bluuebunny/crossref_metadata_2025 huggingface dataset:
Closed-Loop Modeling of a Gulf of Mexico Reservoir Using Petrophysical Seismic Inversion
Authors: Liu Yuhong , Pelissier Michael , Barnes Martha , Tribe Julian , Uden Richard , Teer Joshua
Published: October 2009

We integrated pre-stack 3D seismic data with petrophysical, geological and production data to build a closed-loop reservoir model. All four data types were honored at the appropriate scale in their respective domains using a petrophysical seismic inversion workflow.

Starting from an initial fine-scale geocellular model of the subsurface built using state of the art methods, we forward modeled it into synthetic seismic data through user-defined petro-elastic models, that is, a set of rock physics relationships used to compute compressional and shear velocities, and density. Reflection coefficients were calculated and convolved with the wavelet to obtain the forward modeled seismic response. The modeled seismic data were compared with the measured seismic data and the discrepancy was gradually minimized through a simulated annealing optimization. Additional perturbation of the initial model was performed through comparing modeled production performance with the measured production data. This perturbation/updating process stops when the modeled performance matches the measured performance data.

The workflow was applied to a sand reservoir in the Gulf of Mexico. It is shown that the resulting product is a closed-loop reservoir model consistent with log, seismic and production data at their respective scales and domains. The workflow overcomes the many limitations of the linear "throw-over-the fence" approaches widely used in reservoir modeling. A potential expensive deep-water well was analyzed using precise delineation and evaluation of the reservoir and was found to have a high risk of failure so the well program was cancelled.
GeoMechanics Field Characterization of the Two Prolific U.S. Mid-West Gas Plays With Advanced Wire-Line Logging Tools
Authors: Abousleiman Younane , Tran Minh , Hoang Son , Ortega J. Alberto , Ulm Franz-J.
Published: October 2009

Woodford shale has recently emerged as a potential gas play in the U.S. Mid-continent, following in the footsteps of the Barnett shale. Profitable production from these formations relies on the success of horizontal well drilling and hydraulic fracturing design, which in turn depends greatly on knowledge about rock formation anisotropic elastic properties and pore pressure coefficients (poroelastic properties). In this paper, a suite of recently developed wire-line logs such as the Element Capture Spectroscopy (ECS) log, Sonic Scanner log, and porosity logs, were run on the Woodford and Barnett formations. The results were utilized to estimate the anisotropic elastic and poroelastic properties of these gas shale formations using the GeoGenome™ model, a theoretical upscaling model backed up with unique laboratory testing on field retrieved preserved shale samples at a scale that has never before been investigated; that is, observing mechanics from displacements as small as 100 nm to 100 μm, and maximum applied forces not even reaching 1000 μN. Comparison between laboratory Ultrasonic Pulse Velocity measured data, Sonic Scanner log data, and simulated data has shown excellent agreement, and thus confirmed the reliability of the GeoGenome upscaling model in obtaining shale anisotropic mechanical properties of which some parameters cannot be obtained even with the most advanced sonic log. In addition, a new technique was developed using nano-indentation to extract the Woodford shale mechanical and strength properties from drill-cuttings. The measured stiffnesses and compressibility on Woodford shale drill-cuttings-size chips have shown great potential for full mechanical characterization of rocks from just the drill-cuttings, which until recently were regarded as having little value for rock mechanical characterization besides some existing simple empirical correlations. This new shale testing technique will undoubtedly help the industry to significantly reduce the overhead associated with full core retrievals at great depths.
Minimizing Water Invasion in Shale Using Nanoparticles
Authors: Sensoy T. , Chenevert M. E. , Sharma Mukul M.
Published: October 2009

This paper presents data showing the positive impact of adding nanoparticles to water-based drilling muds and their effect on fluid penetration into hard and soft shale. Use of present-day water-based muds during drilling can produce fluid penetration from the mud into shale formations resulting in swelling and wellbore instability. The nanometer sized pore throat diameters of shales are too small for conventional drilling fluid particles to invade and build an internal or external mud cake.

Four field muds in contact with Atoka and Gulf of Mexico (GOM) shales were studied with and without the addition of nanoparticles. Penetration of fluids into the shales was shown to decrease dramatically when nanoparticles were properly sized and applied.

Results show that nanoparticles reduce the permeability of the Atoka shale by a factor of 5 to 50. Similar results are obtained for the GOM shale. When nanoparticles were used, water penetration into Atoka shale was reduced by 98% as compared to sea water.

