bluuebunny/crossref_metadata_2025 huggingface dataset:
Plunger Lift Modeling Towards Efficient Liquid Unloading in Gas Wells
Authors: Chava G. , Falcone G. , Teodoriu C.
Published: October 2009

This paper is a follow up to SPE 115934, which introduced a preliminary plunger lift model built around the availability of Smart Plunger(**) data. These devices are equipped with internal gauges to record pressure and temperature with time, which can be downloaded whenever the plunger is at surface.

We present an updated model that accounts for pressure drop only due to gravitation, but satisfactorily reproduces the dynamics of a field installation in East Texas, USA.

We also present a comparison of the predictions from the new model and the corresponding results from some earlier plunger lift models available in the public domain.
Simulation of Two Phase Flow in Reservoir Rocks Using a Lattice Boltzmann Method
Authors: Ramstad Thomas , Øren Pål-Eric , Bakke Stig
Published: October 2009

We present results from simulations of two-phase flow directly on digitized rock microstructure images of porous media using a lattice Boltzmann method. The implemented method is done on a D3Q19 lattice with fluid-fluid and fluid-solid interaction rules to handle interfacial tension and wetting properties. We demonstrate that the model accurately reproduces capillary and wetting effects in pores with non-circular shape. The model is applied to study viscous coupling effects for two-phase cocurrent annular flow in circular tubes. Simulated relative permeabilities for this case agree with analytical predictions and show that the non-wetting phase relative permeability might greatly exceed unity when the wetting phase is less viscous than the non-wetting phase.

Two-phase lattice Boltzmann simulations are performed on microstructure images derived from X-ray microtomography and process based reconstructions of Bentheimer sandstone. By imposing a flow regulator to control the capillary number of the flow, the lattice Boltzmann model can closely mimic typical experimental setups, such as centrifuge capillary pressure and un-steady and steady-state relative permeability measurements. Computed drainage capillary pressure curves are found to be in excellent agreement with experimental data. Simulated steady-state relative permeabilities at typical capillary numbers in the vicinity of 10−5 are in fair agreement with measured data. The simulations accurately reproduce the wetting phase relative permeability, but tend to under-predict the non-wetting phase relative permeability at high wetting phase saturations. For higher capillary numbers, we correctly observe increased relative permeability for the non-wetting phase due to mobilization and flow of trapped fluid. It is concluded that the lattice Boltzmann model is a powerful and promising tool for deriving physically meaningful constitutive relations directly from rock microstructure images.
Joint Radial Inversion of Resistivity and Sonic Logs to Estimate In-Situ Petrophysical and Elastic Properties of Formations
Authors: Mallan Robert K. , Ma Jun , Torres-Verdín Carlos , Wang Gong Li
Published: October 2009

Presence of near-wellbore damage, resulting from drilling and mud-filtrate invasion, can substantially affect sonic and resistivity borehole logging measurements. Therefore, unbiased log interpretation must account for presence of invasion in order to procure accurate estimates of formation properties. Our objective is to estimate the formation's dry bulk and shear moduli, porosity, and water saturation from the joint inversion of borehole array-induction resistivity and sonic measurements.

We assume a radial one-dimensional (1D) model in the inversion, with the formation model described by a radial variation of water and hydrocarbon saturations representative of mud-filtrate invasion. The inversion is guided by the data misfit of both array-induction apparent resistivities and sonic-log flexural and Stoneley wave velocity-frequency dispersion curves. Radial distributions of fluids are converted to distributions of resistivity, density, and bulk modulus, which are input to the simulations of apparent resistivity and sonic logs. We make use of fluid-substitution models to relate bulk density, dry bulk modulus, and dry shear modulus to porosity and fluid saturation. Apparent resistivities are simulated based on a commercially available array-induction logging tool. Sonic measurements are analyzed in the frequency domain via flexural and Stoneley wave mode dispersions, which are calculated directly in the frequency domain.

Synthetic cases consider water-base mud filtrate invading a hydrocarbon-bearing sand and oil-base mud filtrate invading a water-bearing sand. Porosities and elastic properties consistent with a soft formation are considered in the models. Sensitivity analysis indicates that sonic flexural and Stoneley mode dispersions naturally complement apparent resistivity measurements in the presence of mud-filtrate invasion. Inversions of synthetic cases produce reliable estimates of dry-rock bulk and shear moduli, porosity, and initial water saturation. Furthermore, these cases show that combining resistivity and sonic measurements reduces ambiguity in the inversion.
Wellbore Stability: A Critical Review and Introduction to DEM
Authors: Kang Yongfeng , Yu Mengjiao , Miska Stefan , Takach Nicholas E.
Published: October 2009

Borehole stability issues are always a spotlight in drilling activities because of their costly consequences, including borehole collapse, lost circulation, stuck pipe etc.

