bluuebunny/crossref_metadata_2025 huggingface dataset:
First Intelligent Well Completion in the Troll Field Enables Feed-Through Zonal Isolation: A Case History
Authors: Dahle Bjørn Olav , Smith Peter E. , Gjelstad Geir , Solhaug Kristian
Published: October 2012

Statoil operates the Troll Field in the Norwegian Sector of the North Sea and wished to run a deep sidetrack from the mother bore in a multilateral well that would exit through the 10-3/4-in. liner in the reservoir. The plan would have to address several new challenges, including an intelligent completion that would offer zonal isolation for four zones and dual pressure and temperature for all oil zones; these were not usual requirements for the standard multilateral wells in the field.

Statoil had evaluated several zonal-isolation methods, and based on previous experience, they decided to use swellable packer technology. Since this would be the first intelligent-well completion in Troll field and the first ever for Statoil using feed-through swellable packers, a full scale test to qualify the technology was required. Swelling and differential-pressure tests were initiated using oil from the Troll field. Testing revealed that this type of completion actually would exceed the necessary requirements.

The lower completion was designed with 7-in. inflow-control-device (ICD) mesh screens and three openhole swellable packers to isolate the reservoir into three separate oil zones and to separate the gas cap. The inner completion string was designed with three dual gauges, three 3-1/2-in. feed-through swellable packers, three 3-1/2-in. hydraulic flow-control valves, and a hydraulically operated gas-lift valve below the production packer to allow natural gas lift.

The installation was performed from a semi-submersible rig without an HSE incident and ahead of plan. The well was put on production shortly thereafter, and zonal isolation was confirmed by selective closure of the flow-control valves. The paper will discuss the swellable packer design, qualification testing, planning, installation, and the results of this intelligent completion, which was the first in the Troll Field.
Information from a Downhole Dynamics Tool Provides Real-Time Answers for Optimization While Drilling 10,000 ft Laterals in the Middle Bakken Formation of the Williston Basin
Authors: Chrisman John , Orley Cole , Hood James , Stone Casey , Fleischhacker Curtis , Leopold Nathan , Taylor Richard
Published: October 2012

Economically exploiting the Bakken reservoir of the Williston Basin requires long horizontal wellbores through the drilling zones which continually change from sandstone to siltstone to shale with hard calcite cementation. Changes of formation within the drilling zone have caused numerous drilling challenges by creating dynamics issues, resulting in vibration problems and bit/bottom hole assembly deflections. These, in turn, result in high local doglegs that lead to a loss of drilling efficiency.

Traditionally, a real-time downhole dynamics tool has been used occasionally within lower-cost drilling projects to accelerate learning about the downhole environment. This knowledge and real-time control of drilling parameters are essential. However, the value of these downhole tools may be underexploited, since they might not be considered economical for everyday use in the lower-cost drilling projects. Case history examples display the benefits due to the closer-to-the-bit steering control from bending moment and bending toolface data, and have made the use of this downhole dynamics tool a necessary choice.

This paper will expand on the challenges encountered while drilling the long lateral sections in the Williston Basin, and show how the use of real-time downhole dynamics information helped optimize the drilling effort by saving time and increasing the percentage of successful one-run laterals. Furthermore, the paper expands on the practical use of the directional information from bending moment and bending toolface close to the bit thus allowing the directional driller to make better real-time decisions on whether a wellbore correction is really needed. The paper is supported with over 30 months of field examples and results.
Kuparuk River Unit Field - The First 30 Years
Authors: Jensen Trond B , Little Laird , Melvin John , Reinbold Eric , Jamieson David , Shi Wen
Published: October 2012

This paper will review the history and current operations of the Kuparuk River Unit (KRU) field, the second largest field on the North Slope and one of the largest fields in the US. The field is a legacy asset in the ConocoPhillips portfolio with more than 6 BBO OOIP. The field came on line in December 1981 and has produced 2.25 BBO to date through water flood, immiscible water-alternating gas (IWAG) and miscible water-alternating-gas (MWAG) injections. Currently the field produces 90,000 bopd, 460,000 bwpd and 210 MMscf/d gas, and injects 570,000 bwpd and 160 MMscf/d miscible injectant.

Some of the recent challenges at KRU include: maintaining pressure support (water injection) through an aging infrastructure, development and use of fit-for-purpose simulation models to support field management decisions, estimation of facilities back-out from a complex multi-field system, and optimization of one of the largest MWAG EOR floods in the world. History and current status of the KRU field will be discussed.
Azimuthally Focused LWD Sonic Logging for Shear Wave Anisotropy Measurement and Borehole Imaging
Authors: Mickael Medhat , Barnett Craig , Diab Mohamed
Published: October 2012

An azimuthally focused LWD sonic tool has been developed to resolve shear wave anisotropy in fast formations, and provide borehole images of compressional and shear acoustic slowness. As the drillstring rotates, waveform measurements are recorded in 16 fixed-orientation azimuthal bins. The waveforms are processed to yield azimuthally oriented compressional and refracted shear slowness values.