Measurement of shale pore sizes and scanning electron micrographs of the Atoka shale taken after exposure to nanoparticle dispersions, show that the nanoparticles are indeed small enough to penetrate and plug the shale pores and pore throats. This plugging of pore throats by the use of nanoparticles offers a powerful and economically viable new solution for controlling wellbore stability problems in troublesome shales.
Sequestering Carbon Dioxide in a Closed Underground Volume
Authors: Economides M. J. , Ehlig-Economides C. A.
Published: October 2009

The capture and subsequent geologic sequestration of CO2 has been central to plans for managing CO2 produced by the combustion of fossil fuels. The magnitude of the task is overwhelming in both physical needs and cost, and it entails several components including capture, gathering and injection. The rate of injection per well and the cumulative volume of injection in a particular geologic formation are critical elements of the process.

Published reports on the potential for sequestration fail to address the necessity of storing CO2 in a closed system. Our calculations suggest that the volume of liquid or supercritical CO2 to be disposed cannot exceed more than about 1% of pore space. This will require from 5 to 20 times more underground reservoir volume than has been envisioned by many, and it renders geologic sequestration of CO2 a profoundly non-feasible option for the management of CO2 emissions.

Material balance modeling shows that CO2 injection in the liquid stage (larger mass) obeys an analog of the single-phase, liquid material balance, long-established in the petroleum industry for forecasting undersaturated oil recovery. The total volume that can be stored is a function of the initial reservoir pressure, the fracturing pressure of the formation or an adjoining layer, and CO2 and water compressibility and mobility values.

Further, published injection rates, based on displacement mechanisms assuming open aquifer conditions are totally erroneous because they fail to reconcile the fundamental difference between steady state, where the injection rate is constant, and pseudo-steady state where the injection rate will undergo exponential decline if the injection pressure exceeds an allowable value. A limited aquifer indicates a far larger number of required injection wells for a given mass of CO2 to be sequestered and/or a far larger reservoir volume than the former.
Comprehensive Model for Flow Behavior of High-Performance Fracture Completions
Authors: Zhang Y. , Marongiu-Porcu M. , Ehlig-Economides C. A. , Tosic S. , Economides M. J.
Published: October 2009

Experience shows that high-performance fractures (HPFs) may retain near unit flow efficiency (equivalent to zero skin in a vertical well) and rarely fail, even in highly deviated wells. This may be partly because overly simplistic models of the well flow behavior lead operators to maintain wells at lower production rates than could have been achieved for the same amount of injected proppant with a vertical well completion design. Rigorous models that account for widely accepted rock mechanics fundamentals indicate that the fracture to well connection is compromised in deviated wells and lead to questions whether the bulk of the flow to the well actually passes through the fracture.

Distributed volumetric sources are used in this model to rigorously model a wide variety of possible fracture geometries such as an expanded wellbore due to halo effect, flow strictly through the fracture, and combined flow to a single fracture and to remaining flowing perforations not connected to the fracture. The model also includes turbulent flow effects that may occur for radial flow conditions in the fracture plane or in the reservoir opposite wellbore sections not connected to the fracture as well as high velocity flow through the perforation tunnels. It also computes the effective flow area at the resulting face between the reservoir and the completion to check whether flow velocity exceeds conditions that would risk production of reservoir fines, and estimates the screen flow velocity based on the number of flowing perforations.

This comprehensive view of the HPF completion enables a thorough analysis of the risks of flowing the well at high rate. Field examples show that the new model better depicts the real field conditions in calculating the total skin, flow fractions and the flux for HPF completions in high rate gas and oil wells.

Complete inflow performance behavior for all likely flow patterns for HPF wells in oil and gas reservoirs is provided.
Improving Fidelity of Network Models for Drainage and Imbibition
Authors: Peng Yao , Prodanovic Maša , Bryant Steven L.
Published: October 2009

Network models are a powerful method for extracting macroscopic multiphase properties from microscopic information. All network models of capillarity-controlled displacements (drainage/imbibition) require critical curvatures for pore level events as input. Techniques that ensure accurate critical curvatures in these models are therefore valuable. We describe a novel method to verify the correct choice of curvatures: a pore-by-pore comparison of displacement events predicted by a network model with those computed directly in the original pore space. The latter are obtained from LSMPQS, our implementation of the level set method for tracking fluid/fluid menisci in arbitrary confining geometry. We examine the robustness of a new, convenient criterion to estimate the critical curvature for imbibition events, derived from observing instances of Melrose's mechanistic criterion during LSMPQS simulations in about 200 individual pores. We validate the approach by comparing predictions from large, finite networks and infinite-acting networks to measured drainage/imbibition curves.

