using a calibrated analytical model, and these results showed fracture closure time is more sensitive to the type of fluid injected and less sensitive to job volume. These results are encouraging and suggest the application of MiniFrac testing in the Marcellus shale, and possibly other shale formations, may be an effective tool in hydraulic fracture diagnostics.
Innovative Use of NMR to Study the Fracture Fluid Propagation in Shale Formation
Authors: Gomaa Ahmed M. , Zhang Boyang , Chen Jinhong , Qu Qi , Nelson Scott
Published: June 2014

The breakdown of shale and the created fracture complexity are greatly dependent on the flow behaviors of fracture fluids just before fracture initiation. Because of the unique characteristics of shale formations—including low permeability, existence of micro-fractures, and sensitivity to contacting fluids—it is difficult to evaluate fluid flow with traditional laboratory methods. NMR technology has been explored to study the propagation of fracture fluid inside shale core before fracture initiation. All fluids were injected at pressures less than fracture pressure. Cores from three different shale formations (Eagle Ford, Marcellus and Mancos) were evaluated with the new methods. Variations such as fluid types (slickwater, acid and oil), injection pressure were evaluated.

Based on experimental results, the volume of fracture fluid that propagated inside shale cores has a strong relationship with fluid viscosity, where increasing fluid viscosity reduced this volume. NMR confirmed that slickwater or a higher-viscosity fracture fluid did not propagate inside the small shale pores (less than 0.01 μm as an average estimation) but did propagate inside larger pores and inside the existing microfractures. High-viscosity fracturing fluid was only able to fill the larger shale pores, while slickwater fracture fluid filled the large pores and connected them to increase the microfracture density. This allows the slickwater fluid to break the shale formation with lower pressure and produce more complex fractures than high viscosity fluids. Reactive fluids, such as HCl acid solution, were also studied and found to leak into the shale core by increasing the contact time, even for shale with low HCl solubility (less than 2 wt%).
Multiphysics Investigation of Diagnostic Fracture Injection Tests in Unconventional Reservoirs
Authors: Wallace J. , Kabir C. S. , Cipolla C.
Published: June 2014

Diagnostic fracture injection tests (DFIT) are commonly used to characterize stress and reservoir properties in unconventional reservoirs. Although simple in concept, interpreting DFIT results can be difficult because several factors can cause results to deviate from ideal DFIT behavior. Some examples of nonideal DFIT behavior include steep pressure declines after shut-in, absence of pseudolinear and pseudoradial flow, and excessive storage indications. Such deviations from ideal DFIT behavior challenge our ability to estimate formation properties reliably. Potential drivers of nonideal behavior include heterogeneous rock properties, complex rock/fluid interaction, thermal effects, phase entry, and natural fractures.

The objective of this study is to investigate how these factors can impact DFIT results and interpretations. A comprehensive approach was taken using a combination of pressure transient analysis, frac modeling, analytical leakoff modeling, and detailed numerical simulation of DFIT behavior. The application was for a horizontal well, completed in a shale gas reservoir, which included an actual field DFIT. Detailed modeling included full wellbore transients and storage, hydraulic behavior through induced fractures, as well as complex interactions between rock, fluids, and natural fractures. It was determined that the actual DFIT showed indications of a complex network created by the pump-in. Closure pressure estimates were found to be reliable, between the simulation cases and DFIT analysis. However, a consistency check on initial reservoir pressure had to be used to obtain reasonable estimates compared to the simulation input. Finally, estimates of reservoir conductivity were highly uncertain compared to the actual simulation inputs. Furthermore, the actual DFIT estimates of reservoir pressure and conductivity were found to be overoptimistic. Estimated ultimate recovery using DFIT-based estimates of reservoir quality was shown to be more than twice the estimated ulterimate recovery using reservoir quality estimates made with integrated core, log, and a pressure build-up test.
Evaluation of Multi-Fractured Horizontal Well Performance: Babbage Field Case Study
Authors: Al-Shamma Basil , Nicole Helene , Nurafza Peyman R. , Feng Wei Cher
Published: June 2014

This paper presents the analyses of well tests and production logging carried out on three multi-fractured horizontal wells in the Babbage tight gas field, UK Southern North Sea. The actual performance observed in these wells was compared to the forecasts made based on open-hole well data and the data gathered during hydraulic fracturing operations. Some of the drawbacks in analysing well test data are discussed along with the uncertainties in modelling hydraulic fractures.