Wellbore instability is primarily a function of how rocks respond to the induced stress concentration around the wellbore during various drilling activities. By considering different failure mechanisms between the formation and drilling fluid interaction, several major wellbore models have been presented over the last seventy years. Those models take into account the mechanical, chemical, hydraulic, or thermal effects between the drilling fluid and the formation, or couple two or more effects in a model. The time effect is also taken into account in some of the models. In most of the models, 1) the rock is treated as a continuous material 2) borehole failure is normally based on single initial failure point. However, rocks are discontinuous materials formed under an environment of complex stresses. Also, it is likely an overstatement to say that instability occurs when only one point fails. Even if a small group of grains disconnects from wellbore, the well can still be stable. While somewhat irregular (noncircular) the wellbore can still accommodate casing and installation of down-hole equipment. Therefore, this paper also introduces a new approach based on grain-scale discrete element modeling (DEM) to mimic the realistic rock condition. The rock is modeled as an assembly of numerous grains bonded by cement-like materials, and pore spaces are formed between the small grains. The dynamics of rock grains is simulated and tracked on a computer. Micro cracks (because of tensile or shear failure) occurring at stress-concentrated zones and their coalescence to form macro fractures are tracked. The borehole shape and size are tracked with time.

This paper is useful to those who wish to understand the main limitations of the conventional models and the potential usefulness of a new approach based on a discrete element method (DEM). The approach presented in this paper can also help engineers understand how wellbore instability (post-initial failure) develops with time.
Development and Implementation of a Slimhole Very-High-Dogleg Through-Tubing Rotary-Steerable Drilling System
Authors: Andersen Stein Kristian , Winterstø Knut Morten , Eidem Morten , Robson Ian
Published: October 2009

The maturing of many of the major oil fields around the world, combined with the drive to extend the life of assets and improve recovery rates, has led to significant interest in technology able to access bypassed oil and multiple small targets by achieving complex 3D well paths using Through Tubing Rotary Steerable Drilling (TTRSD) practices. The technology allows for reentry of existing wells and the enhancement of recovery by the drilling of one or more laterals from the existing well bore, while the completion and Xmas tree remain in place. Since the lateral is created deep in the existing well, the necessary distance, and drilling time, to the target are short and of comparatively low cost. Furthermore, since the existing completion remains in place, a costly re-completion is avoided. Assets will thus have production enhanced and utilization increased by quickly and efficiently getting access to additional reserves.

In June 2006, Statoil (before the merge between Statoil and Hydro) and Schlumberger entered into a joint development program to build the systems suitable for TTRSD. The primary motivation for the program was to make a system that would enable drilling very high curvature well sections. This is important in TTRSD since the laterals are deep, and often in depleted reservoirs, making high doglegs quite critical in order to quickly steer away from water and other problem-zones. The new Very High Dogleg series of rotary steerable tools were developed in a size suitable to pass through existing completions in the North Sea, and communication technology was developed to allow transmission of near bit inclination and azimuthal information.

During the period August-September 2008 the tool was successfully tested out in a Through Tubing Rotary Drilling (TTRD) operation in a well on the Gullfaks field on the Norwegian Continental Shelf, operated by StatoilHydro. The system provided, among other things, an average buildrate of 12,25°/30 m in the build section of the well. For the dimensions in question this is a significant improvement compared to existing Rotary Steerable Systems (RSS) systems.
Incremental Reserves and Production Potential from Horizontal Wells in Chuchupa Field, Colombia
Authors: Rivera Nestor , Meza Nestor , Munoz Jaime , Joya Pedro , Mora Carlos
Published: October 2009

During 2006 we drilled 3 horizontal wells in Chuchupa field, a large gas offshore reservoir in the Colombian Caribbean Sea. The drilling campaign included drilling, logging, pressure testing, and coring a pilot vertical hole, which was key in improving our reservoir characterization. The reservoir thickness and petrophysical parameters found were better than expected and the new information reduced the uncertainty on the Original Gas In Place (OGIP). These wells increased the production potential for this field significantly. Current cumulative gas in Chuchupa is 2.5 Tscf, equivalent to 400 Million barrels of oil. The field has 7 horizontal, 7 slanted and 1 vertical production wells located on 2 production platforms.

We formed a multidisciplinary team to design the optimal development plan for Chuchupa. The team included geoscientists; reservoir, production, drilling, completion, and facilities engineers; decision analysts; and commercial and planning professionals. We performed seismic re-interpretation, petrophyscial evaluation, geologic modeling, and integrated-reservoir-to-surface simulation. The study resulted in a set of static and dynamic models that were used to generate a phased development that consisted of 3 new horizontal wells and installation of a compression system.