A subset of a densely packed, disordered packing of spheres was used to test these concepts. More than 95% of the pores investigated have the same filled phase for network model and LSMPQS simulations at the drainage endpoint and more than 85% are the same at the imbibition endpoint. A smaller fraction (around 65%) matched in the vicinity of the percolation threshold, mainly because a small error in estimating critical curvatures in the network leads to a disproportionately large shift in the pressure-saturation curve. But the sequence of pore-filling events during drainage is very similar in the two cases. The new criterion for pore imbibition was also verified, as the imbibition curves for both simulations exhibit similar behavior, which in turn match experiments reported in the literature. The sequence of pore-filling events during imbibition differed for the network model and LSMPQS, however. This was primarily because the network model simulations did not account for coalescence of pendular rings.

Capillary pressure curves from infinite acting network models showed the same percolation threshold as traditional estimates, but a larger saturation of displaced phase was obtained at the drainage/imbibition endpoints. The larger residual nonwetting phase saturation (Snwr) is consistent with estimates of residual saturation in reservoirs from tracer tests, indicating that lab-scale measurements of this quantity are influenced by boundary effects not present in the field.
Interpretation of Well Test Data in Gas Condensate Deformable Formations
Authors: Shandrygin A. , Rudenko D. , Begar A.
Published: October 2009

The interpretation of WT data in gas condensate formation with stress sensitive rock is very complex problem due to simultaneous effect of several phenomena on fluids flow in the near wellbore area such as: "formation damage skin", non-Darcy flow effect, condensate bank and permeability changing due to rock deformation. In this case it's not possible to estimate the main reservoir properties and total skin with its components using only standard interpretation technique of the WT data. This problem can be solved on the basis of special approach of the joint treatment of the steady flow multirate test and pressure build up test data. The proposed WT data interpretation method allows to get the key formation parameters: "undamaged" formation permeability (permeability in area distant from well), permeability vs. formation pressure as exponential function, non-Darcy flow coefficient, total and "condensate bank" skins. Suggested approach was evaluated using synthetic production data for the reservoir model based on the Urengoyskoe field (Western Siberia, Russia) parameters.
Collaboration in Extracting More Oil in Mature Dual Completion Wells
Authors: Khalid M. Idham , Poit R. Elug , Jumaat M. Shafie
Published: October 2009

The offshore state of Sarawak in Malaysia contains many mature wells that were completed 20-30 years ago with dual-strings and multiple packers to exploit the many layers of sand packages. The wells that were designed to exploit the main sand packages are currently depleted and producing at high water cut. The operator is now considering ways of exploiting the smaller intermediate sand packages in these wells. In many cases, this requires oriented perforating through one completion string while avoiding shooting another completion string that is still producing. Oriented perforating using analog orienting devices that were previously deployed has many operational problems that on several occasions have led to abandoning jobs, and ultimately deferment of additional production. As such, this has led to many of these mature wells that require oriented perforating being left unexploited for many years. The arrival of a new digital orienting device is expected to open the path to better exploitation of the intermediate sand packages.

This paper is a case of deployment of this device for PETRONAS Carigali in Sarawak, Malaysia which required collaboration with the service contractor at many stages, from planning and characterizing the device responses in various completion configurations in Sarawak, to writing standard operational procedure and contingency planning, and to real-time decision making during operation.

The results of operation of this device on two wells in Sarawak are also presented, as is how the collaboration in the planning stages contributed to their successes.

While the success paves the way for future exploitation of the intermediate sand packages for PETRONAS Carigali, the exercise also provides a reference for similar operations in other places, from the point of collaboration and technicality of the service itself.
Seawater Desalination Using Excess Heat from GTL Process
Authors: Srivatsan Jagannath Saiyee , Linke Patrick , Amani Mahmood
Published: October 2009

Over the years, the increasing prices of crude oil and environmental issues have been the major factors for the development of GTL technology. With over 910 Tcf of natural gas reserves in Qatar (gas-in-place and recoverable resources), there is tremendous capacity for additional GTL plants in Qatar. Out of the global projected GTL production of 1.92 million B/d, Qatar alone already has planned to produce 696,000 B/d (36% of total global production). One of the efficient ways of using the exothermic heat from GTL is for desalination. This helps in reducing a large quantity of the fresh fuel to be used as energy input for desalination.

