bluuebunny/crossref_metadata_2025 huggingface dataset:
Unconventional Type Curves: Useful, or Sirens of Destruction?
Authors: Haskett William J.
Published: October 2011

Considerable faith is placed in Type Curves; Type Curves that are ultimately responsible for resource estimation, revenue generation, and value determination. We assume that they are valid representations of what will happen, but is this faith warranted?

In and of itself, a type curve is a purely deterministic forecast of a multi-dimensional uncertainty. To their credit, explorationists have recognized range-based volumetric assessments as providing significant advantage in both resource determination and downside risk mitigation for nearly two decades. Given that nearly two-thirds of the uncertainty in NPV for an unconventional opportunity is production profile based, it is vital to understand the true range in the production profile. Unfortunately, given the two dimensional aspect (both rate and time are uncertainties) of time series uncertainty and the scale up issue from individual well ranges, this is not as straightforward as it may seem.

Attempts at ranged type curves tend to be biased by center anchoring and unreliable P10-P90 estimates. Ranged type curves are often the "expected" curve factored up and down symmetrically (!). This typically does not reflect valid production behavior. Well life is often inappropriately anchored at 40 years, or even 60 years and the curve is back-calculated to one of the most unreliable elements... initial production. The free variable in the calculation becomes decline, yet we receive decline information early in the life of the well. We have no clear reason to anchor production curves to a set time. As such, time should be the calculated variable. Additionally, the expected type curve when replicated across an area of potential will not be a representative case that delivers the expected value of an opportunity.

Type curves can be useful, ranged type curves even more so. Stochastic assessment of production potential allows companies to validly assess the true potential of a project area. It enables prioritized learning plans and downside recognition. Individual profile iterations can be easily ranked using discounted present production (DPP), but a value context is greatly preferred. Valid curves enable a company to recognize if a project will be production- or cost-sensitive and efficiently allocate time, people, and capital, thus optimizing the factory phase of the project.

Assessments are made to support decisions. Assessments without a decision context are a waste of time.
A New and Improved Approach for Geological Dependency Evaluation for Multiple-Prospect Exploration
Authors: Rasheva Svitlana , Bratvold Reidar B
Published: October 2011

Geological properties are likely to be shared for different prospects in a common basin. If, for example, source rock is found in one location, this increases the chance of finding it in other locations. Other geological characteristics will have similar correlation structures. When developing a drilling plan, these correlations should be considered because they can affect the optimal drilling sequence.

Modeling and accounting for these dependencies pose a significant challenge. The strength and structure of the dependencies must be assessed and specified through the use of conditional probabilities or correlations. Even for a relatively simple exploration plan, the resulting decision tree may have hundreds or even thousands of endpoints.

The sequential exploration problem with geological dependence has been addressed by several authors in the past few years. In this paper we extend this work by (1) simplifying the structure and model of the problem through the use of Influence Diagrams (Bayesian Decision Networks) and (2) using stochastic reservoir models to assess the dependence structure and strength. We also illustrate how to use the Maximum Entropy principle to construct joint probabilities when we have incomplete information about the correlation structure. Using Bayesian Decision Networks informed by stochastic reservoir models simplifies the modeling of exploration plans with a realistic number of wells.

Applying well known geostatistical techniques to aid in the assessment of the geological dependence structure and strength makes the approach more accessible to geoscientists wanting to account for these dependencies in their plans. Similarly, using Bayesian Decision Networks with their relatively simple and transparent structure will better facilitate the understanding and communication of the impacts of dependencies on the exploration plan. Given the typical exploration well cost, an optimal exploration program will in most cases generate significant savings.
Modeling SAGD with a Black-Oil Proxy
Authors: Ghasemi M. , Whitson C. H.
Published: October 2011

This paper describes a new approach to model steam-assisted gravity drainage (SAGD) using an isothermal black-oil (BO) reservoir simulator. The oil viscosity reduction caused by heating in the actual SAGD process is emulated by a tuned saturated pseudo-oil viscosity relation where solution gas-oil ratio (Rs) is used as an "equivalent temperature variable". In the black-oil formulation: (1) fully saturated oil viscosity (μo*) at reservoir pressure equals μo that would be attained at steam-chamber temperature (T*) in the actual SAGD process; (2) initial oil viscosity (μoi) with initial Rs=0, represents initial oil viscosity at reservoir temperature; and (3) black-oil gas properties represent steam at T*.

Upon careful analysis of the SAGD process, one finds that oil flows only along a narrow zone along the outer edge of the steam chamber – "edge oil-flow zone". The temperature gradient within this narrow zone is perpendicular to the oil flow direction and is practically impossible to model with any precision because of the large temperature variation and dynamic steam chamber shape over time. The black-oil model solubility gradient also varies, analogous to temperature in a thermal model, from zero to fully-saturated (Rs*) with an associated drop in oil viscosity from μoi to μo*.