Horizontal wells with multiple hydraulic fractures are used to increase productivity and recovery in tight reservoirs. Understanding and predicting fracture performance is essential to the field commerciality considering the associated high development costs, especially in the North Sea.

The results of this study indicate that based on several pressure transient analyses, the clean-up time can be up to several months, which was observed in the form of gradual skin reduction over time. The PLT data also confirmed that there is cross flow during the shut in periods, usually flowing from the outer fractures into the inner fractures. This was believed to have an impact on the interpretation of the build-ups. Moreover it was shown that during build-up tests of more than 500 hours, linear flow was the dominant flow regime and therefore the final radial flow stabilization had not yet been reached.

There are many studies in the literature on the design, operations, characterization and numerical modelling of similar multifractured horizontal wells. However there are not many publications presenting real field data and the performance of these wells. This paper covers the well performance data in addition to the design, modelling and operations of the multi-fractured horizontal wells.
Performance of Mixed Proppant Sizes
Authors: Schmidt Darren , Rankin P.E. Russell , Williams Brandon , Palisch Terry , Kullman John
Published: June 2014

Many well stimulation designs in the Bakken Petroleum system of the Williston Basin include hybrid treatments in which multiple fluid types and proppant types are incorporated into the pumping schedule. The industry at the present time is generally focused on cost competitiveness and efficiency. Given the changing trend, a convergence of well stimulation techniques might be expected, however stimulation design and strategies among operators have diverged (figure 1) relative to fluid choices, proppant, and pump rates [Robart et al 2013].

This paper presents an investigation that was conducted to ascertain the potential effect of the mixed proppant sizes relative to fracture conductivity. It is common in hybrid completion designs to mix various sizes of proppant based on stimulation design assumptions and criteria. It is expected that a high concentration of the least conductive proppant is likely to dominate the overall fracture conductivity, but to what degree and to what extent was the question. Also, proppant size distribution is likely to vary throughout the fracture. Depending on the treatment fluids, viscosity, and expected settling rates, proppant may be segregated by tail-in, evenly blended, or blended with dominant concentrations of one particular size.

These potential scenarios were simulated in conductivity cell experiments to gain an understanding from laboratory results. The results include a number of interesting conclusions regarding the selection of tail-in proppants and the performance relative to smaller sizes of sand and light weight ceramic.
Achieving a more Efficient Frac Network for Horizontal Development of the Bone Spring Sandstone
Authors: Carrasco Arturo , DeGeare Joe , Hunter John
Published: June 2014

As development of shales and other tight formations has evolved, it has become clear that the key to optimum reservoir drainage is systematic well placement and an efficient fracture network that delivers maximum connectivity to the reservoir. That typically means the greatest number of wells and stages per well as is practical for a given acreage, without risking communication either between stages or between wells.

The most efficient fracture network, however, requires consistent stage spacing and uniform fracture volume, neither of which has been achievable using plug-and-perforate (PnP), the most common multistage completion technology. The limitations of PnP are well known and documented. Because the technique relies on stimulating multiple perforation clusters simultaneously, and because breakdown pressures vary widely across any lateral stage section, there is no control over which clusters actually fracture. Studies using radioactive tracers and production logs have revealed that a third or more of all clusters are not stimulated at all, while others receive varying amounts of treatment. That leaves only a few clusters to account for almost all of the proppant placed, indicating uncontrolled fracture volume as well as unpredictable placement.