Most shale reservoirs exhibit significant intrinsic anisotropy. Knowledge of the acoustic velocities and anisotropy ratio is vital for properly computing formation mechanical properties and modeling hydraulic fracturing performance, as well as for seismic processing and interpretation. Yet VTI shear wave anisotropy cannot be resolved from dipole measurements in vertical wells, and such data are rarely available from horizontal wellbores.

The LWD azimuthal sonic sensor has been successfully tested in horizontal shale reservoir wells in the northeastern U.S., where VTI shear wave anisotropy of 5 to 50 percent was clearly measured in the horizontal sections. Borehole images constructed from azimuthal shear slowness data provided a clear visual indication of the orientation and magnitude of the shear wave anisotropy, while compressional slowness borehole images compared well with conventional images from LWD azimuthal gamma ray and density tools, and can provide information on formation dip and the stratigraphic position of the horizontal wellbore.

Azimuthally focused LWD sonic measurements of compressional and anisotropic shear wave slowness provide new and valuable information from horizontal shale wells, supplying geomechanical data necessary for more informed hydraulic stimulation programs, as well as providing geophysicists with key anisotropy parameters and complementing data available from vertical wells to provide a complete three-dimensional compressional and shear velocity model.
Parameters Controlling Hydraulic Fracturing and Fracture Tip-Dominated Leakoff in Unconsolidated Sands
Authors: Hurt Robert S. , Germanovich Leonid N.
Published: October 2012

Hydraulic fracturing of unconsolidated materials has been a long-recognized technique to control sand production. This work describes the results of an experimental investigation on the dominant parameters of hydraulic fracturing in unconsolidated sands. The variables in this study, each varied by several orders of magnitude, are sample permeability, fluid rheology, remote stresses, and fluid injection rate. We have quantified the results of these experiments in terms of injection pressuretime history, fracture aperture, and leakoff thickness. Directly measuring the magnitude of fracture aperture and leakoff thickness is significant in hydraulic fracturing of unconsolidated materials to constrain modeling this process.

Laboratory observations presented here suggest that in our experiments, the leakoff process is primarily confined to the tip of the fracture and that leakoff precedes fracture propagation. This may be the first direct experimental observation of the dominance of the leakoff process in the tip region of a propagating fracture in cohesionless materials.

Our experimental results also suggest that the primary factor affecting peak (initiation) pressure and fracture aperture is the magnitude of the confining stresses. However, the morphology of the fracture (and fluid leakoff zone) changes significantly not only with stresses, but also with other parameters such as flow rate, fluid rheology, and sample permeability. Typical features of the observed fractures are multiple offshoots, a blunt fracture tip, leakoff primarily confined to the fracture tip region, and material shear banding. Dimensional analysis of the recorded experimental data results in the power-law dependence of the peak injection pressures on the dominant experimental parameters.

The results presented here quantify the effect of the experimental parameters on injection pressures, magnitude of leakoff, and fracture aperture. This is a significant development and our data set is consistent with available field observations, also discussed in this work.
The Braess Paradox and its Impact on Natural Gas Network Performance
Authors: Ayala H. , Luis F. , Blumsack Seth
Published: October 2012

Steady increases in natural gas transportation volumes have prompted operators to reevaluate the performance of the existing gas pipeline infrastructure. In order to accomplish an increased transportation capacity, conventional wisdom dictates that adding an additional link or a pipe leg in a gas transportation network should enhance its ability to transport gas. Several decades ago, however, Dietrich Braess challenged this traditional understanding for traffic networks. Braess demonstrated that adding extra capacity could actually lead to reduced network efficiency, congestion, and increased travel times for all drivers in the network (the so-called "Braess Paradox"). The study of such counter-intuitive effects, and the quantification of their impact, becomes a significant priority when a comprehensive optimization of the transportation capacity of operating gas network infrastructures is undertaken. Corroborating the existence of paradoxical effects in gas networks could lead to a significant shift in how network capacity enhancements are approached—challenging the conventional view that improving network performance is a matter of increasing network capacity. In this study, we examine the occurrence of Braess’ Paradox in natural gas transportation networks, its impact and potential consequences. We show that paradoxical effects do exist in natural gas transportation networks and derive conditions where it can be expected. We discuss scenarios that can mask the effect and provide analytical developments that may guide the identification of paradoxical effects in larger scale networks.
Shale Gas Hydraulic Flow Unit Identification Based on SEM-FIB Tomography
Authors: Zhang Hao , Bai Baojun , Song Kai , Elgmati Malek
Published: October 2012