SAGD design requires many hundreds of runs to find operational conditions that maximize economic value – e.g. injector and producer location, rates, pattern spacing, and steam chamber temperature T*. The proposed black-oil proxy model runs up to 10 times faster than a thermal model, while maintaining similar performance behavior.

The proxy model saturated pseudo-oil viscosity μo(p) relation used is found by history matching a full-physics thermal model performance prediction of oil rate, BHFP, and cumulative oil for a 2D homogeneous model. We have found a single-constant μo(p) equation that yields a good match to thermal SAGD performance. The tuned pseudo-oil viscosity relation honors the measured initial reservoir and fully-heated (at T*) oil viscosities. Its dependence on Rs is not physical, but reflects the use of Rs as a transform variable for temperature, capturing the strong spatial variation of temperature and oil viscosity within the localized steam-oil boundary region where oil has been mobilized.

The pseudo-oil viscosity relation, defined by a single empirical best-fit constant n – for a given T* and set of thermal properties – appears to be applicable for a wide range of reservoir heterogeneity, injection and production rates, and well placement. Consequently, it should be possible to use the black-oil proxy model for SAGD optimization of T*, control rates, and well placement, at a fraction of the CPU cost. We also see the potential of using the black-oil proxy model for solvent-based SAGD, with the pseudo-oil viscosity model depending on both T* and solvent; thermal compositional modeling is yet-even slower and less suitable for optimization.
EOS and Viscosity Modeling for Highly Undersaturated Gulf of Mexico Reservoir Fluids
Authors: Larsen Jarle , Sørensen Henrik , Yang Tao , Pedersen Karen Schou
Published: October 2011

PVT and viscosity data are presented for fluids from a deep and highly undersaturated Gulf of Mexico reservoir with a pressure of around 150 MPa. The fluid compressibility is a key property when evaluating the reserves and the potential recovery from such reservoirs. A common equation of state (EOS) model valid for 5 reservoir fluids is presented for use with the volume corrected SRK cubic equation of state. The compressibility at reservoir pressure is matched well and so is multi stage separator data. That makes the common EOS model applicable for reservoir simulation studies as well as for flow and process simulation studies. Simulation results obtained with the cubic equation of state are compared with results obtained with the PC-SAFT equation of state. High pressure viscosity data is presented and matched well with the corresponding states viscosity model using the same critical component properties as used with the common EOS model. It was possible to tune up the Lohrenz-Bray-Clark viscosity correlation to match viscosities ranging from 0.001 to 0.030 Pa s.
A Universal Formulation for the Prediction of Capillary Pressure
Authors: Goda Hussam (Sam) , Behrenbruch Peter
Published: October 2011

Capillary pressure and associated relative permeability are special core analysis parameters which are vital in accurately describing fluid distributions and movement in porous media when two (or more) immiscible fluids are present. Conventionally, the determination of capillary pressure requires laboratory experiments, which are expensive and time consuming. Assuming that core material is available, typically a limited number of core plugs are considered for testing, often resulting in incomplete reservoir description. This situation then leads to motivation for developing mathematical capillary pressure models, as an alternative to adequately describing fluid behaviour in reservoirs.

The well known Carman-Kozeny (C-K) equation (Carman 1937; Kozeny 1927) is commonly used to model permeability as a function of other pore structure parameters. More recently parametric groups were established for the C-K equation, which are in regular use in reservoir characterisation. Specifically, the determination of flow zone units for the description of distinct (litho)facies is now widely used in linking fluid flow to geological descriptions. In this paper, a new and innovative deployment of the C-K equation is investigated to derive capillary pressure relationships.

The new mechanistic, drainage capillary pressure model uses the principle of "effective saturation", and is developed and validated with data sets from onshore and offshore Australian hydrocarbon basins, giving a good comparison with laboratory measurements and other established models. Most significantly, the new mechanistic formulation does not just fit capillary relationships but is able to predict drainage curves by knowing or assuming up to six properties: absolute permeability; effective porosity; irreducible water saturation; maximum capillary pressure, which may be related to a particular reservoir situation or laboratory standard; capillary entry pressure; and associated entry water saturation. The last two parameters are typically required for a higher permeability (or better quality) rock. Absolute permeability is incorporated indirectly. Furthermore, there is no requirement for correlation parameters or constants but the analysis determines two parameters which give a measure of heterogeneity of the sample being investigated.
A Novel Well Annular Barrier Solution Alternative to Swellable Casing Packers
Authors: Plessing Hans , Arnskov Michael Macdonald
Published: October 2011

Having safe effective annular barriers that can be used for annular isolation is the key for managing wells. This has traditionally been done by either cementing the annulus or through the use of swellable packers.