When multiple adjacent and parallel wellbores are completed using PnP, the effects of the random fracture pattern are multiplied, with large areas of the formation unreached by the stimulation. One operator developing the Permian Bone Springs sandstone estimated that as much as 60% of producible reserves were stranded as a result of incomplete reservoir stimulation using PnP.

This paper compares those PnP completions with a subsequent completion using full-drift, cemented casing sleeves and a coiled-tubing-deployed frac-isolation assembly to achieve exact fracture location and uniform fracture volumes, regardless of varying formation breakdown pressures. This well was on the same lease property and was drilled in the same manner as those completed with PnP. The operator typically runs 44 evenly spaced full-drift casing sleeves in the completion string instead of 48 perforation clusters in 12 stages.

Throughout the stimulation operations, the operator was able to confirm the volume of proppant placed at every stage. This paper describes how the comparison wells were drilled and completed and presents production data that indicates a much more efficient fracture network across the entire lateral using the cemented casing sleeves. The paper also compares the operating advantages and disadvantages of the two completion methods.
Quantifying Proppant Transport in Thin Fluids - Theory and Experiments
Authors: Mack Mark , Sun Juan , Khadilkar Chandra
Published: June 2014

In conventional fracturing fluids, proppant transport is governed by settling, described by Stokes Law. In thin fluids, saltation and reptation (creep) may dominate proppant transport. Past slot tests have shown that a proppant bank forms in the fracture and that proppant pumped later may overshoot previously-pumped proppant. If this occurred in full-scale hydraulic fractures, it could negate the benefits of pumping tail-in stages of more conductive proppant.

Proppant banks can also migrate in a manner similar to wind-blown sand dunes. Although some qualitative results have been derived from past slot tests, there is very limited quantitative data on proppant transport via saltation and reptation. This paper outlines the theory behind these two transport mechanisms and identifies the key parameters governing them. The relative importance of a high coefficient of restitution and low friction coefficient are demonstrated.

The methodology and results of experiments to measure the material properties governing saltation and reptation are presented for both conventional and advanced ceramic proppants and compared with those for sand. Advanced ceramic proppant has both a high coefficient of restitution and a low friction coefficient. Although sand has a higher coefficient of restitution than conventional ceramic proppant, it transports poorly due to the high friction associated with a rough, irregular surface.

Both qualitative and quantitative testing has been performed in two large-scale slots. Qualitative testing has shown the development of dunes and demonstrated the impact of friction on dune shape. Results of tests pumping larger (30/40) proppant after smaller (50/60) show that larger proppant can fill the entrance (near-wellbore) area as opposed to passing over the smaller proppant, and flow through a slot representing a complex network has shown how proppant can "turn the corner" from a primary fracture to build a dune in a secondary fracture. Finally, quantitative testing has validated the theory and experimental measurements related to the initiation of proppant transport from a static bank.

Some criteria to select the optimum proppant for slickwater fracturing are provided.
Spatial and Statistical Analysis of Hydraulic Fracturing Activities in US Shale Plays and the Effectiveness of the FracFocus Chemical Disclosure System
Authors: Arthur J. D. , Layne M. A. , Hochheiser H. W. , Arthur R.
Published: June 2014

The FracFocus chemical disclosure registry provides public disclosure of hydraulic fracturing chemical additives used in more than 55,000 wells by over 600 companies in the United States. The large number of well sites that have been entered into the registry present a rich population of hydraulic fracturing jobs over a wide geographic area and spanning a period of almost three years. As FracFocus evolved, the authors conducted an internal project to compile the disclosures into a database format more suited to analysis. This has entailed considerable resources to capture the PDFs available, assess the quality of the data in FracFocus, detect and correct data errors and inconsistencies, and convert PDF submittals to a database format. The resulting database can be used to analyze a number of research questions about hydraulic fracturing and related environmental concerns and public disclosure issues.