The 3 proposed horizontal wells were successfully drilled and completed and field production capacity increased by 250 MMscf/D. We have produced 203 Bscf from these wells after three years. We acquired 330 ft of core in the vertical pilot hole with 100% recovery. We found 60 ft of additional gas column, with average porosity and permeability of 30% and 6 Darcies respectively. Rigorous production- and pressure-history match supported the revaluation of OGIP range from 4.1-5.3 Tscf to 5.0-5.6 Tscf.

Integration of various disciplines, detailed planning, good execution, and use of robust coupled reservoir-surface tools resulted in a successful development project that increased reserves and production potential significantly. The added capacity and additional reserves supported the implementation of compression installed in 2009. The obtained results allow Chuchupa to continue being an important player in supplying the gas demand in this north corner of South America.
Understanding the Roles of Inflow-Control Devices in Optimizing Horizontal-Well Performance
Authors: Fernandes Preston , Li Zhuoyi , Zhu D.
Published: October 2009

Inflow Control Device, often referred to as equalizer, is a completion hardware that is deployed as a part of well completions aimed at distributing the inflow evenly. Even though the detail structures vary from one design to another, the principle for different inflow control devices is the same - restrict flow by creating additional pressure drop, and therefore balancing or equalizing wellbore pressure drop to achieve an evenly distributed flow profile along a horizontal well. With a more evenly distributed flow profile, one can reduce water or gas coning, sand production and solve other drawdown related production problems. In general, inflow control devices are not adjustable; once installed in the well, the location of the device and the relationship between rate and pressure drop are fixed. This makes the design of a well completion and inflow control devices extremely critical for production. Inflow control devices can be either beneficial or detrimental to production, strongly depending on the reservoir condition, well structure and completion design. Realizing that reservoir conditions will change during the life of a well, the impact of an inflow control device is a function of time. The inflow control devices sometimes can be overlooked if the design is only based on reservoir flow simulation.

In this paper, we will investigate how and when an inflow control device should be used. An integrated analysis method of inflow (reservoir) and outflow (wellbore) is used to generate the flow profile of a horizontal well, and additional frictional pressure drop created by inflow control devices will be considered. Two conditions that result in production problems, wellbore pressure drop and breakthrough of unwanted fluids, will be addressed. The focus will be on when and how an inflow control device can optimize production. Examples at field conditions will be used to illustrate that it is critical to understand the reservoir conditions and wellbore dynamics together when designing a well completion with inflow control devices. Since uncertainty of reservoir condition always exists, backup plans and conservative designs are desirable. The observations from this study show that overdesigned inflow control devices will not just increase the cost of well completion, but also impact the well performance negatively.
Coupling Capillarity-Controlled Fluid Displacement with Unconsolidated Sediment Mechanics: Grain Scale Fracture Opening
Authors: Prodanovic Maša , Holder Jon , Bryant Steven L.
Published: October 2009

We rigorously model immiscible displacements in unconsolidated sediments subject to confining stress. Fluid-fluid interfaces are assumed controlled by capillary forces, and the progressive quasi-static (PQS) algorithm based on the level set method determines the pore level geometry of those interfaces. From the pore-level fluid configuration we compute the net force exerted on each sediment grain by capillary pressure, including cohesion at grain contacts supporting pendular rings. We combine those forces with mechanical stress and elastic properties of grains to determine the resultant movement of grains using a discrete element method code (Itasca's PFC3D). To our knowledge this is the first rigorous coupling of capillarity and grain solid mechanics in 3D. When grains can move in response to net force exerted by the nonwetting phase, small variations in the distribution of pore throat sizes lead to self-reinforcing, focused channels of nonwetting phase during drainage. When forces exerted by capillary pressure are the same magnitude as the force required to displace grains, this channeling prevents the emergence of a recognizable fracture.
Determining Acid Distribution Using Distributed Temperature Measurements
Authors: Tan X. , Zhu D. , Hill A. D.
Published: October 2009

Placement of a sufficient volume of acid in all desired zones is critical for a successful acid stimulation treatment. Particularly in thick, highly heterogeneous carbonate formations, the acid distribution is crucial for optimal stimulation results. A variety of diversion methods are applied in acidizing treatments to evenly place acid along the well, but the effectiveness of these diversion methods is generally only inferred from the rate and pressure behavior during the treatment, and is not known with any certainty. It would be extremely helpful if the acid distribution could be measured.