Shale gas reservoir developments have steadily increased over the past few years throughout North America. A significant amount of the produced gas in shales is stored in complex submicron pore structures. The absence of an intensive hydraulic flow unit (HFU) model for these shale gas source rocks makes the prediction of economic gas productivity and hydraulic fracturing risky. Therefore, understanding of pore size distribution, permeability, pore connectivity, and other petrophysical properties is crucial for accurate performance prediction and effective reservoir management. This study utilizes the dualbeam (SEM-FIB) instrument for shale gas tomography. The reconstructed 3D sub-micron pore model provides insights into the petrophysical properties of shale gas, including pore size distribution and porosity. These properties were used to define the shale gas hydraulic unit and permeability. The identified flow units were able to fit into existing flow unit models for unconventional reservoirs. The comparison between the proposed method and mercury injection capillary measurements (MICP) revealed similar data range however MICP method tends to slightly overestimate the flow unit. Flow simulation based on 3D Stokes equation using image segmentation was performed and consistent permeability value was found compared to the estimation in SEM-FIB tomography. However, the permeability simulation results tend to underestimate the permeability value in reality. A case example from Utica shale illustrated the use of this approach.
Production Decline Analysis of Horizontal Wells Intersecting Multiple Transverse Vertical Hydraulic Fractures in Low-Permeability Shale Reservoirs
Authors: Poe Jr Bobby D. , Vacca Herman , Benjamin Art , Atwood W. Keith
Published: October 2012

This paper reports the development and application of production performance decline analysis techniques that are applicable for the characterization of the well and reservoir properties of low permeability fractured shale gas or oil reservoirs which are completed with horizontal wells intersected by multiple, transverse, finite-conductivity, vertical fractures. This type of well completion is now the most common type of completion technique that is currently being used to develop wells in low permeability fractured shale gas and oil reservoirs in North America.

It can be extremely difficult, if not technically impossible, to fully characterize the physical properties of unconventional reservoirs using conventional transient testing methods within a reasonable amount of time or at an acceptable cost. Instead, the production performance of these wells can be evaluated using transient production decline analysis techniques to determine the reservoir properties [permeability and estimated Stimulated Reservoir Volume (SRV)] and the well completion effectiveness [effective fracture half-length and conductivity] of the system.

The production decline analyses that have been developed in this work include both graphical production decline diagnostic analyses and history matching with a multiple-transverse fracture horizontal well transient solution using regression analysis techniques. Specialized diagnostic analyses have been developed for the intermediate flow regimes that are commonly exhibited in the transient performance of multiply-fractured horizontal wells to obtain estimates of or limits on the reservoir and well properties, which are then refined using nonlinear minimization techniques in a history matching analysis.

A field case history example is presented in this paper to demonstrate the application of the production performance analysis procedures. The evaluation of the reservoir properties and well completion effectiveness of multiply-fractured horizontal wells in fractured shale reservoirs using the transient production performance of these wells is of tremendous importance to the petroleum industry. It has been found that a combined production diagnostic - history matching analysis provides a reliable and accurate means of properly characterizing the properties and production performance of multiple-transverse- fractured horizontal wells in low permeability shale reservoirs.
Enhancing the Effectiveness of Long Horizontal Water Injection Wells with ICD/SSD Technology – Design, Simulation, and Installation
Authors: Kuck Marc , Holderman Luke , Brown Dan , Thornton Kim , Kuo Nicholas
Published: October 2012

Horizontal completions have continued to increase in length and complexity, which has made their design considerably more challenging for completion engineers. Eni Petroleum's Nikaitchuq Field in Alaska is a prime example of how the increases in wellbore length have affected the use of traditional technologies. Previously, these completions would use horizontal water injection to drive the horizontal producers; however, with the increased wellbore lengths, Eni Petroleum was facing challenges that were due to the completion criteria exceeding the capabilities of the traditional injection/production completion scenarios.

Nikaitchuq is a low pressure, low temperature, high-oil-viscosity reservoir in which Eni Petroleum must drill shallow wells with long lateral sections. This trajectory requires high torque completion equipment in order to assure that equipment will reach total depth (TD). With these extended horizontal lengths, delivering tools to depth and uniformly driving a cold viscous hydrocarbon is extremely difficult with the use of traditional technology.