This paper will demonstrate the effectiveness of the FracFocus database in investigating a variety of questions concerning hydraulic fracturing, including: water use trends across plays, among plays, among companies, and over time; chemical makeup of fracturing jobs, again within and between plays, and among companies; geographic distributions of disclosures (where are submissions being made?); company distributions of disclosures (who is making them?); how the volume of fluids and the number and type of fracture fluid additives vary by company, by region and play, and even within plays. The analysis of the data from FracFocus can help bring a scientific, data-driven approach to addressing many of the concerns expressed by the public, non-profit organizations, and regulatory agencies regarding hydraulic fracturing.
Cement Sheath Integrity during Hydraulic Fracturing: An Integrated Modeling Approach
Authors: Wang W. , Dahi Taleghani A.
Published: June 2014

Recent arguments about the possibility of underground water pollution in particular regions have raised significant concerns regarding wellbore integrity during hydraulic fracturing in shallow formations. In this paper, we take a look at the containment of annulus cracks that might develop during hydraulic fracturing treatments. Wellbore integrity is highly dependent on the integrity of the bonding between the cement and the formation as well as the bonding between casing and cement. Cement heterogeneity resulted from unsmooth borehole surfaces, complex geological conditions, mud cakes, and cement contamination. Excessive fluid pressure during hydraulic fracturing could provide the driving force not only for initiation and propagation of fractures in longitudinal and transverse directions, but also in cases of low confining pressure, it may lead to fracture propagation around the casing, i.e. annulus cracks. A coupled three-dimensional poroelastic model with embedded cohesive zones is used to simulate different fracture propagation scenarios that may occur in vertical and horizontal wells during hydraulic fracturing stimulations. The cohesive layer theory is utilized to model initiation and propagation of transverse, longitudinal and delamination fractures. Using the numerical analysis provided in this paper, few hydraulic fracturing cases were simulated by taking the advantage of the treatment pressure data and petrophysical logs, and the results were compared with the post-treatment radioactive tracer logs available for these wells.
Development of the Wolfbone Formation Using Open Hole Multistage Vertical Completion Technology
Authors: Lohoefer Darrell , Keener Brett , Snyder DJ , Ezeldin Saiff
Published: June 2014

The Permian Basin is one of the top five resource plays in the United States and consists of a number of stacked pay zones. Two of these formations, the Wolfcamp shale and Bone Spring (Wolfbone), together deliver a pay zone thickness of 1,000 to 1,500 ft. They are made up of several different layers of organic rich shales intermingled with sandstone and siltstone. Horizontal completions in the shales are just beginning and have yet to be proven; however, operators are successfully exploiting the reserves through vertical wells.

While a mature exploration area, the completion of the thick shale intervals is a new target formation. To date, two vertical completion methods have been utilized to gain access to hydrocarbons: open hole multistage systems (OHMS) and the conventional cemented liner, "plug and perf" (CLPP) method. This paper compares 30-, 60-, and 90-day production results from 12 vertical wells in Reeves County, Texas completed with OHMS systems and 44 offset wells completed with the CLPP method. The system details, fracture methods used, as well as the cost and operational differences are discussed.

By comparing these two methods, this paper highlights OHMS as a long-term solution for operators completing vertical wells in stacked pay. The production, operation and cost comparisons of the two completion methods will provide theoretical and practical arguments to assist in designing a completion. The results of this study contribute to the technical conversation of how to economically produce a vertical well.
Reducing Proppant Flowback From Fractures: Factors Affecting the Maximum Flowback Rate
Authors: Shor Roman J. , Sharma Mukul M.
Published: June 2014

Proppant flowback under confining pressures is not well understood and difficult to reproduce in a laboratory setting. Improper management of proppant flowback leads to flow restrictions near the well bore, poor fracture conductivity and costly production equipment damage. A simple, scalable model is developed using a discrete element method (DEM) particle simulator, to simulate representative cubic volumes consisting of fracture openings, fracture walls and the confining formation. The effects of fracture width, confining stress, fluid flow velocity and proppant cohesion are studied for a variety of conditions. Fracture width is found to be dependent on confining stress and fluid flow velocity while proppant production is also dependent on cohesion. Three regimes are observed, with complete fracture evacuation occurring at high flow rates and low confining stresses, fully packed fractures occurring at high confining stresses and open but mostly evacuated fractures occurring inbetween. From these observations, a recommended flowback rate can be estimated for a given set of conditions. A slow and controlled well flowback is recommended to improve proppant pack stability. The rate ramp-up time is dependent on the leak-off coefficient.
Cement Sheath Durability: Increasing Cement Sheath Integrity to Reduce Gas Migration in the Marcellus Shale Play
Authors: McDaniel Jessica , Watters Larry , Shadravan Arash
Published: June 2014