The need for this study is to investigate the availability of exothermic heat from the Gas-To-Liquids (GTL) process to desalinate seawater thereby producing substantial volumes for industrial and/or domestic sectors. This is performed by first designing a schematic base case model of the GTL operation using Aspen Plus. The quantity and quality of heat available from the cooling of the syngas and syncrude streams is used as the energy source for the desalination process. Both thermal desalination and reverse osmosis processes are considered to determine the optimal process for desalination. An integrated GTL-Desalination (GTL-D) process is later designed to compare the output ratio of the GTL-D as opposed to a standalone desalination process.
Intelligent Upscaling of Static and Dynamic Reservoir Properties
Authors: Gholami V. , Mohaghegh S. D.
Published: October 2009

Rock typing is an essential part of building geological model for an asset. Millions of dollars are invested in logs, core measurements, SCAL studies and geological interpretation that result in definition of different rock types. In most caes rock types that are identified in a reservoir do not have crisp boundaries and display overlapping characteristics. During the upscaling process, multiple rock types that have been identified in a high resolution geological (geo-cellular) model are approximated into a dominant rock type for any grid block in a reservoir simulation flow model.This defeats the original purpose of performing detail geological and petrophysical studies as far as reservoir flow models are concerned. The objective of this study is to develop a new upscaling methodology based on fuzzy set theory principles. Fuzzy rock typing refers to taking into account the inherent uncertainties and vagueness associated with rock typing in hydrocarbon bearing reservoirs.

In this paper a numerical simulator has been used as the control environment in order to set up multiple studies that would demonstrate the difference between using conventional approach of implementation of geological models in the reservoir flow simulation studies and the new approach that is the subject of this study. By using the numerical reservoir simulator as the control environment it is intended to study the complexities that exist in geological model at much higher resolution and then compare simulation in large grid blocks using two different approaches. The problem has been set up in the form of upscaling study.

First, the study was performed using conventional upscaling practices and then it was carried out using the proposed technique. The results then have been analyzed in order to demonstrate the difference between the two techniques and the advantages and disadvantages o f each have been identified.

This manuscript has been organized in several sections. In the literature review section the current practices in upscaling dynamic reservoir properties such as relative permeability and capillary pressure are reviewd as well as basic definitions of rock typing. A brief section on fuzzy set theory is also presented in this section. The problem is defined in more details and some background information is presented in the "Introduction" Section. The approaches used to perform the study are presented in the "Methodology" section. Details results are presented and discussed in the "Results & Discussion" section and the manuscript is completed providing some concluding remarks.
Nonlinear Sorption Kinetics and Surface Diffusion Effects on Gas Transport in Low-permeability Formations
Authors: Fathi E. , Akkutlu Yucel
Published: October 2009

In coals and shales, gas transport and storage are important for accurate prediction of production rates and for the consideration of subsurface greenhouse gas sequestration. They involve coupled fluid phenomena in porous medium including viscous flow, diffusive mass transport and adsorption. Standard approach to describe gas-matrix interactions is deterministic and neglects the effects of local spatial heterogeneities. Using an upscaling approach based on small perturbation theory, the authors have previously investigated the influence of small-scale heterogeneities in matrix porosity on Darcy flow and Fickian-type pore diffusion in the presence of linear non-equilibrium gas adsorption (Fathi and Akkutlu, 2009). They identified non-trivial macro-transport and -kinetics effects of the heterogeneity which significantly retard gas release from the matrix and influence the ultimate gas recovery adversely. The work was a unique fundamental approach for our understanding of the gas behavior in unconventional reservoirs; however, it was simplified and did not consider (i) the presence of nonlinear sorption kinetics and (ii) a transport mechanism for the adsorbed phase, i.e., surface (or solid) diffusion. In this paper, we incorporate the sorption nonlinearity and surface diffusion into their formulation and apply the same upscaling approach. Gas sorption involves the so-called Langmuir kinetics, which reduces to the well-known Langmuir isotherm in the equilibrium limit. It is found that the nonlinearity participates into both macro-transport and -kinetics, promoting primarily the surface diffusion effects. Whereras, the surface diffusion, although commonly ignored by the industry, brings an intricate nature to the gas release dynamics. Through macro-transport effect of the heterogeneity, it increases the ultimate gas recovery and, through the macro-kinetics effect of the heterogeneity, it decreases the time needed to reach the ultimate recovery significantly. As the consequence of these effects, it is shown that the gas-matrix system does not reach the equilibrium adsorption limit during any stage of the gas release.
Case Study of a Novel Hydraulic Fracturing Method that Maximizes Effective Hydraulic Fracture Length
Authors: Tudor Eric H. , Nevison Grant W. , Allen Sean , Pike Blaine
Published: October 2009

Effective fracture lengths are frequently observed to be much less than antcipated fracture lengths. This is seen in lower than expected production or evidenced in pressure transient analysis results. A precursor to the poor fracture performance is poor recovery of the fracturing fluid; often less than 50% is recovered during clean-up. In many reservoirs this unrecovered fracturing fluid remains immobile within the formation creating an obstruction to flow. This significantly compromises effective frac length and results in decreased production.