We developed a model to simulate the temperature behavior along the wellbore during acid injection and during the flow back period following an acid stimulation. An important phenomenon in this process is the heat generated by reaction, the key factor enabling the interpretation of the acid distribution from the temperature profile. We have developed a mathematical model that describes the coupled flow and heat transfer process. The flow system consists of a near wellbore formation with a wormhole region and a spent acid region. Wormhole propagation and the spent acid front are simulated as a function of acid injection volume (time). The thermal model includes conduction, convection, and reaction heating to seek the connection between acid volume distribution and temperature profile. The result of the thermal model showed significant temperature effects caused by reaction. During flow back, the zone that took more acid volume would have created more heating because of reaction, providing a mechanism to quantitatively determine the acid flow profile.
Research of Gas Separator with Disperser Influence of ESP Work and Increase of Well Operation Efficiency by the Use of ESP
Authors: Mokhov Mikhail , Tsunevskiy Andrey
Published: October 2009

In recent years there is a tendency of standing increase of ESP share in performance stock of oil recover companies. At the same time there is an increase of oil production from water-producing wells observed in consequence of universal application of water flooding and depletion of the most large deposits. An average watercut of recovered products at pump operation system is at the present time 8085%. As you know, one of the complicating factors of steady operation of ESP is free gas inflow into the pump. For the protection of ESP against free gas deleterious effect on the oil-fields, gas separators are widely used because they allow separate some part of the gas into annular space. When watercut increases, the quantity of free gas in the flow stream falls, and it becomes possible to apply disperser which is required for the generation of fine liquid-gas mixture, which reaching the inlet of ESP decreases free gas effect on the pump operation. Application of the dispersers is also effectually for zero water-cut oil fields with moderate-size gas oil ratio.
Expanding Knowledge to Young Engineers in our Industry
Authors: Jabaley Sally
Published: October 2009

It is a well-established fact in the oil and gas industry that the workforce is aging and there are fewer people in the 10-15 year experience range each year. The solution to this dilemma has been to hire university graduates and quickly train them to succeed the existing aging workforce. Unfortunately, the very people who need to train these new graduates are the experienced employees who are stretched to keep up with the unprecedented workload in the recent environment of asset development and projects. They simply do not have the time to train and supervise new hires. Additionally, current projects and assets are so large and complex, that companies cannot afford the opportunities to allow these new hires to learn by doing, as a mistake can have huge heath, safety, environmental or economic consequences.

In order to help train these new graduates adequately, the Society of Petroleum Engineer's Projects, Facilities, and Construction Committee developed the Expanding Facilities Knowledge Workshop, which consisted of five cafeteria-style presentations. These presentations covered a range of Facility Engineering basic competencies and were held at various locations around Houston throughout the summer. The sessions were heavily attended and there are current plans to continue the workshop in the future. This workshop can also be considered a model for other disciplines within SPE to help train new graduates in their field.
A New Upscaling Method of Relative Permeability Curves for Reservoir Simulation
Authors: Wang Kefei , Killough John E. , Sepehrnoori Kamy
Published: October 2009

Relative permeability is one of the most important factors in numerical reservoir simulation. Although the relative permeability curves may be available on a very fine level of detail, their direct use to estimate the amount of uncertainty, which requires thousands of reservoir simulation runs, is generally not practical because of the excessive computer time and memory that would be required. Despite the extensive research that has been performed in the past few decades, effective upscaling to reduce computation times in highly heterogeneous reservoir still remains a challenging procedure.

In this paper, we demonstrate how conventional upscaling approaches may lead to large errors. To overcome the inaccuracy, we investigated and developed a new relative permeability upscaling technique for the coarse scale modeling for heterogeneous reservoirs. In our new method, single-phase upscaling was applied at the beginning to set up the base case for optimization. The regression runs were conducted by non-linear optimization. The decision variables in a standard Corey and logistic form were used to check the errors between the coarse and fine models. After the procedure converged, a new relative permeability curve for the coarse model was generated. The match for the breakthrough time and post-breakthrough performance was very accurate using the new relative permeability curves. Predictability with the new curves also appeared to be substantially improved; the newly generated relative permeability curves can be used over periods beyond that of the original match.

The new method was verified by using three-phase, 3D, and highly heterogeneous reservoir models. These verifications were performed on large models approaching one million cells with black oil and composition fluids with waterflooding and water-alternating-gas (WAG) recovery processes.

The ultimate goal of the work has been to use the upscaled models with modified relative permeabilities to investigate how uncertainty is affected by upscaling. The fine scale results indicate that more reasonable results can be obtained for estimating the effect of uncertainty with the new upscaling technique as compared to conventional methods, with computation time orders of magnitude faster than previously available.
Determination of Concentration Dependent Diffusivity Coefficient in Solvent Gas Heavy Oil System
Authors: Etminan S. R. , Maini B. B. , Hassanzadeh H. , Chen Zh.
Published: October 2009

Molecular diffusion coefficient is an important parameter in modeling mass-transfer based reservoir processes. However, experimentally measured diffusivities for heavy oil systems are relatively scarce and no standardized method exists for measurements of this important parameter. The available measurement techniques are tedious, expensive and often not very reliable. There is an obvious need for developing improved methods for measuring diffusivity of gases in heavy oils.