This study examines the effects of drilling, completion, and production operations and their associated cyclic stresses on a cement sheath. The operations performed after cement placement can damage cement sheath integrity and bond with the casing or formation resulting in loss of zonal isolation and sustained casing pressure often requiring remediation and reducing productivity.

This paper describes evaluation of cement sheath failure resulting from cyclic stresses experienced while drilling, fracturing, and producing shale gas wells and showcases optimization of cement systems used for Marcellus shale play intermediate casing strings. This study correlates the durability of each cement system with mechanical properties of the cements to determine each system's ability to resist failure under cyclic stresses. Two different cement compositions were used to cement intermediate casings on a number of wells. Both had similar performance properties and were designed to prevent gas migration following cementing. Wells cemented with one of the blends experienced a higher incidence of seal failure as evidenced by sustained casing pressure. In laboratory stress endurance testing, each cement system failed at a specific quantified magnitude of cumulative energy input. The results show a higher maximum endurance for the more durable cement, which also exhibits the higher field success rate. The fatigue endurance limit gives an approximation of the stress magnitude that a cement composition can withstand. Correlating laboratory endurance measurements and mechanical properties of the cement systems to field performance further quantifies the mechanical properties needed to optimize zonal isolation.

U.S. shale gas production is a major component in the future of U. S. energy supply. As such, there is focus on the drilling and production of U.S. shale plays. This study takes measured look at annular seal failure and lays the ground work to calibrate it to actual field results allowing operators and service companies to select more durable cement systems. Results from this study can ultimately decrease time and funds spent repairing compromised cement seals. Furthermore, improved seal performance equates to improved well performance with lessened environmental risk and impact.
Addressing UBO and MPD Challenges with Wired Drill Pipe Telemetry
Authors: Pixton David S. , Shishavan Reza Asgharzadeh , Perez Hector D. , Hedengren John D. , Craig Andrew
Published: June 2014

Wired drill pipe (WDP) telemetry has been used in over 100 wells worldwide to create a drillstring network that provides high bandwidth communications between tools deployed in the wellbore and the surface. When applied to managed pressure drilling (MPD) and underbalanced operations (UBO), wired drill pipe offers substantial benefits. Because of its independence from fluid flow, it gives visibility to downhole conditions where never before possible, including environments where traditional telemetry methods are not supported, and time intervals where pumps are not operating. Similarly, memory-quality data can be provided real-time from measurement tools located in the bottom hole assembly (BHA) as well as at points along the drillstring. Specific case studies and lessons learned from using wired drill pipe in the underbalanced and managed pressure drilling environments are summarized, as are recent enhancements to the wired drill pipe system, and their impact on extending the operating envelope and reliability of wired drill pipe.

Methods for leveraging the increased quantity and quality of real-time data to improve the drilling process are important if the highest value is to be obtained from high-speed telemetry technology. To this end a novel automated borehole pressure (BHP) control system with predictive technology has been designed. A preliminary UBO case study is used to assess the performance of this controller during different drilling events, including a drill pipe connection procedure and an unexpected gas influx. While making a connection, the controller maintains tight pressure control and may enable efficiency improvements by allowing faster trip speeds, when offered as part of an automation system. For the gas influx case, the ability of the controller to properly control the influx is shown to be dependent on low latency communications, such as that provided by WDP. This controller offers a substantial decrease in time required to control influx events as compared to manual methods and earlier controllers.