During the fracturing process and subsequent closure of the fracture, the bulk of the fracturing fluid invades the reservoir matrix along the fracture face, referred to as the "invaded zone". This fluid is forced into the reservoir by the significant pressure differential between fracturing pressure and reservoir pressure. Once in the matrix, removal of fluid from the invaded zone can be very difficult as it is held by relative permeability, irreducible saturation, and/or capillary pressure effects.

A novel hydraulic fracturing process using 100% liquefied petroleum gas (LPG) has demonstrated quick and complete fracture fluid recovery, significant production improvements and dramatically longer effective fracture lengths. The process gels the LPG for efficient fracture creation and proppant transport. With that there is no compromise in the fracture treatment placed when compared to conventional treatments. However, once the fracture treatment is complete and the viscosity of the gelled LPG is broken, the unique properties of LPG create an ideal fluid for complete cleanup. Removal of this fluid from the invaded zone is easily achieved; relative permeability effects, irreducible saturation behaviour and capillary pressure demands are eliminated. Complete recovery of the LPG is consistently demonstrated.

Fracturing with 100% gelled LPG was first completed in January 2008. By June 2009 over 210 fracture treatments had been completed. This new process has been applied to a wide range of formations from depths of 750 ft through to 11,500 ft. In this paper, short term technical evaluations, such as post fracture pressure transient analysis, are used to demonstrate the rapid cleanup and effective fracture lengths that approach anticipated fracture lengths. Long term actual production comparisons will be a focus on future papers as results become available.
Oriented Fracturing: A New Technique to Hydraulically Fracture Openhole Horizontal Well
Authors: Abass H. H. , Soliman M. Y. , Tahini A. M. , Surjaatmadja Jim , Meadows D. L. , Sierra Leopoldo
Published: October 2009

Successful fracturing treatment necessitates expensive completion assembly that provides some form of isolation to perform controlled fracturing treatments. Currently isolation is performed mechanically which dictates that isolated interval is very short. This in turn may require that the well is cased, cemented and perforated. This would increase the cost of completion significantly. Another option is to focus the fracturing energy via the use of hydrajetting. In this paper we present another approach that provides a high degree of control on where the transverse fractures will initiate and propagate.

The various existing techniques for creating multiple hydraulic fractures along an openhole horizontal well are briefly summarized. Laboratory experiments shedding light on some of these techniques will be first presented. The new technique to precisely place a hydraulic fracture in an openhole horizontal well drilled in any direction relative to the in-situ stress field is presented. The new technique is based on rock mechanics understanding of an openhole horizontal well under a given in-situ stress field; thus it accounts for the near wellbore stress field to ensure creating a planar hydraulic fracture. Additionally, the new technique does not require costly mechanical isolation to place a hydraulic fracture. Basically, the new technique aims to bypass the near wellbore stress field such that the fracture can be conveniently initiated independently of the stress direction.

This new approach is validated using laboratory experiments which will be discussed in details. The experiments were performed on simulated wells casted in rock samples with dimensions of 6"× 6"×10". The samples were triaxially loaded simulating various arrangements of a given wellbore relative to the in-situ stress field. Then, the simulated wells were hydraulically fractured using water based gel. Fracturing pressure versus time was recorded and analyzed.

The experiments were very successful in proving the new concept to fracture openhole horizontal wells. The developed technique is fairly easy to implement and the impact of precise placement of a hydraulic fracture across an openhole horizontal well is illustrated.
New Technique to Determine Biot Coefficient for Stress Sensitive Dual Porosity Reservoirs
Authors: Abass H. H. , Tahini A. M. , Abousleiman Y. N. , Khan Mirajuddin
Published: October 2009

Poroelasticity plays a vital role in many applications of rock mechanics in petroleum engineering. To model dual porosity stress sensitive reservoirs such as tight gas, it is necessary to quantify the stress-dependant hydraulic conductivities of their porous components, the matrix and natural fractures. The role of effective stress concept near the wellbore is more pronounced as the reservoir pressure declines rather rapidly approaching the bottom hole flowing pressure. The porous media changes when reservoir pressure is altered and therefore the elastic coefficient (α) becomes a function of reservoir pressure for both components; matrix and fractures.

Rock samples from tight formation were tested to determine the stress-dependant matrix permeability. Various combinations of net effective stresses were applied and the corresponding permeabilities were measured at each stress level. Applying the definition of effective stress with an iterative assumption of Biot's coefficient enabled the determination of (α) as a function of pressure.

Additionally, the Biot coefficient was determined for a natural fracture. A tensile fracture was simulated by splitting a whole core following a Brazilian test procedure. The stress dependent permeability was evaluated under varied effective stresses simulating a reservoir depletion scenario. The concept of effective stress within the natural fracture was totally different than that of rock matrix; therefore, the effective stress function for both matrix and natural fractures were evaluated and representative functions for both media were obtained. These stress-dependent permeability functions can then be used in any rock mechanics application in petroleum engineering. The developed experimental procedure is fairly simple and is discussed in details, and selective relavant applications are presented.