It is well known that as a gas dissolves into heavy oil, the oil viscosity drops considerably and this affects the diffusivity. The objective of this work is to measure the diffusivity of highly soluble gaseous solvents in heavy oils at different concentration levels. We have developed a modified pressure decay method that maintains constant concentration at the gas-liquid interface and measures the amount of gas transferred to the liquid as a function of time. An analytical solution has been developed for finding diffusion coefficient and the equilibrium solubility of gas in the oil at the test pressure. To study the concentration dependence of diffusivity, a stepwise increase in pressure is used starting from a low pressure. Through this stepwise procedure, a diffusion coefficient is measured for each gas saturation pressure (concentration), going from low pressure to near gas dew point pressure in 5 to 6 steps. The bitumen height in our cell is updated at each pressure to account for bitumen swelling. Propane was used as vapor solvents and diffusion cell was kept at constant temperature.
Calibration of High-Resolution Reservoir Models Using Transient Pressure Data
Authors: Kim Jong Uk , Datta-Gupta Akhil , Brouwer Roald , Haynes Byron
Published: October 2009

Integrating dynamic data into high resolution reservoir models is a crucial aspect of any optimal reservoir development and management strategy. In this regard, pressure data provides several advantages. First, pressure transient tests are easier and less expensive to carry out in the field. Second, pressure responses can be obtained early in the field life compared to watercut or tracer data. Finally, the pressure perturbations travel much faster compared to tracer or water front, resulting in quicker response in the field. This makes interference tests much more appealing compared to tracer tests which may require months to see a field response. However, the computation cost and localized nature of pressure sensitivities pose difficulties in history matching transient pressure data with a finite difference model. Also, pressure tests from multiple wells are difficult to analyze because of superposition of pressure responses.

We propose a fast and robust approach to integrating transient pressure data using a trajectory-based approach that relies on a high frequency asymptotic solution of the diffusivity equation. The trajectory or ray-based methods are routinely used in seismic tomography. In this paper, we make a detailed comparison of streamlines and seismic rays and examine the applicability of streamline-based methods for transient pressure data inversion. Specifically, the high frequency asymptotic approach allows us to analytically compute the sensitivity of the pressure data with respect to reservoir properties such as porosity and permeability. This results in a very efficient approach for the integration of pressure data into geologic models.

We apply our proposed method to transient pressure data from both single well test and multi-well interference tests. Our results demonstrate the advantage of performing interference tests compared to performing tracer tests in terms of identifying heterogeneities early in the field life. Finally, we apply this approach to data from a multiwell interference test in a Middle Eastern reservoir. Specifically, the pressure data obtained from permanent downhole gauges (PDG) in multiple wells are utilized to determine communications in the reservoir and to derive quantitative information about the permeability distribution in the reservoir for potential aid in the design and optimization of a miscible gas flood.
A Practical Method for Minimum Miscibility Pressure Estimation of Contaminated Gas Mixtures
Authors: Johns R. T. , Ahmadi Kaveh , Zhou D. , Yan M.
Published: October 2009

Minimum miscibility pressure (MMP) is a key parameter in the design of gas floods. Injection gas compositions often vary during the life of a gas flood owing to reinjection and mixing of fluids in situ. Understanding the impact of the gas compositional changes on the MMP is essential to optimal design of field-wide pressure management and CO2 utilization. Determining the MMP by slim tube or other methods for each possible gas mixture is impractical. This paper gives an easy and accurate way to determine MMPs for any multicomponent gas based solely on a few estimates of MMPs from binary gas mixtures.

We use the method of characteristics (MOC) and our newly developed mixing-cell method to estimate MMPs for binary gases, where the primary component is contaminated by another component. We demonstrate how to calculate MMPs for multicomponent solvents using two example reservoir oils displaced by CO2 contaminated by various mixtures of N2, CH4, C2, C3, and H2S. We also examine the sensitivity of local displacement efficiency to dispersion for binary gas mixtures using one-dimensional simulation.

The results show that the MMP for gases composed of two or more components can be very accurately estimated from a linear mole-fraction weighted function of the MMPs determined from each binary gas mixture, such as CO2–CH4 and CO2–C2. For a West Texas crude, the MMPs for contaminated CO2 injection streams are determined accurately over a wide range using only the pure-component MMPs. The accuracy of the MMPs are within +/− 15 psia of those calculated using mixing cell and slim-tube simulations. That is, the MMP for all possible gas compositions is nearly a linear combination of the pure-component MMPs. For the second oil displacement by impure CO2, however, the linear interpolation is accurate as long as the contaminant levels are less than about 20% by mole fraction. For this volatile oil we use an extrapolation of the MMPs for small contaminant concentrations in our linear MMP estimation function.
Compositional Modeling in Three-Phase Flow for CO2 and Other Fluid Injections Using Higher-Order Finite Element Methods
Authors: Sun Shuyu , Firoozabadi Abbas
Published: October 2009