An innovative solution was designed to meet these challenges. By coupling adjustable inflow control devices, sliding sleeve devices, and low-temperature water-swelling packers, Eni Petroleum was able to balance their injection profile without complex and costly equipment. Now, Eni is able to shut off individual injection zones in the event of reservoir formation breakdown that results in problems in injector/producer communication.

Using reservoir simulation software, the service company's new completion design can maximize productivity. The ICD's can be adjusted based on reservoir simulations, and the tools can be run to depth with the newly developed completion design. In the trial run by Eni, injection was brought on line, which enabled the swelling packers to reach full diameter. Because of this success, the completion plan was executed on additional wells in the field. This paper will discuss the completion used and how a simple, repeatable, completion design was capable of successfully overcoming a complex problem.
Production Array Logs in Bakken Horizontal Shale Play Reveal Unique Performance Based on Completion Technique
Authors: Boyer Robert , Findlay II Clyde , Suparman FNU , Sudija Jaja , Reyes Robert
Published: October 2012

ConocoPhillips drilled and completed three horizontal wells in the Bakken Shale, North Dakota in 2010; these wells contained between 33 and 40 stages. The lateral of each well consisted of a hybrid design using sliding sleeves in the toe- most half of the well and plugs/perforations for the heel-most half. Multiple completion techniques were pumped in an alternating pattern throughout the plug and perforation section of each well, and production array logs were deployed on coiled tubing in an attempt to determine fracture design best practices.

As one of the key parameters to horizontal well performance in the shale plays, fracture performance evaluation becomes the main objective. The flow contribution from each fracture stage was first determined from array production log interpretations in terms of the in-situ productivity index, which became the basis for fracture stage performance analysis. This paper also includes a discussion of the challenges associated with understanding the multiphase fluid flow behavior in horizontal wells.

The subsequent analysis of fracture performance was performed to relate the in-situ productivity index with other well parameters, such as well trajectory, fracture method, fluid and reservoir information around the well and the mud log information during drilling. Oil, gas, and water rates were generated for each stage and correlated to completion technique.

The final analysis was aimed to answer some of the questions about how certain fracture stages performed better in comparison to others. This analysis includes identifying parameters in favor of increasing fracture performance and defining the steps needed to deal with the challenges related to the geological nature of the field. The information from this integrated evaluation result was then used to define a better strategy to improve the well performance in the future drilling campaign and to optimize the commercial value of the field.
Reappraisal of the G Time Concept in Mini-Frac Analysis
Authors: Bachman R. C. , Walters D. A. , Hawkes R. A. , Toussaint Fabrice , Settari A.
Published: October 2012

Industry is currently using mini-frac analysis for the determination of fracture closure stress and after-closure reservoir properties. The foundation of all mini-frac analysis is the one dimensional Carter leak-off model, which leads directly to the concept of G Time. For 30+ years, G Time (or the G function) has played the dominant role for the determination of closure stress. The current norm uses combination G function and combination square root Δt plots for closure pressure determination. Each combination plot has three plotting functions associated with it. These combination plots also allow the identification of non-ideal behavior. Additionally, various log-log derivative techniques based on pressure transient analysis concepts have been developed to act as a guide for determining flow regimes and closure pressure. These PTA based techniques also allow the determination of after-closure flow regimes and properties. Concurrently, various specialized afterclosure plotting techniques have been developed for fracture/reservoir property determination.

Despite all these techniques, there remains ambiguity in performing mini-frac analysis. Part of the problem is that the recommended plots do not rigorously identify the various flow regimes that occur during a mini-frac fall-off. Mini-frac analysis requires a general theory that accounts for all of the actual observed flow regimes. A systematic approach based on pressure transient analysis (PTA) concepts has been developed to identify the various flow regimes (Carter leak-off being only one of them). The starting point is the Bourdet log-log derivative plot, accompanied by the primary pressure derivative (PPD) function. It will be shown that the PPD on its own has independent flow regime identification capabilities. Once specific flow regimes have been identified, specialized log-log plots can be constructed for further flow regime verification. New combination plots are then developed for each flow regime to further assist in closure pressure determination. The theory will first be developed and illustrated with various example problems.
Combined Uncertainty and History Matching Study of a Deepwater Turbidite Reservoir
Authors: Aggarwal Akshay , Du Song , King Michael J.
Published: October 2012

A textbook description of history matching could indicate that it is a process wherein changes are made to an initial geologic model of a reservoir, so that the predicted reservoir performance matches with the known production history. A practitioner recognizes that this is an overly simplistic description:

Does not recognize subsurface uncertainty and how we may explore this uncertainty with multiple geologic models. Offers no guidance on the requirements of spatial resolution, and how this choice may vary depending the stage of field life or reservoir processes, e.g., a pressure history match versus the modeling of a secondary or tertiary process. Offers no guidance on the nature of the geologic model: its characteristics, its level of detail, or its structure. Provides no description of the history matching process itself, nor the choices available to a practitioner.