The use of cement as annular isolation usually is considered as the industry standard, however it is a complicated, time-consuming and expensive to deploy. Alternatives, such as polymer-based swellable packers, are usually less complicated to deploy, but the degradable polymers invoke a risk in the typically harsh environment of a well.

The approach presented is based on a solid metal expandable system developed for the applications where swellable external casing packers traditionally have been used. The well annular barrier provides long term robust and reliable zonal isolation in cemented or un-cemented wellbores and may be used in conjunction with casing as well as liners. It also provides higher differential pressure capacity and higher expansion ratio to running OD without compromising the inner diameter. Consequently it does not impair or restrict flow conditions and furthermore enables subsequent well maintenance to take place unhindered.

The paper presents the results of the development and testing of the new solid metal expandable system for external casing applications and discuss the rationality behind the technology as well as the experience gained.
Production Tubing Frac Pack: An Unconventional Multi-Zone Design with Significant Cost Savings
Authors: Patterson Richard , Ross Colby , Larpenter Mike
Published: October 2011

The conventional process of frac packing that was initiated in the early 1990s and revolutionized the industry is well documented in the literature (Meese, et. al., 1994, and Mullen, et. al., 1994). Frac packing provided sand control as well as stimulation in unconsolidated reservoirs, and it has played a key role in enhancing productivity and adding reserves to many wells. The results of frac packing in unconsolidated reservoirs have been so positive, and its acceptance so widespread, that today it is considered standard practice though operators have customized numerous variations of frac packing for specific types of applications. For all the completion processes for frac packing that have been developed to date, one common factor is that rig assist is usually required throughout the entire process, including the phase of fracing the well. Additionally, multizone stack packing completion systems have evolved so that it is common practice to stack completions to economize the high cost of rig service that is involved with intervention (Brannon, et. al, 1991, and Bennett, et. al, 1996).

This paper describes an innovative and more economical multi-zone frac packing design known as production tubing frac packing (PTFP), which was developed in 2009 in the Gulf of Mexico. The new design combines the steps of perforating, completion setting, and frac packing into a single trip. PTFP is in the initial phase of a learning curve but has already proven to be more economical and potentially to have a similar impact on the industry as both frac packing and stack packing zones. With PTFP, much of the completion phase is performed through the production tubing after the rig assist has been demobilized, with the biggest savings realized during the rigless frac phase. This paper will cover all phases of the PTFP completion technique and will discuss three case histories.
Application of Single Well Chemical Tracer Tests to Determine Remaining Oil Saturation in Deepwater Turbidite Reservoirs
Authors: DeZabala E. , Parekh B. , Solis H. , Choudhary M. , Armentrout L. , Carlisle C.
Published: October 2011

Remaining oil saturation (ROS) and waterflood residual oil saturation (Sorw) are key parameters for reservoir modeling and waterflood management in a group of heterogeneous deepwater turbidite reservoirs. A large amount of laboratory special core analysis (SCAL) data indicated high Sorw values and a large target potential target for chemical EOR (enhanced oil recovery). Available SCAL data was not considered reliable. Acquiring additional core was considered to be too costly and too risky due to the highly deviated well paths required for new wells. Single Well Chemical Tracer Tests (SWCTT's) in producing wells were the only viable alternative. This paper describes – to our knowledge – the first applications of SWCTT in a deepwater setting.

An early 2010 SWCTT showed ROS / Sorw to be much lower than expected but test interpretation was uncertain. The 1st SWCTT provided a valuable learning experience to improve test design and execution and to improve on significant logistical challenges in the deepwater setting. Using lessons learned we performed two additional SWCTT's in late 2010. The later SWCTT's included well integrity pre-tests and smaller completion intervals. Typical SWCTT volumes were ~5,000 bbl of seawater containing tracers with a depth of investigation of ~4 to 5 meters.

All three SWCTT's indicated low Sorw values, ranging from 0.05 to 0.20 with a nominal average of 0.15. Similar results from all three SWCTT's indicate that microscopic displacement efficiency is very good; eliminating the option of chemical EOR. The current field development plan is focused on improving volumetric sweep efficiency.