CO2 injection is one of the most attractive options for water-flooded reservoirs. The numerical simulation of the process is computationally challenging; it requires accurate compositional modeling of three-phase flow in porous media. In this work, we simulate for the first time, three-phase compositional flow using higher-order finite element methods. Our numerical model is based on an iterative IMPEC coupling of the pressure equation and species transport equations, which are solved by mixed finite element (MFE) and discontinuous Galerkin (DG) methods, respectively. A number of numerical examples in one and two dimensions are presented to illustrate the modeling capability of the proposed algorithm. We take into account various phase behavior effects including swelling, viscosity reduction and vaporization from CO2 injection in water-flooded reservoirs. The model captures the spike in concentration. Numerical comparison of our combined MFE-DG approach with the conventional upstream weighted finite difference method indicates that MFE-DG has low numerical diffusion. The proposed MFE-DG method can capture the solution discontinuities and yield accurate prediction of shock locations arising in computational three-phase flow. The work sets the stage for broad extension of the higher-order methods for numerical simulation of three-phase flow for complex geometries and complex processes.
Managing Your Business Using Integrated PRMS and SEC Standards
Authors: Etherington John R.
Published: October 2009

The SPE/WPC/AAPG/SPEE Petroleum Resources Management System (PRMS) published in March 2007 provides an international industry standard for classifying and reporting reserves and resources. Many companies have adopted PRMS directly, or in modified versions, as part of their internal asset management systems. However, publicly traded companies have historically been forced to maintain two sets of reserves and resources records: one for internal project and portfolio management, and one for regulatory disclosures. This may no longer be required for those issuers listed on U.S. stock exchanges. On December 29, 2008, the U.S. Securities and Exchange Commission (SEC) published revised rules for disclosure of oil and gas reserves that closely align with the evaluation principles and reserves guidelines contained in PRMS.

The SEC mandates reporting of Proved Reserves while disclosure of Probable and Possible Reserves is now optional. These disclosures may be viewed as a subset of PRMS which also includes guidance on Contingent and Prospective Resources. While PRMS reserves are confined to projects that are economic based on internal price forecasts, the SEC requires use of 12-month historical average prices. However, the systems may be integrated with options to include supplemental assessments based on alternative pricing scenarios. Both PRMS and SEC accommodate deterministic and probabilistic estimates of "as sold" hydrocarbon products irrespective of the extraction method and interim processing required.

This alignment allows the same resource evaluation to underpin both internal business processes (project tracking, portfolio management) and regulatory disclosures including reconciliations by category. It is now feasible to design a single database to support reporting requirements for both functions at multiple aggregation levels based on geographic area, product type, resource class, and resource category.

Companies can now manage their business based on PRMS industry standards but accommodate SEC disclosures within a single integrated assessment system. In addition to allowing significant process efficiencies, a common system improves the linkage between technical and business analyses providing a clear audit trail.
Development and Application of Upscaling Techniques for Modeling Near-Well Flow in Heterogeneous Reservoirs
Authors: Chen Yuguang , Bernath Alan , Rai Himansu , Muron Pierre
Published: October 2009

Upscaling is often applied in reservoir simulation to coarsen highly detailed geological descriptions. Flow in petroleum reservoirs is mainly driven by wells, thus upscaling of near-well flow is important in coarse-scale flow simulation. In this paper, we present an upscaling methodology, which involves a recently developed coarse-scale well model, combined with transmissibility upscaling for inter-well regions. The coarse-scale well model, referred to as near-well arithmetic averaging, directly uses fine-scale permeabilities along well trajectories to compute coarse-scale well index. Compared to flow-based near-well upscaling techniques, this method does not require solving any fine-scale flow problem, but can approximately capture the effects of fine-scale heterogeneity in near-well regions. Therefore it is straightforward for use and does not incur any computational overhead. This model is implemented in a general reservoir modeling framework, which allows for the handling of realistic grid geometry and well completion from real field data. In inter-well regions, we apply transmissibility upscaling, which directly computes the upscaled transmissibility (defined at block interfaces) rather than permeability upscaling. Standard upscaling methods (local permeability and border region permeability upscaling) are also considered to illustrate their potential errors when not being applied appropriately (e.g., without near-well treatment). We apply the proposed upscaling methodology (near-well arithmetic averaging for near-well flow and transmissibility upscaling for inter-well regions) to sector models from real field cases. All the cases involve general multiphase flow simulations, including primary production, water flooding to oil-water and three-phase flow models. It is shown that the proposed methodology consistently improves the accuracy of standard upscaling methods that are commonly used in the industry and for some cases, provides accurate flow predictions, demonstrating its practical applicability for real field cases.
An Improved Model for Water-Hydrocarbon Surface Tension at Reservoir Conditions
Authors: Sutton Robert P.
Published: October 2009