We have been supplied with the historical field data for a deepwater turbidite reservoir, which is still under active development. We have used this reservoir to explore a number of history matching strategies. This project involved an integrated seismic to simulation study, wherein we interpreted the seismic data, assembled the geological information, performed petrophysical log evaluation and well test pressure transient analysis before creating the 3D geologic model.

In the matching process we examined the trade-off between exploring a wide number of models versus calibrating a single model. We examined the scale at which the geologic model was constructed, and how the scale of simulation could be determined. Finally, we studied both the large discrete steps in the process, and the smaller local "assisted" parameter calibration. The results provide general guidance on workflow sequence, guidance on model selection, and guidance on the scales of static and dynamic modeling. We expect many of these conclusions to have general utility, not restricted to this specific study.
The Value of Assessing Uncertainty
Authors: McVay Duane A. , Dossary Mubarak N.
Published: October 2012

Despite the perception of lucrative earnings in the oil industry, various authors have noted that industry performance is routinely below expectations. For example, Brashear et al. (2001) noted that average return was around 7% in the 1990s, despite using typical project hurdle rates of at least 15%. The underperformance is generally attributed to poor project evaluation and selection due to chronic bias. While a number of authors have investigated cognitive biases in oil and gas project evaluation, there have been few quantitative studies of the impact of biases on economic performance. We believe that incomplete investigation and possible underestimation of the impact of biases in project evaluation and selection are at least partially responsible for persistence of these biases.

The objectives of our work were to determine quantitatively the value of assessing uncertainty or, alternatively, the cost of underestimating uncertainty. In this paper we present a new framework for assessing the monetary impact of overconfidence bias and directional bias (i.e., optimism or pessimism) on portfolio performance. For moderate amounts of overconfidence and optimism, expected disappointment was 30-35% of estimated NPV for the industry portfolios and optimization cases we analyzed. Greater degrees of overconfidence and optimism resulted in expected disappointments approaching 100% of estimated NPV. Comparison of modeling results with industry performance in the 1990s indicates that these greater degrees of overconfidence and optimism have been experienced in the industry.

The value of reliably quantifying uncertainty is reducing or eliminating expected disappointment (having realized NPV substantially less than estimated NPV) and expected decision error (selecting the wrong projects). Expected disappointment and decision error can be reduced by focusing primarily on elimination of overconfidence; other biases are taken care of in the process. Elimination of expected disappointment will improve industry performance overall to the extent that superior projects are available and better quantification of uncertainty allows identification of these superior projects.
Examining the Effect of Cemented Natural Fractures on Hydraulic Fracture Propagation in Hydrostone Block Experiments
Authors: Bahorich B. , Olson J. E. , Holder J.
Published: October 2012

Micro seismic data and coring studies suggest that hydraulic fractures interact heavily with natural fractures creating complex fracture networks in naturally fractured reservoirs such as the Barnett shale, the Eagle Ford shale, and the Marcellus shale. However, since direct observations of subsurface hydraulic fracture geometries are incomplete or nonexistent, we look to properly scaled experimental research and computer modeling based on realistic assumptions to help us understand fracture intersection geometries. Most experimental analysis of this problem has focused on natural fractures with frictional interfaces. However, core observations from the Barnett and other shale plays suggest that natural fractures are largely cemented. To examine hydraulic fracture interactions with cemented natural fractures, we performed 9 hydraulic fracturing experiments in gypsum cement blocks that contained embedded planar glass, sandstone, and plaster discontinuities which acted as proxies for cemented natural fractures.

There were three main fracture intersection geometries observed in our experimental program. 1) A hydraulic fracture is diverted into a different propagation path(s) by a natural fracture. 2) A taller hydraulic fracture bypasses a shorter natural fracture by propagating around it via height growth while also separating the weakly bonded interface between the natural fracture and the host rock. 3) A hydraulic fracture bypasses a natural fracture and also diverts down it to form separate fractures. The three main factors that seemed to have the strongest influence on fracture intersection geometry were the angle of intersection, the ratio of hydraulic fracture height to natural fracture height, and the differential stress.