A nonlinear model predictive controller and a nonlinear estimator are used in the automation study. Information available from multiple sensors arrayed in a WDP system was found to be very useful in model parameter estimation, including friction factor and annular fluid density.

Proper application of WDP technology to challenges experienced in the UBO/MPD environment can yield more cost effective and successful deployment of these methods, further improving the value UBO/MPD technology can provide. Future work will included continued development of the control system to more fully capture the value of wired pipe technology.
The First Application of Whole Process Underbalanced Drilling in Ultradeep Horizontal Well in Tarim Oilfield
Authors: Xueqing Teng , Pei Yang , Ning Li , Chengxin Yang , Yan Jin , Yunhu Lu , Bo Zhou , Xiaoliang Wang , Feng Zhang , Tao Zhang , Xiaohong Zhou
Published: June 2014

In Tarim Oilfield the Ordovician carbonate reservoirs develop lots of cracks and caves. The formation pressure is very low(>6000m, less than65MPa), leading to the narrow mud weight window(MWW) problem. Serious lost circulation and reservoir damaged was encountered when we use the traditional overbalanced drilling method, also the oil and gas reservoirs cannot be discovered timely, therefore whole process underbalanced drilling technique must be employed. The underbalanced drilling technique has been applied in the narrow MWW formations, but there’s no report of the whole process underbalanced drilling technique (including the underbalanced drilling, underbalanced tripping, underbalanced logging and underbalanced completions, etc.) being used in such formations in China.

Based on the analysis of difficulties encountered by traditional overbalanced drilling methods such as serious lost circulation, horizontal wells cannot reach the design sections, serious damage to the reservoir, the feasibility analysis and construction plan of the whole process underbalanced drilling in Y block is proposed. The first whole process underbalanced drilling of horizontal wells in Tarim Oilfield was conducted and completed. Finally 6 layers of reservoirs are being discovered (2 layers are not discovered by the prospect well), the cumulative thickness is 16m, which increases the rate of oil and gas discoveries.

Compared with the on-site well, the efficiency of drilling is greatly improved, no lost circulation and no complex situation encountered; the ROP increases 74% compared to the adjacent wells in the same layers. It also created the deepest drilling depth record using the inflatable mud in China. The whole process underbalanced drilling program formed in this thesis provide an effective drilling and completion mode for the Y block in Tarim Oilfield, which greatly increased the rate of oil and gas discoveries, and reduce non-productive time, while this method has some reference significance for the low-pressure reservoir development in the other parts of the world.
Fit-for-Purpose Modeling for Automation of Underbalanced Drilling Operations
Authors: Aarsnes Ulf Jakob , Di Melgio Florent , Aamo Ole Morten , Kaasa Glenn-Ole
Published: June 2014

Automation has the potential to improve efficiency, precision, and safety of pressure and flow control during underbalanced drilling (UBD). In addition, advanced estimation theory can be used to extract more information from existing measurements to increase knowledge of the downhole conditions during operation.

An essential part of an advanced (model based) pressure control system is the hydraulic model. Even with high-bandwidth distributed downhole measurements, a calibrated hydraulic model is required to ensure robustness, e.g. to sensor loss, and obtain real time estimates of unmeasured quantities and reservoir characteristics.

In UBD operations, in contrast to Managed-Pressure-Drilling (MPD) operations, the flow in the annulus is inherently a multiphase gas liquid flow, which severely complicates the modelling. Much effort has been put into developing multiphase flow models, however, to date; most of these are very complex, requires extensive configuration and are not well suited for real-time applications. Consequently, a major gap with respect to automation of UBD is the lack of a fit-for-purpose model capable of reproducing the main dynamics of the multiphase flow in the annulus, while being sufficiently robust and suitable for real-time applications.