The new technique for determining the Biot coefficient is based on the application it is being used for; the effect of effective stress on matrix and natural fracture permeabilities. This paper shows that two poroelastic coefficients, and not one, should be used in any dual porosity system to obtain reasonable prediction of reservoir performance. Varying the coefficient as a function of pore pressure allowed for determining a pressure dependant function for a given porous medium.
A New Performance Award System for Petroleum Engineering Students - Development and Implementation
Authors: Williams John M.
Published: October 2009

A system was developed to give public recognition to high-performing students and encourage other students to strive towards better performance. Two categories of award were established, one for the best performance, and one for the most-improved performance, to add incentive to students who did not think they were in the top echelon of performers. Much effort was put into developing award rules which would ensure students were taking effectively full technical course loads, and would cover numerous complications, such as change of student level between semesters, students switching majors, uneven workload between semesters, possible faculty bias in faculty voting, and tie-break rules. Different types of award gift were evaluated in the light of local culture and traditions, and a non-financial award was considered to be most appropriate.

Many universities are introducing or expanding Petroleum Engineering (PE) programs due to the serious worldwide shortage of petroleum engineers. These applied engineering programs probably involve the most significant progression from basic science, and thus can be very challenging to many students. Presentation of rewards for successfully making the transition motivates students, and provides an important component in department activities each semester.

Awards have now been presented since the academic year 2006-7, with significant interest and competition for awards being demonstrated. Only small rules clarifications have been required since. A survey of students and past graduates has given positive feedback to the award program, though a number of possible improvements have been identified. Other programs at the Petroleum Institute have adopted the same or similar award system.

This issue has not been addressed in an SPE publication previously. The paper provides full details of the student selection procedures which could be adopted by other universities.
Taking Real Options into the Real World: Asset Valuation through Option Simulation
Authors: Jafarizadeh B. , Bratvold R. B.
Published: October 2009

Despite the early enthusiasm, real option valuation (ROV) has hitherto failed to "revolutionize" the way companies value their uncertain real-world assets. The reluctance to embrace ROV is largely due to its complexity and limited applicability to real-world problems.

In this paper, we will introduce, discuss, and demonstrate the potential of one of the most promising ROV techniques: Least-Squares Monte Carlo Simulation (LSM). LSM is a significant step in overcoming the limitations in valuation techniques. It is particularly powerful when investment decisions are a function of multiple uncertain factors and when compounded options which may be exercised at any time exist. The paper will also include a real-world application, illustrating the power and flexibility of the LSM method.

Developing and using a fit-for-purpose ROV model for a realistic investment opportunity is no simple task. However, the result of an ROV is not only an estimated value that includes the value of flexibility, but a complete strategy map showing the optimal choices as uncertainties are resolved. This, together with the creative thinking required to come up with valuable options and identifying the key uncertainties, creates insight and clarity for the decision-makers.
Oil, Natural Gas and NGL Endowment in North, Central and South America
Authors: Aguilera Roberto F. , Aguilera Roberto
Published: October 2009

This study uses the USGS 2000 world petroleum assessment as a starting point. Then it uses a previously defined variable shape distribution (VSD) model for estimating the endowment of oil, natural gas and natural gas liquids (NGL) throughout North, Central and South America.

Use of the VSD model is validated by an excellent fit with actual data, supported by coefficients of determination (R2) equal to 0.98 or greater. The study includes endowments in petroleum provinces not assessed previously by other organizations. Endowment, as defined by the USGS, refers to the sum of known volumes of hydrocarbons (cumulative production plus remaining reserves) and undiscovered volumes. Petroleum is the sum of oil, gas and NGL.

The importance of North, Central and South America is highlighted by a hydrocarbon output during 2007 that accounted for 25% of the world oil production and over 31% of the natural gas production.