The surface tension that exists between hydrocarbon and water systems is an important property within the petroleum industry. Uses of this property range from quantifying its effects on capillary pressure which governs the vertical saturation distribution of hydrocarbons in a reservoir to determining liquid droplet size for multiphase flow calculations. A general correlation for estimating water-hydrocarbon surface tension has been developed. Prior generalized methods presented in the literature were found to be in error for gases other than methane and did not adequately characterize the change in surface tension with temperature. A large database consisting of 1902 data points was created as part of the development of the correlation. Pure hydrocarbon component surface tension measurements against pure water provide the basis for this database. Data ranging from methane through hexadecane as well as benzene and toluene were included in the main database. Pure water data at vapor pressure equilibrium was also included in the analysis to ensure that changes in surface tension with temperature were modeled accurately. In addition, natural gas, natural gas-carbon dioxide and natural gas-nitrogen mixtures with pure water were tested with the new correlation to ensure realistic scenarios could be accurately modeled. Pressure data covered the range from 14.7 to 43,526 psia while temperature ranged 33–500 °F which ensures that both conventional and HPHT conditions can be modeled. Real hydrocarbon-water systems usually contain dissolved salts in the water; therefore, a salinity correction must be applied to account for the increase in surface tension. Available data from the literature was examined and a suitable correction is proposed. This paper presents the analysis of an exhaustive database and proposes a new correlation to model water-hydrocarbon surface tension with significantly higher accuracy.
Laboratory Testing of Downhole Gas Separators in Inclined Wellbore Configurations
Authors: Alabi O. , Podio A. L.
Published: October 2009

This paper attempts to establish the effects, if any, of wellbore inclination on the performance of downhole gas separators. Different downhole gas separator designs have been extensively studied in the laboratory and far reaching conclusions have been drawn from observations made in the laboratory for vertical wellbores. However, it is pertinent to note that most wellbores are not truly vertical and a survey which shows the deviation of the wellbore from a vertical reference point is often present in most wellbore configurations. Hence, this paper compares the performance of different downhole gas separator designs in a vertical wellbore set up with that of the same downhole gas separators operating under similar conditions but installed in an inclined wellbore set up.

Technology has made it possible to drill horizontal wells which are fast becoming ubiquitous in most oilfields. With gravity forces dominating separation in static downhole gas separators; it is certainly logical to study the effect of wellbore inclination on the separation efficiency of downhole gas separators as transport properties of multi-phase fluids are affected by gravity. With the above mentioned arguments, it becomes imperative to study downhole gas separators under conditions which best simulate oilfield operations.

The approach utilizes an instrumented full scale model of an inclined well-bore and separator constructed with clear acrylic pipe. The base case consists of the entire wellbore and separator set up installed vertically and subsequent experiments were performed with the wellbore inclination angle at 45°. An air and water mixture is injected through the well's perforations. The air and water flow rate measurements define a performance plot of each separator design with respect to wellbore inclination. Continuous flow conditions were applied in all tests

Results obtained from laboratory annular bubble rise experiments show that in an inclined set up, the bubbles tend to move along the walls of tubing where the effect of drag is maximum. Results from the annular bubble rise experiments in an inclined wellbore equally show that the upwards motion of the smaller bubbles tend to be considerably reduced and sometimes halted by drag while on the contrary, the larger bubble (Taylor type bubbles) have higher mobility along the walls of the tubing.

Also, results from the downhole gas separator performance tests conducted in a wellbore inclined at 45° indicate that at similar operating conditions, a gravity driven downhole gas separator installed in a wellbore inclined at 45° would perform better than the same gravity driven downhole gas separator in a vertical wellbore. While at similar operating conditions, a centrifugal force driven downhole gas separator installed in a vertical wellbore would perform better than the same centrifugal force driven downhole gas separator in a wellbore inclined at 45°.
Field Test Results of an Electromechanical Precision Pipe-Cutting Tool
Authors: Fanini O. N. , Fuhst K. , Cousin D. , Moeller M. , Ahmed M. A. , Ross B. , Krueger S. , Lowson P. , Cattanach S. M.
Published: October 2009

A recently developed electromechanical precision pipe-cutting tool is being field tested. Its primary applications are to cut and free stuck pipe (tubing or drillpipe) or cut pipe to modify a production completion installation. Cutting pipe in today's complex completions presents many challenges. Testing of this new cutting technology has demonstrated significant advantages over previously used equipment. It is non-ballistic, has a large cutting range for a wide range of metal pipes, provides cut monitoring and success detection. The precision of the cut is facilitated by the tool's internal programming (smart function) which allows for specifying the type of metal to be cut, monitoring the depth of the cut, recognizing the drag and making the appropriate adjustments to complete a cut. The ability to complete multiple precise cuts reduces associated rig time. Its large operating temperature and pressure ratings (20,000 psi), large cutting size range, and portability make possible quick deployment to offshore and land operations. Additional field-demonstrated capabilities include: performs accurate smooth cuts, cuts harder metals with a high chrome content, performs precision cuts for inner pipe cutting, works at any deviation, produces minimum debris, surface system allows application to any wireline, does not require circulation holes for the cutting device, operation deployment is not constrained by chemical issues relate to safety and environment, the cutter's light weight, short shipping length (two sections, each less than 10 feet in length), and compatible portable support equipment allow for quick deployment in a variety of transport modes. This paper includes a case study to illustrate the operating challenges associated with tubing and drillpipe cutting in a variety of conditions and environments.
Practical Solutions for Pressure Transient Responses of Fractured Horizontal Wells in Unconventional Reservoirs
Authors: Brown M. , Ozkan E. , Raghavan R. , Kazemi H.
Published: October 2009