In this work, we present recent advances on the development of a simplified fit-for-purpose model of the distributed gas-liquid dynamics, suited for advanced control of UBD operations. Using an automated calibration procedure, the model is shown to retain accuracy in a realistic case study. It is also shown that its reduced complexity enables real time coupling with measurements to obtain estimates of unmeasured quantities such as gas distribution and perform reservoir characterization.
MudCap Drilling: New Variations, Drivers, Limitations, and Lessons Learned – Case Histories
Authors: Goodwin Bob , Nauduri Sagar , Medley George
Published: June 2014

MudCap Drilling (MCD), a major variation of Managed Pressure Drilling (MPD), is a key drilling technology that can help drill zones with total lost circulation otherwise not drillable using conventional methods.

Multiple variations of MCD have evolved, including: a) Floating MudCap Drilling (FMCD), b) Pressurized MudCap Drilling (PMCD), and c) Dynamic MudCap Drilling (DMCD). Case histories serve as a guide to understand the variations and their application during drilling. Drivers and limitations for each of the MCD variants are addressed, as are engineering, planning and training needs associated with each variant.

Additionally, an in-depth case history of a recent five-well MCD program in the Texas panhandle Granite Wash formation is presented, describing the process the operator employed to investigate, select, design and deploy Dynamic (constant injection) MudCap Drilling. The case history describes the pros and cons and the criteria justifying MCD as the preferred solution, including the prerequisites to successful deployment of MCD. The paper describes the design process and equipment deployed, highlights the integration of conventional services with the unconventional, and presents challenges, highlights and lessons learned from these drilling activities.
Impact of Experimental Studies on Unconventional Reservoir Mechanisms
Authors: Rosen Richard , Mickelson William , Sharf-Aldin Munir , Kurtoglu Basak , Kosanke Tobi , Paiangle Meghana , Patterson Robert , Mir Faraz , Narasimhan Santhosh , Amini Amir
Published: June 2014

Novel apparatuses have been developed to measure permeability using steady- and unsteady- state methods on nano-Darcy (nD) shale (source rock) using intact cylindrical samples returned to isostatic effective reservoir stress. The steady-state method uses a high pressure dual pump system using supercritical fluids. High pressure supercritical fluids have low viscosity and low compressibility. The effect of low viscosity fluid results in measureable flow rates and the effect of low compressibility fluid minimize unsteady-state transients thereby reducing the amount of time required to achieve steady-state equilibrium. Specially designed and configured pump systems, seals and sleeves reduce leak rates to allow Darcy flow and permeability determination below 1 nD. The unsteady-state method is based upon standard designs but is optimized for small pore volume. In this report we present a summary of over 200 such permeability measurements. Permeability is observed to be dependent on geologic parameters, such as, texture and composition. Stress dependence, with hysteresis, is observed for samples with and without fractures as is rate dependent skin (Forchheimer). An interpretation model where matrix storage feeds a progressively larger fracture network provides a logical basis for a dual-porosity reservoir simulation model. This dual-porosity model is used to understand the influence of reservoir production parameters, such as choke management.

An additional observed effect is possibly related to pore collapse and disconnection. Pores associated with organic matter are softer than the surrounding mineral matrix. If these pores have a sufficiently small throat diameter, it is not hard to envision that they easily compact and close under increased effective stress as the result of reservoir depletion. Therefore, organic pore systems can become isolated unlike those of a sponge where fluids remain in pressure communication at all times. The implication of such pore isolation phenomena is that fluid material balance is not preserved during production and can contribute to large production decline rates.
Simulation of Liquid-Rich Shale Gas Reservoirs with Heavy Hydrocarbon Fraction Desorption
Authors: Haghshenas B. , Soroush M. , Brohi I. , Clarkson C. R.
Published: June 2014

Liquid-rich shale (LRS) gas reservoirs have gained increasing attention in recent years. The Eagleford Shale in the U.S. and the Duvernay Shale in Canada are examples of liquid-rich shale gas plays which are being exploited to produce more profitable liquid hydrocarbons with natural gas. These reservoirs may store liquid hydrocarbons in liquid or vapor state, as with gas condensate systems. Further, shale gas reservoirs may contain significant volumes of organic matter, which stores gas (and liquid hydrocarbons) in the adsorbed state.