Simply put, the most significant finding of this research is that fracture intersection geometries are complex. Our results show that bypass, separation of weakly bonded interfaces, diversion, and mixed mode propagation are likely in hydraulic fracture intersections with cemented natural fractures. The impact of this finding is that we need fully 3D computer models capable of accounting for bypass and mixed mode I-III fracture propagation in order to realistically simulate subsurface hydraulic fracture geometries.
Reliable Completion Systems for Gas Migration Prevention
Authors: Pleasants Charles W. , Joseph Basil J. , Farrar Amy L.
Published: October 2012

Long String completion systems will be presented for prevention of gas migration composed of an annular casing packer with remote-set technology activated by a cementing wiper plug (CWP) with a magnetic array or an acoustic wave generator. Proven and reliable zero-extrusion gap element technology provides a gas-tight annular seal while reliability is enhanced by eliminating all communication ports and potential leak paths between the packer inner diameter (ID) and casing annulus.

There are three main benefits of these systems. They provide a reliable mechanical barrier to "flow after cementing" which can result in a significant financial impact to the operators and their service providers. They reduce / eliminate issues with annular casing pressure (ACP) and sustained casing pressure (SCP). They also provide a permanent seal between casing strings, reducing the risks of costly plug and abandonment (P&A) operations.

During cementing operations the packer is activated by the CWP. Downhole sensors detect the magnetic field generated by the CWP and initiate the setting sequence of the packing element. Another system employs an acoustic wave generator at the rig floor to initiate the setting sequence in shallow-depth applications. An optional contingency setting sequence can be programmed prior to deployment and can be deactivated remotely if required. Design and qualification of these systems will be discussed along with available field installation data. Three systems are currently awaiting field trials.

Industry standards are focused on reducing annular flow prior to, during, and after completion of primary cement jobs. While these changes will improve annular isolation, conventional cementing contains fundamental limitations that complicate control of shallow gas hazards and water flows. The US Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) has thus identified "flow after cementing" and SCP as potential hazards. The above completion systems will help alleviate these concerns. It is noted as of October-1-2012, BOEMRE has been replaced by the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE).
Impact of Matrix Block Size on Oil Recovery Response Using Surfactants in Fractured Carbonates
Authors: Goudarzi Ali , Delshad Mojdeh , Mohanty Kishore K. , Sepehrnoori Kamy
Published: October 2012

Oil recovery from fractured carbonate reservoirs by water flooding is often inefficient due to the commonly oil-wet nature of these rocks and the lack of sufficient spontaneous capillary imbibition driving force to push oil out from the matrix to the fracture network. Chemical processes such as surfactant/alkali-induced wettability alteration and interfacial tension (IFT) reduction have shown great potential to reduce the residual oil saturation in matrix blocks, leading to significant incremental oil recovery (IOR). However, the IOR response time is the most crucial decision factor in field projects. The magnitude and time efficiency of recovery depend on the degree of wettability alteration and IFT reduction, the nature and density of fracture network, and the dimensions of matrix blocks.

Oil recovery experiments were performed for the same matrix rock and chemical formulation, but for different sized cores to gain a better understanding of the time dependence of the recovery process. The measured oil recoveries were history-matched. The simulation models were then used to predict the recovery response times for larger cores. The controlled and systematic laboratory measurements for several core sizes helped in developing dimensionless scaling groups to aid in understanding the time dependence and upscaling of laboratory results to field-scale applications.

This finding is significant as it illustrates the extent of wettability alteration and IFT reduction needed in fractured reservoirs. Laboratory measurements and simulation work substantiate the validity and the range of applicability of upscaled procedures, and indicate the importance of viscous and buoyancy forces in larger field cases. The results of this work will be useful for the design of future field projects.
Experience with Fiberglass GRE Lined Carbon Steel Tubular for Corrosion Protection for Oil Production Applications
Authors: Sharif Qamar J. , Esmail Omar J. , Radhakrishnan Gokulnath , Simpson John A. , Bremner Martin R.
Published: October 2012

Saudi Aramco experienced serious corrosion problems in oil production tubing in one offshore field, attributed to presence of H2S, CO2 and varying levels of water cut.

In early 2002, the company installed on trial test basis Glass Reinforced Epoxy (GRE) or commonly known as fiberglass lined carbon steel tubing in three wells. The fiberglass lining was installed to provide a corrosion barrier to protect the steel tubing from internal corrosion. As far the technology, the fiberglass lining or sleeve is carried out joint by joint by inserting a solid fiberglass tube into the low cost carbon steel tubing and cement is pumped into the narrow annulus between the fiberglass liner and the carbon steel tubing. The connection area is protected by the combination of end flares and a corrosion barrier ring.