It is concluded that there is a large petroleum endowment in North, Central and South America that will last for several decades and will help to contribute significantly to the energy needs of these regions. It is recommended to actively pursue research and development of this endowment.
A Molecular Dynamics Study on Natural Gas Solubility Enhancement in Water Confined to Small Pores
Authors: Campos Mery Diaz , Akkutlu I. Yucel , Sigal Richard F.
Published: October 2009

Unconventional natural gas reservoirs are a major source for the global energy market. Unconventional gas reserves generally are considered to consist of a volumetric component, hydrocarbons stored in the pore space as free gas, and a surface component, gas adsorbed on the large surface area of these microporous systems. A second volumetric component, gas dissolved in the formation water, is generally not considered. For such reservoirs, free gas is quantified by modifications of standard reservoir evaluation methods. Physically adsorbed gas has generally been quantified from laboratory studies to establish the equilibrium adsorption isotherms. Based on bulk solubility calculations, the amount of dissolved gas in water, however, has not been considered important. Our group has recently performed a theoretical study which, for reasonable values of its parameters, predicts that methane solubility is enhanced in microporous media. The implication of this is that the dissolved gas in the formation water may represent a significant portion of the total gas reserves in unconventional reservoirs. Best quantification of this result and insight into this solution chemistry problem should ideally come from theoretical studies at the pore-scale, particularly from molecular-level simulations and the subsequent free energy change calculations accompanying dissolution. In this paper, we examine natural gas solubility enhancement in water residing in a graphene slit-pore with a length-scale on the order of ten nanometers, namely a micropore, using an analytical approach and molecular dynamics simulations. The solubility of methane in water is estimated under controlled temperature condition using the test particle insertion method with the excluded volume map sampling. The results indicate that the methane solubility in the pores is improved significantly (typically, one order of magnitude larger), compared with that in the bulk phase, i.e., in the absence of pore walls. The enhancement is further investigated under varying force-field conditions due to pore-wall surface potential, namely hydrophobicity and found that the solubility is extremely sensitive to small pore wall wettability. The work is a fundamental approach to better understand the unconventional gas reservoirs, and important for the estimation of gas reserves.
High Dogleg Rotary Steerable System: A Step Change in Drilling Process
Authors: Bryan Sonny , Cox Joe , Blackwell Dennis , Slayden Fred , Naganathan Siva
Published: October 2009

Directional drilling has long evolved from the days of Drilling primarily with rotary assemblies, motors and turbines to regular use of rotary steerable systems (RSS). Spears estimate that RSS decreases drilling time by 50% on average (no sliding intervals) and overall well time by 25% (good quality borehole enabling smooth casing and wireline runs). However current rotary steerable systems available in the market have several limitations:

Maximum Dogleg severity capability for RSS drilling 8.5in or 8.75in hole sizes from major service companies is about 6.5 to 8° /100ft in normal formations. In case of soft formations or excessive borehole enlargement these figures drop significantly and BHA is tripped out of hole for running PDM.

Most RSS require a cement plug to be in place to perform consistent and reliable sidetracks. This results in additional time and trips for the operator.

Controlled kick off from vertical is not possible with RSS that require a gravity vector defined to seek TF. This results in quick course corrections and higher T&D.

Steering through highly inter-bedded formations close to horizontal is challenging to conventional RSS due to limited DLS resulting in POOH.

This paper discusses the new generation of fully rotating RSS that has twice the dogleg severity capability of any current RSS systems (up to 15°/100ft). This new technology enables deeper Kick off lowers the horizontal displacement significantly (by 50% or more compare to current RSS), decreases overall measured depth and improves ROP. In addition to this, this new technology has proven its directional versatility by performing open hole sidetracks, saving cost and operating times. It has repeatedly demonstrated its ability to kick off accurately from vertical, land the well precisely on target depth and execute closed loop trajectory controls while drilling lateral sections.

A number of case studies are covered in this paper with results from the field trials of this unique technology. With these capabilities every driller's dream to drill more complex well profiles in single run without the need to trip out of hole with time and cost savings will become reality.
Mechanistic Modeling of Solids Separation in Solid/Liquid Hydrocyclones
Authors: Severino Jose G. , Gomez Luis E. , Wang Shoubo , Mohan Ram S. , Shoham Ovadia
Published: October 2009

Hydrocyclones have been used for many years for removing solids from continuum liquid media in the Mineral, Chemical, Petroleum, and Environmental industries; among others. In oilfield applications, the Solid-Liquid Hydrocyclone (SLHC) has emerged as a sound technological and economical alternative to conventional filtration systems where space, efficiency, reliability and continuous operations are critical. The SLHC is particularly attractive in offshore, subsea, and water injection applications; and other oilfield operations. Early and effective removal of solids in pipelines and process equipment help prevent erosion and premature failures that are costly and pose serious health, safety or environmental hazards.