Properly designed and executed SWCTT's can be considered as large-scale "laboratory waterflood tests" at true reservoir conditions (e.g., live oil, wettability and stress history). Compared to conventional SCAL tests using small plug samples, SWCTT's see a much larger rock volume and avoid wettability alteration issues that plague modern cores taken with OBM (oil based mud). Though logistically challenging in deepwater, SWCTT's can be more cost- and time-effective than taking a new core.
The Practice and Evolution of Torque and Drag Reduction: Theory and Field Results
Authors: McCormick John E. , Chiu TzuFang
Published: October 2011

With the global trend moving toward drilling deep water wells, ultra-extended reach wells (u-ERW) and complex geometry wells, we can no longer ignore the drilling limitations caused by high torque and drag forces. Extreme torque and drag, especially unplanned, can be detrimental to drilling operations. Over the years, engineers have developed numerous ways to challenge the drilling limitations by reducing torque and drag forces in order to drill further and deeper. This paper attempts to describe the practices and the evolution of torque and drag reduction methods. The different torque and drag reduction methods that this paper focuses on are listed below.

Wellpath design Light weight string components Lubricants Hole cleaning Co-polymer beads Mechanical friction reduction tools Increased drill string and rig capability

In highly inclined wells, solutions to problematic torque and drag are essential in order to complete the drilling and completion operations. Because many restrictions are imposed by the drilling rig, top drive, wellpath and drilling components, engineers have came up with ways to reduce torque and drag while drilling. There are weight limitations that a rig can provide, especially in non-rotating operations such as slide drilling. If the compressive forces in the drill string are too high, bucking will occur. In an extended reach well (ERW), two common problems with torque are the friction resistance to drill string rotation and the make-up torque limitations. If the rotary torque is too high, torsional failure would result. Therefore, it is essential for engineers to accurately account for the torque and drag forces and attempt to reduce them in order to prohibit these scenarios from occurring. At the same time, it is the engineer's responsibility to ensure that we do not over-design to accommodate unnecessary needs.
Plastering Effect of Casing Drilling; A Qualitative Analysis of Pipe Size Contribution
Authors: Karimi Moji , Moellendick Eric , Holt Calvin
Published: October 2011

Casing Drilling is a process in which the well is drilled and cased simultaneously. The original purpose of developing this technology was to eliminate the Non-Productive Time (NPT) associated with tripping out drill pipe and running casing. However, during the early implementation of the technology other benefits were observed while drilling with the casing. In this study the authors explain how these benefits can be related to the larger diameter of the casing compared to drill pipe.

The Plastering Effect is an inherent and unique feature of Casing Drilling that strengthens the wellbore, prevents lost circulation, and mitigates formation damage. Plastering Effect augments the pressure containment of the wellbore by smearing the drilling cuttings and available PSD (Particle Size Distribution) into the formation face, hence sealing the pore spaces. This continuous process creates a low porosity, low permeability filter cake on the wellbore wall reducing or preventing losses to the formation and effectively widening the operating mud weight window.

In Casing Drilling operations the casing is used to drill the well so the (pipe size/hole size) ratio will be larger than the ratio when conventional drilling pipe is being used. This feature is a significant contributor creating the Plastering Effect. Casing dynamics is qualitatively compared to drill pipe. Pipe ontact angle and area, side force and momentum, and grinding effect, are analyzed to help understand how the benefits of the Plastering Effect are created and answer the question of why it happens in Casing Drilling and not in conventional drilling.

Casing Drilling has been used successfully in numerous difficult wells to drill through troublesome well sections which would not have been possible to drill with conventional drill pipe techniques. The Plastering Effect of Casing Drilling has been recognized as an enabling tool to overcome difficult drilling challenges. Therefore, understanding its mechanism is crucial to its successful application.
Numerical Modeling of Massive Sand Production
Authors: Wang Jianlin , Yale David , Dasari Ganesh
Published: October 2011

Primary production of heavy oils where significant sand is produced (generally referred to CHOPS for Cold Heavy Oil Production with Sand) is one of the heavy oil recovery processes that have been used to recover bitumen from weakly consolidated reservoirs. There has been significant debate over the exact mechanisms that allow the sand to be produced and whether the process creates a radial zone of high permeability around the wellbore or more linear high permeability channels (wormholes) out from the reservoir. Numerical modeling of the sand production process presents significant numerical challenges mainly because it is a highly-coupled nonlinear process and requires constitutive models that are able to capture the material instability. In this paper, we present a numerical approach to explicitly model the sand production process using the Finite Element Method with Arbitrary Lagrangian Eulerian (ALE) formulation. A number of novel features have been developed and integrated into the ALE formulation to tackle the challenges associated with sand production simulation, such as Eulerian boundary, automatic adaptive remeshing, and advanced constitutive models. By combining these features, our model enables stable coupling between fluid flow and geomechanics, and is capable of modeling large deformation and highly nonlinear geomechanical behaviors. Some examples are provided to demonstrate the soundness, accuracy, and effectiveness of the numerical model. For simulation of the CHOPS process, the model shows that a key aspect of the process is the shifting of overburden stress from parts of the reservoir sand that fail and are produced to those where the sand has not failed. It is this mechanism that allows wormholes to form in the numerical models. The models have also shown conditions which can be induced in the reservoir to enhance formation of wormholes.
Toward Rapid, Expert-Driven Learning Content Development, Embedded Learning And Reduced Time To Market
Authors: Rousseau Meta
Published: October 2011