The company examined various methods to evaluate the performance of the fiberglass lined tubing, without having to pull out the tubing from the well as these wells are oil producers. After review of the evaluation options, it was decided to run a multi finger caliper to evaluate the condition of the fiberglass lining and check for any internal corrosion in the steel tubing. The log showed the fiberglass lining to be in good condition with no damage indicating that the steel tubing was protected from corrosion. The other two wells had no tubing leaks indicating the GRE lining is providing corrosion protection.

Based on successful trial test results, the company adopted the technology to protect tubing strings deployed in corrosive environments in oil producers, water injectors and water supply wells.

Field experience has shown that the use of fiberglass lined tubing is a low "life cycle cost" solution compared to other options. There has been no workover in these wells since installation. Today fiberglass lined tubing is applied in Saudi Aramco in high water cut oil producers, water injectors and combined water source and injection wells.

The paper shares the history of corrosion, challenges and lessons learned during the implementation of the solution, various performance assessment methods evaluated and the results and interpretation of the caliper log.
Wanted Dead or Live: Crude Cocktail Viscosity: A Pseudo-Component Method to Predict the Viscosity of Dead Oils, Live Oils, and Mixtures
Authors: Yarranton Harvey W. , van Dorp Johan J. , Verlaan Marco L. , Lastovka Vaclav
Published: October 2012

A broadly applicable methodology is presented to reliably predict crude oil liquid viscosity from only a gas chromatographic assay composition (C30+ is recommended). The viscosity model employs a Walther-type correlation of double log viscosity with log temperature to predict the viscosity of dead and live crude oils and mixtures. The model has three parameters: the slope and intercept of the Walther plot and a viscosibility factor to account for pressure effects. Simple mass based mixing rules are applied on these three parameters to obtain mixture viscosity. The three parameters were correlated to component molecular weight and therefore a gas chromatographic assay is the only required input apart from the temperature and pressure.

The methodology was developed from a Western Canadian dataset of two bitumens, one heavy oil, and one condensate, and then tested on an independent dataset of 10 conventional and heavy crude oils from the Gulf of Mexico, the Middle East, Asia, and Europe. The model provides un-tuned viscosity predictions within a factor of two of the measured values for dead and live crude oils ranging in viscosity from 0.5 to 500,000 mPa.s. A single multiplier is used to tune the model. Models tuned to dead oil data predict live oil viscosities and mixtures of oils with solvents to within 30% of the measured values. Models tuned to the viscosity at the saturation pressure predict the effect of temperature and pressure to within 20% of the measured values.

The method retains its accuracy when components are lumped into a few pseudo-components and is ideally suited for use in simulators for accurate liquid phase viscosity predictions over a wide range of compositions, pressures, and temperatures. It would be necessary to include the proposed mixing rules in numerical simulators. An additional advantage of the method is the reduction in viscosity measurements needed to construct an accurate viscosity model.
Thermal Performance Testing of a High-Temperature ESP Motor for SAGD Applications
Authors: Waldner Leon , Wonitoy Kelvin , Klaczek Wayne , Noonan Shauna
Published: October 2012

During 2012, BakerHughes, ConocoPhillips and Nexen Inc. continued their research partnership [Waldner 2011] with a new experimental test program focused on the thermal performance of Electric Submersible Pump (ESP) systems for Steam Assisted Gravity Drainage (SAGD) applications, which was completed in the high-temperature flow loop at C-FER Technologies.

Accurately monitoring the internal temperature of the ESP motor is a key consideration when trying to increase the operational longevity of an ESP system for any application; however, as the SAGD process develops, understanding this temperature profile has become more critical. This test program included several tests at various fluid temperatures and ESP operating conditions that helped determine the thermal performance of the ESP motor. Another unique aspect of this test program was the incorporation of two different temperature monitoring methods at approximately the same position on the internal and external base of the ESP motor: one internal probe positioned near the motor windings via a fiber optic sensor and one external skin temperature RTD positioned on the motor surface to monitor this important temperature differential.

This paper presents the equipment and instrumentation used, and demonstrates some of the more interesting test results, thus providing further insight into the thermal performance of this ESP motor under representative SAGD conditions between 220°C (428°F) and 250°C (482°F).
In-situ Measurement of Fracturing Parameters from Communication Between Horizontal Wells
Authors: Daneshy Ali , Pomeroy Mark
Published: October 2012

The study reported in this paper presents direct and in-situ measurement of critical fracture properties using analysis of downhole pressure data recorded in a horizontal well. The first well (Monitor Well) was fractured in multiple stages, produced, and later instrumented for downhole pressure measurement while a second (Active Well) was being fractured. Review of the pressure data from the Monitor Well showed intermittent communication between the two wells. Analysis of this data provides direct indications of in-situ fracture conductivity. Signatures of other non-intersecting fractures (shadowing) were also detected in the Monitor Well. This data is used for estimation of fracture orientation, length, and propagation pattern. Some of the results obtained from these measurements include;

Two types of communication were observed between wells connected via hydraulic fractures; a shadowing effect, and direct hydraulic communication Fracture conductivity was very high during fracture communication and then decreased rapidly with time as fractures closed. The connection between the two wellbores was entirely lost soon after pumping stopped. Fractures extended vertically from Three Forks into the Middle Bakken The fracture growth pattern in this case study can best be classified as off-balance with low to medium branching and shear fracturing.