This paper presents an analytical trilinear flow solution to simulate the pressure transient and production behavior of fractured horizontal wells in unconventional reservoirs (Ozkan et al., 2009). The model is simple, but versatile enough to incorporate the fundamental petrophysical characteristics of unconventional reservoirs, including the intrinsic properties of the matrix and the natural fractures. Special characteristics of fluid exchange among various reservoir components may also be considered. This practical solution provides an excellent alternative to rigorous solutions, which are cumbersome to evaluate. One of the advantages of the trilinear flow solution is its convenience in deriving asymptotic approximations. Though linear and bilinear flow regimes have been noted for fractured horizontal wells in the literature based on their diagnostic features, they have not been associated with particular reservoir characteristics and flow relationships. The solutions documented in this work provide insight about potential flow regimes and the conditions leading to these flow regimes. Identification of these flow regimes is important for the characterization of unconventional reservoirs from pressure transient tests. Because of its relative simplicity, the trilinear flow solution does not require special expertise to compute and apply.
Experiences In Introducing 3D Visualization In Petroleum Engineering Education
Authors: Gupta A. , Platt F. M.
Published: October 2009

This paper describes the experience obtained in introducing 3D immersive visualization exercises in petroleum engineering at Texas A&M University in Qatar. Challenges encountered in the process are discussed. An immersive visualization facility (CAVE) was recently installed at TAMUQ to support teaching and research needs. Although, similar systems are used in industry for visualizing reservoirs and making development decisions, there is no known precedent of using CAVE for petroleum engineering education. Given that petroleum engineering revolves around subsurface reservoir and well systems, there is heavy reliance on engineers' ability to use their imagination for effectively visualizing and designing such systems. Petroleum engineers do not have the luxury of seeing, touching, feeling, and in general, developing an intuitive feel for the objects and systems they are dealing with. Two types of visualization exercises have been introduced.

First experience relates to visualization of pore structure based on 3D rendering of CT-scan data obtained for core samples of sandstone and carbonate reservoirs. Time-lapse CT scans were repeated during capillary imbibition experiments to visualize and animate the displacement process in CAVE. The scanner was also used to visualize and animate frontal advances. The results are compared to animation of simulation results. The second experience relates to visualizing results of simulation of reservoir displacements. The students are able to experience various recovery mechanisms at reservoir scale.

3D visualization of subsurface reservoirs offers benefit of providing students greater insight into reservoir and well systems and mechanisms of recovery processes. It allows students to conduct virtual-walk through the reservoir pore space. It gives them insight into the nature of flow at various length scales. Students are able to view pore-level fluid-flow in reservoir rocks in "virtual-reality. Based on results of 3D visualization, students are able to "experience" recovery mechanisms at porelevel and grid-block resolution.
Composites Improve Well Construction Efficiency
Authors: Imhoff Jamie , Parmer Don , Ronck Ben , Smith Kenny , Yuan Yusheng
Published: October 2009

After cementing a new liner section during wellbore construction, the liner wiper plugs and landing collar must be drilled out to proceed with the next well section. Current conventional aluminum systems produce considerable resistance and wear to drilling equipment resulting in increased effort and time to drill out the components. The conventional aluminum tools are typically drilled out in 4 to 16 hours.

This paper discusses the development, laboratory testing, and field testing of composite liner wiper plug systems for two-plug and four-plug applications that dramatically reduce standard drill-out times, ease the development path for future plug designs, and open doors for other drillable products. The composite liner wiper plug systems include running tools, liner wiper plugs, pump-down plugs, and landing collars that perform multiple functions during the liner cementing process. In addition to the cost savings associated with reduced drill-out times, the systems provide wellbore fluid isolation for cementing integrity, reliable fluid displacement, high-pressure and high-temperature performance, positive bump indication, clear flow paths for setting ball compatibility, and special contingency backups.

The composite material needed excellent drillable properties without compromising performance and reliability. The lab results matched the ratings of conventional plugs and landing collars. The systems have completed many successful runs and are gaining favorable reception from our customers and operations personnel. With drill-out times of less than one hour, these initial results represent a significant reduction in rig time and operational costs, adding savings and value to the completion solution.