bluuebunny/crossref_metadata_2025 huggingface dataset:
Formulas for Rupture, Necking, and Wrinkling of Oil Country Tubular Goods Under Combined Loads
Authors: Klever F.J.. J.
Published: June 2010

Advanced well-design methods based on risk assessment of actual failure mechanisms require accurate formulas for burst, collapse, yield, and fracture. Moreover, these strength formulas should be generalized to account for the combined internal pressure, external pressure, and axial load that well tubulars experience.

This paper describes the development of a set of formulas for burst strength [i.e., the failure envelope and the design limit for oil country tubular goods (OCTG) under internal overpressure and any axial tension or axial compression]. Phenomena covered are ductile rupture, pipe necking, and local pipe-wall wrinkling, thus spanning the first and second quadrant in the effective-axial-load/pressure-differential-load space.

This set of formulas is based on a large-strain, elastic/plastic, <3D> formulation of pipe equilibrium, deformation, and buckling that has been solved analytically in closed form for the situation of combined loads. The formulas describe features such as a maximum internal-pressure load (rupture), a maximum axial-tension load (necking), and local buckling of a pipe under axial compression (wrinkling).

Approximate burst-strength formulas are presented that together span the entire axial-load range and closely match the more complex, exact model predictions.

The joint American Petroleum Institute/International Organization for Standardization SC5 Work Group 2B (API/ISO SC5 WG2B) tasked with modernizing the API 5C3 property equations has incorporated the approximate burst-strength formulas presented in this paper into the new ISO TR 10400/API TR 5C3 document (API 2008; ISO 2007).
A Consistent and Accurate Dead-Oil-Viscosity Method
Authors: Bergman David F. , Sutton Robert P.
Published: June 2010

The calculation of pressure drop resulting from the flow of oil through porous media or pipes requires the evaluation of viscosity. This is the single most important transport property necessary to calculate pressure drop accurately. The basis for oil-viscosity calculations using a traditional black-oil approach is the determination of dead- or gas-free-oil viscosity.

A total of 23 dead-oil-viscosity calculation methods have been identified from the literature and evaluated in this paper. A large database consisting of data from conventional pressure/volume/ temperature (PVT) reports, crude-oil assays, and the literature was compiled from more than 3,000 samples from around the world. The number of actual viscosity measurements exceeded 9,800. An evaluation of the correlations yielded unacceptable results largely because of the failure of the methods to properly account for the physics of the problem. In general, this results from the methods’ failure to properly account for the change in viscosity with temperature and to address the chemical nature of the oil. A significant improvement in results can be realized through the use of the Watson characterization factor in addition to oil API gravity and temperature in the correlation of viscosity. This work has identified the character of the crude to have a significant effect on oil viscosity, especially for oils with gravities less than 25°API.

Methods have been proposed in the literature that use the Watson characterization factor; however, these have been largely ignored in the upstream oil industry. Therefore, a new method has been developed that shows significant improvement over existing methods. At reservoir conditions, a 2- to 13-fold reduction in average absolute error was noted when compared with the error observed from traditional methods. At surface process conditions, this improvement ranged 3- to 60-fold. In addition, an updated correlation for Watson characterization has been developed. The ASTM density correction for varying temperature has been examined. Revised coefficients were developed that enhance the method’s accuracy for both oils and pure components and provide a suitable means to convert kinematic viscosity to absolute viscosity.
Field Implementation of Gravel Packing Horizontal Wells Using a Solids-Free Synthetic Fluid With Alpha-/ Beta-Wave Technology
Authors: Aragão A. F. L. , Calderon A. , Lomba R. F. T. , Moreira J. N. V. C. , de Sá A. N. , Martins A. L. , Quintero L. , Moura E.
Published: June 2010

This article details the planning and execution phases of the first openhole gravel-pack (OHGP) operation performed with the alpha-/beta-wave deposition technique using a nonaqueous system as a carrier fluid. The operation was performed at Marlim field, offshore Brazil, and constitutes the first field implementation of a research and engineering effort that started two years ago.