Given the operational simplicity of these measurements and accuracy of its results, the technique is recommended as a tool for fracture diagnosis.
Flow Induced Vibration Of Subsea Gas Production Systems Caused By Choke Valves
Authors: Ligterink N. E. , de Groot R. , Gharaibah E. , Slot H. J.
Published: October 2012

In the design of subsea flow systems the integrity and reliability is paramount. As the equipment must be designed to operate at a large variety of conditions, inherent to the many processes, evaluation of the integrity is complex. Flow induced pulsations and vibrations can cause serious design and production problems, especially in subsea gas production systems. Mechanical vibrations can be induced by internal and external flow through a complex process that is affected by numerous factors such as the piping geometry, flow conditions and fluid properties.

Wellhead choke valves are commonly used to control the flow of fluids from the reservoir. During production, significant noise is produced by the flow as it passes through the choke. The noise is of broadband nature: it can be described by pressure pulsations with frequencies over a large range (1-20 kHz). The subsequent vibration levels can become significant when the pressure pulsations match with a certain acoustic or mechanical resonance mode of the production piping, and can lead to an increased risk of failure of nearby equipment.

The paper describes a method to examine the mechanical loads on nearby equipment due to the vibrations induced by the usage of a wellhead choke by the means of Computational Fluid Dynamics (CFD) simulations and Finite Element Modeling (FEM). Numerical experiments were performed on a generic piping system consisting of standard pipes and bends as well as a fictive ensemble of sensor block and choke valve to explore: 1) the acoustic eigenmodes of the piping, 2) the mechanical eigenmodes of the piping and equipment, and 3) the resulting mechanical loads on the subsea equipment.

It is shown that typical frequencies characteristic of noise related fatigue are such that the number of cycles, easily reaching 1010 within a few months, can be regarded as the primary source instead of the maximum stress levels. Some aspects are not considered in the current approach, such as the effect of the medium and the surrounding. These will lead to slightly lower cyclic stress estimates, and will therefore not invalidate the presented method as a worst case estimation of noise induced vibrational stresses.
Development and Practical Application of a Chemical Hazard Rating System
Authors: Hepburn Krista
Published: October 2012

In order to address the ambiguous nature of the popular terms "environmentally acceptable" and "low toxicity" as they relate to chemical technology, a number of hazard classification and assessment systems were researched. The need for a quantitative determination of the health, safety, and environmental (HSE) impact of well stimulation chemicals was identified, and a meaningful and robust scoring system was developed for that purpose. Discussion of the development of this Chemical Hazard Rating System will include an explanation of the hazards assessed, the classification method, and the scoring framework. Application of the rating system to improve the HSE profile of stimulation fluids was a priority. The system was used to rate the HSE impact of an acid spearhead additive blend frequently used prior to hydraulic fracturing treatments in the Eagle Ford formation in South Texas. Alternative candidate products were identified for use in a new acid spearhead additive blend, based on the HSE impact scores as well as performance testing results. Data from laboratory testing of the improved acid spearhead additive blend will be summarized and presented. The relative cost of the two blends will be discussed, as this project illustrates that contrary to common assumptions, improving the HSE impact of a blend does not necessarily result in significant cost increases. The blend was optimized for the Eagle Ford and implemented with great success in the field.
Rapid Digital Technology Roadmap Deployment in a Growing Unconventional Business
Authors: Sparks Charles J. , Hall Ben R.
Published: October 2012

Delivering useful production information to the right people at the right time can be a challenging proposition in the oil and gas industry. As XTO Energy has grown rapidly through acquisition and drill bit, close engagement between the IT and business organizations has been critical to effectively deliver flexible, scalable software platforms to support various business needs and workflows with rapid setup of new assets.

The result is a standardized yet flexible technology roadmap from the wellhead to the desktop integrated with business operations functionality demands that is as simple as possible, delivering information transparency and utility to the multiple end users including operations, production engineering, regulatory, production accounting, and management.

This paper reviews how XTO Energy has deployed and utilized technology to maximize flexibility in support of growth while providing a stable reliable digital technology platform to serve business requirements, and shares lessons learned.