As the oilfield approaches the long-awaited Big Crew Change and numbers of Generations X and Y employees continue to grow, organizational learning is beginning to reflect this change. Today's new hires tend to have high levels of computer literacy and actively using mobile technology, cloud computing, geo-coded data such as Google Earth, personalized web sites such as Facebook and Linked-In, semantic-aware applications, smart objects and web 2.0 technologies. Naturally, this workforce readily embraces the use of cutting-edge technologies in the work environment as well as for communication and learning.

High levels of comfort with cutting-edge computer and network technologies enable us to develop and implement a greater variety of effective learning solutions. The use of Learning Management Systems (LMS) has become quite common-place and a growing number of early adopters are now implementing Learning Content Development Systems (LCMS) to ensure the effective development and management of rapidly expanding learning libraries.

Through use of the above-mentioned cutting-edge technologies and compatible technical standards as well as the rapidly growing number of user-friendly authoring tools, organizations are able to develop and deliver quality, effective learning solutions. Moreover, the use of web conferencing tools and information mapping environments enable project teams to work well across geographical and time boundaries.

The role of the instructional designer is changing. Facing high demand and close deadlines, instructional designers are spending less time developing learning materials and more on guiding and supporting teams of subject-matter experts through the instructional design process. Instead of working on one or two projects, the typical instructional designer manages several project teams. Through these expert-driven learning solutions, organizations are able to move a significant portion of organizational learning back into the field - and as learning becomes increasingly embedded, organizations are able to cut back on time away from the job and reduce time to market.
An Integrated Approach to Design Completions for Horizontal Wells for Unconventional Reservoirs
Authors: Jain R. , Syal S. , Long T. , Wattenbarger C. , Kosik I.
Published: October 2011

This paper presents a comprehensive and integrated workflow to design completions for a heavy oil recovery process that involves injection and production through the same well. Unlike in traditional completion design, the transient effects are particularly important to consider while analyzing the long-term performance for these types of completions to capture the effect of variations or uncertainties in reservoir and fluid flow characteristics over time. The proposed integrated workflow involves initial screening and selection of flow restricting completions that can meet the desired injection and production performance based on a detailed wellbore hydraulics modeling tool. A select few completions are then analyzed for longer term performance using a reservoir simulator that couples the flow restricting nature of completions with flow in the reservoir. The use of best-in-art wellbore hydraulics model and reservoir simulator in a staged process yields an effective way to assess and optimize the completion design for these wells in a reduced time span. The workflow disclosed here can be used to design effective completions for a broad class of cyclic liquid injection methods for heavy oil resources.
Managing Pressure Drilling with Continous Circulation, A Summary of Eni Experience
Authors: Calderoni A. , Masi S. , Repetto C. , Tufo M. , Molaschi C. , Poloni R.
Published: October 2011

Drilling exploration wells may be challenging due to uncertainties related to several factors like well downhole pressure, pore and fracture pressures, etc. As a result, a well may fail to reach its target depth.

Managed Pressure Drilling (MPD) is a useful technique in challenging conditions. It allows pore and fracture pressures to be accurately calculated while drilling, and the mud weight adjusted accordingly. Besides, it reduces the chance of human errors as it is an automatic device managed by specific software.

Eni's distinctive MPD system is the e-nbd™ (Eni Near Balance Drilling). This system consists of an innovative drilling process that maintains constant bottom hole annular pressure at all times. The system does not require that mud circulation be stopped and compensated with a back up pressure.

The e-nbd™ is assisted by a proprietary system for continuous circulation that is called e-cd™ (Eni Circulating Device). The e-cd™ system is composed of special subs that are positioned on top of each drilling stand. The number of required subs is defined by the length of the open hole section that is to be drilled with continuous circulation. The system is completed by a dedicated manifold that is positioned on the rig floor that automatically diverts mud flow from the Stand Pipe Manifold to the subs.

e-nbd™ through the e-cd™ System ensures a continuous MPD process, without any "transient" time.

This paper presents this innovative system and the achieved results. It reports a summary of the applications performed to date, including some offshore applications from floaters, as well as the major benefits of the system.
The Rapid Growth of e-Learning in the Upstream Petroleum Industry
Authors: Donohue David A. , Donohue Timothy D. , Kapela Jared M.
Published: October 2011

The use of e-Learning to train upstream petroleum technical specialists has grown substantially in the past five years. In this paper we summarize how that rapid growth has occurred among the 80 company users of a major E&P e-Learning resource, list those practices that lead to the most effective use of e-Learning and indicate how this form of learning is reducing the overall cost of training.