To date, hydrocyclone design has mainly relied on empirical experience and, most recently, on costly and lengthy CFD simulations. The main objective of this work is the development of a mechanistic model for practical, yet reliable, SLHC design. The proposed model is capable of describing the hydrodynamic flow phenomenon inside the hydrocyclone, enabling the prediction of continuous-phase swirl intensity and the velocity profile used in determining particle trajectories, and hence, the Grade separation efficiency curves. The model is validated against oilfield experimental data run under a wide range of conditions and equipment configurations. Model agreement with Global and Grade separation efficiency data is 94.7% and 88.2% respectively.
A Study of a Low-Frequency Downhole Hydraulic Pulsing Cementing Device and Its Field Application
Authors: Nie cuiping , Towler Brian Francis , Ye Dengsheng
Published: October 2009

A down-hole pulsed pressure device to improve the quality of cement bonds during primary cementing has been developed. The prime purpose was to control gas and water channeling and enhance the cement slurry displacement efficiency, especially in holes with a small annular space, and in holes with large washed out spaces occupied by mud-cake and in gas wells that are susceptible to gas channeling. These problems are difficult to treat with chemical cement agents.

It is shown that pulsing the curing cement can improve the cement slurry hydration, shortening the time between the initial and final cement gelation and abating the slurry weight loss effect. Our experiments show the pulsing frequency is best between 10–30 Hz and the pressure amplitude should be less than 5 MPa.

The device is highly innovative, is easy to engage to the casing string (under the float collar) and has no effect on the casing design. It does not cause failure during cementing, and does not alter the traditional cementing technology.

It has been applied to gas wells in several fields in Sichuan province in China. The pilot well had 11 gas layers and is 4180m (13,714 ft) in depth, and the hole was prone to lost circulation (1.09g/ cm3 mud) and cave in. The cemented well interval was drilled with a 152.4mm (6") bit and cased with a 127mm (5") liner. There are troublesome formations in the interval that caused difficulties in logging and while running the liner. The down-hole pulsing generator worked well with the 1.50g/cm3 cement slurry, but due to the complicated hole conditions the displacement was not finished when the liner became plugged with cement. But after drilling out the cement plug, the CBL and other logs showed the cement quality had been enhanced 50% compared to the offset wells. Then in application to another three wells we also achieved significantly improved cement bonds. So it has been verified that this device can significantly improve cementing, and is easy to apply in the field. We intend to continue to apply it to wells with troublesome formations and to all gas and oil wells with cementing problems.
An Intelligent Platform to Manage Offshore Assets
Authors: Piovesan C. , Kozman J.
Published: October 2009

For offshore platforms and other facilities, intelligent asset management must include proactive monitoring of surface equipment. Studies (Athens Group, 2009) show that up to 20% of the non-productive time (NPT) experienced by a deepwater rig can be the result of control system failures on drilling or production equipment. But similar failures can impact the fixed surface equipment on the rig floor that can also shut down drilling or production operations. Timely management of the complex, software-dependent control systems from multiple equipment vendors on the rig floor can therefore be a major determinant of productivity for intelligent oilfield implementations. The primary goals of the Intelligent Platform (or I-Platform) are to reduce equipment downtime and personnel-on-board (POB) requirements while increasing reliability, safety, regulatory compliance and environmental responsibility. This requires defining operating envelopes that optimize equipment usage for costs and efficiencies, allowing early identification and intervention for pending equipment outages and enabling root-cause failure analysis that takes into account multiple environmental factors. The use of intelligent platform technology has already been proven for subsurface drilling and production data streams and has reached a competent level of capability maturity (Heiberger, 2009). The I-Platform solution applies best practices derived from numerous digital oilfield case studies to fixed surface equipment in order to reduce NPT. This solution is an end-to-end implementation for surface equipment that brings together mission-critical capabilities developed and already being deployed for downhole operations. It utilizes unique data analysis tools with artificial intelligence algorithms for codifying existing equipment expertise into business rules such as neural networks and self-organizing maps. Results of the data mining and analysis are delivered in a role-based and easily configurable visual dashboard for multiple aggregated data streams. A recent prototype installation utilizes data streams from a major offshore drilling contractor with a versatile fleet of mobile offshore drilling units and an operational performance center at a leading oilfield service company to demonstrate the viability of this approach for both offshore and remote onshore operations. The success of this proof of concept demonstrates that disparate data from multiple equipment vendors can be gathered from remote locations, analyzed and distilled into actionable items, and displayed in order to support proactive decisions by a distributed pool of subject matter experts.
Effect of Material Balance on Well Test Analysis
Authors: Madahar Amit , George Stewart , Gringarten A. C.
Published: October 2009

This paper provides a new definition to pseudo-time that incorporates the effects of formation compressibility and residual fluid compressibility, as the reservoir depletes, into well test analysis. The new definition of the pseudo-time can be incorporated into the existing system by using a correction factor that is applied to conventionally defined total system compressibility. The new definition of pseudo-time determines the final average reservoir pressure more accurately even at high degree of depletions of the reservoir. This study also addresses the errors in gas reserves estimation when using conventionally defined total system compressibility, which may have a substantial economic effect.