There have been several historical simulation studies investigating the impact of various reservoir and fluid properties on fluid production and recovery from LRS, however none have investigated the importance of desorption. Adsorption has previously been suggested to be an important storage mechanism in organic-rich shales, particularly for heavy hydrocarbon fractions. Matrix pore configuration and associated connectivity has also been previously demonstrated to be an important control on gas production from shale gas reservoirs, but the impact on condensate production has not been investigated for LRS.

In this work, the impact of heavy hydrocarbon fraction desorption, pore configuration and connectivity, fluid composition and operating conditions (flowing bottomhole pressure) on LRS production is investigated using a commercial simulator. We use PVT data from previous studies to develop a compositional simulation model analog of an LRS reservoir. Hydrocarbon component adsorption amounts are modeled using the Langmuir isotherm. Different combinations of organic and inorganic matter and fracture porosity, and their connectivity, are also assigned in the simulation cases.

Simulation sensitivities demonstrate that desorption can contribute significantly to condensate production, depending on fluid composition and pore connectivity. In cases where liquid-fraction adsorption contributes significantly to in-place volume, we recommend injection of light end gases to mitigate condensate blockage. This will be studied in detail in future work.
Are the Laboratory Measurements of Proppant Crush Resistance Unrealistically Low?
Authors: Getty J. , Bulau C. R.
Published: June 2014

Crush resistance has become a key, perhaps even the singular, parameter used in selection of proppant for hydraulic fracture stimulation operations. The API Recommended Practice 19C (RP19C)—which is identical to the ISO13503-2 standard1— lays out procedures intended to produce repeatable results.

However, repeated measurements in the same lab are inherently noisy and lab-to-lab results often produce crush strength differences of as much as 2k psi. The RP19C is intended to produce reliable and repeatable proppant crush results. However, results from this study show that when compared to other possible methods, the RP19C procedure both increases the noise in the measurement and lowers the crush rating. We describe a series of experiments which provide statistically reliable insight on the effect that loading and handling of the crush cell has on the crush results. The data allow a comparison of five loading methods: the standard RP19C method; the Pluviator; a jarred-cell approach to test the RP19C admonition to avoid "agitating" the cell; a vibratory settling method and a new mechanical loader, designed by the authors. Because two of the loading methods produce statistically significant improvements in crush resistance (specifically the vibratory method and the new mechanical loading device) and because the primary effect appears to be tied to maximizing the packing density, we conclude that the in-situ crush resistance of these proppants may be higher than estimated by the standard test.
Induced Fracture Complexity, When is it Really Required in Unconventional Reservoir Stimulation?
Authors: Sierra Leopoldo , Mayerhofer Mike
Published: June 2014

Induced fracture complexity maximization, in addition to the primary hydraulic fracture, to improve the recovery efficiency or productivity of gas or liquids in unconventional reservoirs has been accepted and fully implemented by the industry. As a result, stimulation fluids and/or completion strategies have been engineered to maximize induced fracture complexity in many unconventional reservoirs. In typical horizontal completions, induced fracture complexity with sustained conductivity is clearly beneficial for the productivity of nanodarcy (nd) shales, although this might not be a requirement for all unconventional reservoirs, especially tight sands.

In some unconventional reservoirs, operators have observed similar productivity in wells with predominantly planar fractures compared to wells that appear to have more complex fractures. This paper, supported by extensive reservoir simulations, aims to develop criteria for situations in which induced fracture complexity and sustained conductivity are required and when they are not. The simulations include a reservoir permeability range of 10 nd to 0.001 md and a complexity or secondary fracture conductivity of 1 to 5 md-ft. The results show that the fracture complexity and sustained conductivity are generally important for reservoir permeabilities lower than 100 nd for gas and 500 nd for liquid-producing reservoirs.

Based on these results, an optimized completion strategy is suggested to maximize the productivity or recovery factor (RF) in unconventional gas- and liquid-producing reservoirs.