By analyzing the monthly e-Learning usage data of 80 worldwide corporate users and the usage practices of the "best users," we are able to recommend how e-Learning can be most effectively implemented and used in conjunction with challenging simulations to build competency more rapidly.

e-Learning can significantly reduce training costs, and allow classroom courses to focus less on lectures and more on practical assignments and simulations so as to enhance learning and build performance competencies.
Maximization of Oil Mobility within a Hydrocarbon Reservoir for Elastic Wave-based Enhanced Oil Recovery
Authors: Jeong Chanseok , Kallivokas Loukas F. , Huh Chun , Lake Larry W.
Published: October 2011

Elastic wave-based enhanced oil recovery (EOR) has been proposed and used as a low-cost EOR method. Strong wave motions were reported to be able to mobilize oil still remaining in previously bypassed zones. This paper discusses the feasibility of inducing resonance-like wave motion within an oil reservoir in order to maximize wave-based EOR. To this end, a novel mathematical algorithm was developed to determine the optimal conditions of wave sources that can maximize the wave motion within an oil reservoir while minimizing, if desired, the vibrational disturbance in the neighboring formations. The optimized wave sources can generate strong wave motion within an oil reservoir, thereby potentially allowing the oil ganglia trapped in rock pores to overcome the strong capillarity between the droplets and the rock matrix.

Numerical experiments were conducted to identify the unknown optimal time signal information of wave sources that can lead to the maximum kinetic energy or maximum acceleration within an oil reservoir. These numerical experiments consider realistic geometries and material properties of a hydrocarbon reservoir, as well as multiple wave sources located on the ground surface. We demonstrate that optimized time signals can result in constructive interference of wave motion within a targeted hydrocarbon reservoir. We show that such signals can be either monochromatic, where the excitation frequency corresponds to one of the discrete reservoir amplification frequencies, or can even be transient.

Overall, when the formation's characteristics are known, our method allows one to prescribe the necessary waveforms that maximize particle motion within the reservoir.
Crosswell Electromagnetic Tomography in Unconventional Well Geometries
Authors: Wilt Michael , Zhang Ping , Safdar Muhammed
Published: October 2011

Crosswell Electromagnetic (EM) Tomography is a recently developed technology for interrogating the interwell formation resistivity from measurements in boreholes. The tomography data is used for reservoir characterization and for time lapse monitoring of waterflood and EOR processes. Measurements are normally made in vertical wells that encompass the target of interest and collected data are interpreted via computer based inversion.

Modern oil fields often use highly deviated and horizontal wells because they offer improved production and reservoir contact characteristics. These are difficult to use for tomography due to access and sensitivity issues. In addition, the models are in general 3D. In this paper we explore the extension of crosswell EM tomography to non vertical wells. In particular we examine tomography from horizontal wells (HH) and a horizontal-vertical (HV) well combination. Using examples from carbonate oil fields in the middle east we show that the horizontal tomography is an effective method so long as the reservoir has significant thickness compared to the interwell spacing. HV tomography is particularly interesting near horizontal injection wells to track reservoir conformance of the injectate. Numerical models show that this configuration has a good sensitivity to a variety of structures and processes but that the method is only effective for a limited distance along the horizontal well
The Effects of Fluid Hammer Tools on the Efficiencies of Coiled Tubing Plug Milling - A Comparative Best Practices Study
Authors: Schneider Christopher , Craig Steven , Castañeda Juan Carlos , Castro Luis
Published: October 2011

Horizontal fracture stimulated completions remain the de facto method of producing from shale formations. The vast majority of wells are completed using the "Plug and Perf’ fracturing technique which later requires either a drill string or coiled tubing (CT) with a positive displacement motor (PDM) to remove the composite plugs. An estimated 6,000 to 8,000 wells are completed each year, with between 100,000 to 140,000 composite plugs installed in them in the U.S. alone. In extended reach horizontal completions, plug removal using CT becomes less efficient since end load forces transmitted to the PDM from the coiled tubing decrease as well depth increases.

Currently many operators rely on ‘word of mouth’ to design and perform extended reach CT jobs, resulting in ‘non-engineered’ and poorly executed plug milling operations. However, one new method to extend the operating envelope of efficient coiled tubing plug milling utilizing a water hammer tool has gained significant momentum. Several water hammer tools are in common use and there is significant anecdotal evidence that their application has improved job efficiencies.

This paper reviews plug milling efficiencies and general best practices from milling operations conducted in shale formations across the US (Eagle Ford, Bakken, Haynesville, Barnett and the Marcellus). The scope will cover operations completed with three different fluid hammer tools and base cases conducted without these tools.

The paper will also discuss milling efficiencies, number of stalls, stuck pipe incidents, speed and frequency of wiper trips and fluid selection associated with plug milling operations. The authors believe that the information presented in this paper will provide relevant analytical data to assist operators in improving the overall efficiency of the completion process.
In-Line Water Extraction from Crude Oil using Compact Separation Technology
Authors: Wordsworth Carl , Beg Najam
Published: October 2011

Conventional bulk oil-water separation is usually undertaken using gravity separators, where the phases are allowed to separate over time using gravity. One consequence of this technique is that in order to allow a sufficient residence time for the two phases to separate, gravity separators, tend to be large vessels. The step change alternative to this traditional approach is to consider using a compact separator where a high centrifugal force is impacted on the two phases to bring about separation and in doing so reducing the residence time needed to separate the fluids. As a consequence of this approach not only are the separators size and weight significantly reduced but correspondingly its safety features are considerably enhanced due to the lower hydrocarbon inventory and design codes used.

Caltec have developed an in-line cyclonic separator that is designed to separate water from a water continuous oil-water mixture, the devices are capable of recovering up to 60% of the total water at a quality of 1000ppm or less. They are designed to pipeline or process pipework code; can be installed in-line; have a large turn down ratio; have enhanced separation of fluids if gas is present; can separate the fluids at full pipe line pressure and are a fraction of the size and weight of a conventional gravity separators.

Caltec's Water Extraction (Wx) technology has been extensively tested in its own laboratories at Cranfield, and at TUV NEL's multiphase test facilities in Glasgow. Work has also been undertaken both onshore and offshore but this data will not be published in this paper, but will be reported at a later date. This paper describes the water extraction technology and reviews the results of the trials undertaken. This paper also examines potential applications where compact in-line separation technology can be used in future developments.
A Modern Method for Using Databases to Obtain Accurate Solutions to Complex Reservoir Characterization Problems
Authors: Freedman R. , Anand V. , Zhou T. , Rose D. , Beekman S.
Published: October 2011

Many problems in reservoir characterization require the formulation and solution of an inverse problem. The definition of the inverse problem is the prediction of reservoir properties from measurements made on the reservoir. The most familiar example of an inverse problem is well log interpretation. Well logging involves the acquisition of various kinds of data for the purpose of predicting reservoir properties of the earth formations near the borehole.

Conventional inverse methods used in the industry today typically involve the constrained minimization of a weighted sum of the squared deviations between a set of measurements and a forward model equation or equations. The forward model equations are either empirically or theoretically derived equations. These equations relate the reservoir property to be predicted (e.g., saturation, permeability, etc.) to measurements (e.g., resistivity, T2 distributions, porosity, etc.). Adjustable parameters in the forward model equations are determined using a "calibration database" of laboratory measurements made on a suite of representative samples. This traditional methodology suffers from fundamental limitations that reservoir rocks and fluids are too complex to be accurately described by the simple idealized equations that are used today as forward models. Additionally, the forward models contain adjustable parameters which can vary over a wide range, thereby leading to additional inaccuracies in reservoir properties.

Our paper discusses a new model-independent inversion method that overcomes the limitations and inaccuracies of the conventional method. The new inversion method predicts reservoir properties without the need to use idealized model equations or to solve minimization problems. The new method divides the calibration database into input measurements (e.g., used for the predictions) and outputs (e.g., the reservoir properties to be predicted). The outputs are mapped to the inputs using model-independent mapping functions constructed from Gaussian radial basis functions (RBF). The RBF mapping functions are accurate representations of the functional relationship between the database inputs and outputs. The coefficients of the mapping function can be uniquely determined using the database. Once the coefficients are determined, there are no adjustable parameters.

The new method is applicable to a wide variety of reservoir characterization problems. The construction of the mapping functions is presented in detail. We apply the method to a challenging problem in nuclear well logging — accurate predictions of formation thermal neutron capture cross sections (sigma) from well logging data. Logs of formation sigma predicted using the conventional regression method and the new method are compared and discussed.
First Successful Field Utilization of Cuttings Re-Injection (CRI) in the Offshore Field of Saudi Arabia as an Environmentally Friendly and Cost Effective Waste Disposal Method
Authors: Ezell R. , Quinn F. , Chima J. , Baim A.
Published: October 2011

Environmental regulations for oil and gas companies have become increasingly stringent with particular focus on remote areas and environmentally sensitive terrestrial and marine locations and the preservation of natural habitats and resources. With this in mind, many regulatory agencies have adopted "zero discharge" policies requiring monitored disposal of all wastes generated from drilling operations. For designated drilling operations, the various waste streams include: drill cuttings, excess drilling fluid, contaminated rainwater, produced water, scale, produced sand, and even production and cleanup waste. Traditional practices range from onsite pit burial to temporary box storage and hauling of the waste products to a final disposal site. Environmental risks from accidental releases and gas emissions result in higher operating costs and present concerns and liabilities as disposal sites are often several kilometers (km) from the generation source.

Cuttings re-injection (CRI) is a safe and cost-effective alternative that provides permanent and contained disposal of drilling cuttings in an engineering-determined subsurface formation. CRI provides a reliable method for achieving "zero discharge" by injecting slurrified cuttings and associated fluids into hydraulically created fractures up to several thousand meters below the surface. This disposal technique helps mitigate environmental risks and future liabilities associated with potential surface contamination.

This paper outlines the first successful application of CRI technology in the offshore areas of Saudi Arabia as a cost-effective and environmentally friendly waste management technique. Details of CRI theory as well as best practices, challenges and lessons learned are presented in detail from initial engineering design to case study utilization. This high pressure CRI work was the first of its kind in the MENA region.
How Do We Achieve Sub-Interval Fracturing?
Authors: Augustine Jody R.
Published: October 2011

To achieve multiple transverse fractures in a horizontal well, ball-actuated stimulation-sleeve completions were developed as an operationally faster alternative to plug-and-perforate completions. However, ball-actuated stimulation sleeves have reached a physical limit for the maximum number that can be used in a well. Horizontal wells can be divided into approximately 20 independent intervals. The actual maximum number of intervals is dependent on several variables. The goal is to achieve an independent transverse (normal to the wellbore axis) fracture for each interval. Each interval is pumped separately.

To attain more transverse fractures per well, multi-entry stimulation sleeves were developed to subdivide the intervals. An interval consists of one traditional ball-actuated stimulation sleeve and one or more multi-entry stimulation sleeves located upstream of the traditional stimulation sleeve. Multi-entry stimulation sleeves are actuated, or opened, with a specific-diameter ball, and then the ball is released and lands on a traditional stimulation sleeve. Each interval is still pumped separately, and the fluid flows in parallel through each sub-interval (sleeve within the interval). The question to be answered is how can sub-interval fracturing be achieved while pumping through multi-entry sleeves in parallel? The ultimate goal is to achieve one transverse fracture per sub-interval.

Analysis results are presented that address several issues, specifically, the role of annular isolation between sub-intervals, methods to achieve sub-interval fracturing, and scenarios that result in only one fracture per interval.

Several options for the verification of sub-interval fracturing are discussed. Currently, plug-and-perforate completions with multiple clusters are used. The perforation clusters are pumped in parallel. However, there is more to be done to help ensure sub-interval fracturing or verify the effectiveness of the multiple clusters. Strengths and weaknesses of the verification methods for both multiple-cluster plug-and-perforate completions and multi-entry stimulation-sleeve completions are discussed.
Total Organic Carbon and Formation Evaluation with Wireline Logs in the Green River Oil Shale
Authors: Herron Michael M. , Grau James A. , Herron Susan L. , Kleinberg Robert L. , Machlus Malka , Reeder Stacy Lynn , Vissapragada Badarinadh , Burnham Alan K. , Day Roger L. , Allix Pierre
Published: October 2011

A well drilled in the Green River formation in Colorado on the Bureau of Land Management RD&D lease of American Shale Oil LLC (AMSO), provides an opportunity to compare core measurements and log-derived properties in a unique unconventional resource reservoir. The core was analyzed for matrix density, Fischer Assay, total organic carbon (TOC), mineralogy, and 58 inorganic elemental concentrations. Logs include neutron, density, gamma ray, resistivity, magnetic resonance, and inelastic and capture nuclear spectroscopy. The data from this well are used to demonstrate new methodologies to estimate the TOC content and Fischer Assay oil yield.

The TOC content is estimated in three ways. The first is a multitool petrophysical evaluation. The second is an estimation of kerogen from the difference between density and magnetic resonance (MR) porosities where MR porosity corresponds to the water-filled porosity and density porosity to the sum of kerogen-and water-filled porosity. The third method combines inelastic and capture nuclear spectroscopy log data to compute elemental concentration logs of total carbon, inorganic carbon, and TOC.

For comparison of core mineralogy and chemistry with log data, over 200 intervals of core from this well were sampled as 2-ft-long slabs that were ground and homogenized, approximating the vertical resolution of log responses. The agreement between the logs and core values for total carbon, total inorganic carbon, and TOC is very good. The TOC log is used to activate empirical relationships such as Fischer Assay oil shale grade from TOC, again with good results.