The idea in this first field operation was to avoid many changes in the original well design for the area and to concentrate novel steps in the fluid for gravel packing openhole design, friction loss evaluation, fluid substitution, and rheology characterization. On the basis of these results, optimized procedures were proposed for the operation. A broad description of the technical aspects, field pumping profiles, and packing quality is also presented.
A Semianalytical Thermal Multiphase Wellbore-Flow Model for Use in Reservoir Simulation
Authors: Livescu S.. , Durlofsky L.J.. J. , Aziz K..
Published: June 2010

The detailed interactions between the reservoir and the wellbore are especially important in thermal processes such as steamflooding and in-situ upgrading. These linkages, therefore, must be captured in thermal simulations. Although fully coupled thermal wellbore-/reservoir-flow simulators have been developed, the implementation of the thermal well model is somewhat complicated, and the simulations are computationally demanding. In this paper, we present a semianalytical treatment that enables the extension of existing isothermal wellbore-flow models to the nonisothermal case. The procedure entails the use of analytical solutions for wellbore temperature applied in conjunction with numerical solutions of the reservoir mass- and energy-balance equations coupled with wellbore mass- and momentum-balance equations. The approach thus enables a degree of decoupling between the wellbore flow and energy problems. We proceed by first presenting analytical solutions for wellbore temperature, developed under various assumptions (these basic solutions have been obtained previously). We then describe the use of one of these solutions, which allows for general variation of in-situ phase fraction and other properties along the wellbore, within the semianalytical context. The implementation of the overall method into a general purpose research simulator is also described. Results are presented for several cases involving multiphase flow in monobore and multilateral wells. Close agreement with reference solutions, obtained from a fully coupled thermal wellbore/reservoir model, is demonstrated for all of the examples. The semianalytical treatment is additionally shown to provide comparable or improved computational efficiency relative to the fully coupled model.
Valuing Oil and Gas Options by Least-Squares Monte Carlo Simulation
Authors: Willigers B. J. A. , Bratvold R. B.
Published: June 2010

Least-squares Monte Carlo (LSM) simulation is a promising new technique for valuing real options that has received little or no attention in the oil and gas industry. In this paper, we will demonstrate how LSM simulation can handle more-realistic valuation situations including the ability to (1) handle more-realistic (probabilistic) price models and (2) deal with multiple, possibly correlated, uncertain variables.

The LSM method is applied here to an economics problem faced by many operators: What is the value of a gas field given the decision to trade the gas on the spot market as opposed to selling the gas through a long-term supply contract? A company that chooses to trade gas can decide when and how much to produce and can profit from changing market conditions, such as by increasing production during a high-price environment.

Three uncertainties have been modeled: the gas price, the operational costs, and the rate of production decline. Increasing profitability associated with rising hydrocarbon prices typically is offset partially by increasing expenditures. Hence, the costs have been correlated with the gas price. The expectation of the remaining reserves is adjusted continuously on the basis of the performance of the field. The latter is simulated by stochastically modeling the rate of production decline.

The paper shows that a gas field that can be produced and abandoned at will has a large value of flexibility. The net present value (NPV) of such an asset will underestimate the true economic value. A further benefit of using the real-option-valuation (ROV) approach discussed here is that the valuation procedure produces a strategy map showing actions within the project, not just numbers.
Detecting Thief Zones in Carbonate Reservoirs by Integrating Borehole Images With Dynamic Measurements: Case Study From the Mauddud Reservoir, North Kuwait
Authors: Li Bingjian , Najeh Hamad , Lantz Jim , Rampurawala Mansoor Ali , Gok Ihsan , Al-Khabbaz Mohammed
Published: June 2010

One of the key issues in creating a good reservoir model in carbonate reservoirs is identifying the horizontal permeability conduits—"thief zones"—if there are any. In the Sabriyah field in Kuwait, dynamic measurements showed evidence of thief zones in the Lower Cretaceous (Albian) Mauddud formation. Early water breakthrough has occurred in some wells. Previous studies indicated that it was very challenging to detect the thinly layered thief zones using conventional openhole logs. This paper describes a method of recognizing the different types of thief zones in the Mauddud carbonate reservoirs using high-resolution image logs with calibration from core and dynamic measurements and by integrating image logs with nuclear magnetic resonance (NMR) and conventional openhole logs.

The Mauddud carbonates are Early Albian in age and consist of grainstones, wackstones, and mudstones deposited in a ramp setting. Observations from production logging tools (PLTs) and production data indicated that there are a few thief zones in different levels within the vertical Mauddud sequence. A previous core study shows that the fractures in the Mauddud formation are short (<10 cm) and concentrated in diagenetically cemented layers. The fractured thin layers are believed to be the principal type of thief zone. Another type of thief zone is associated with better-developed vuggy porosity. This study shows that both fractured and vuggy porosity-related types of thief zones can potentially be detected through integration of high-resolution image logs with PLT, NMR, and conventional logs. In addition, methods of estimating fracture permeability and porosity-related permeability based on logs are also proposed. The log-estimated permeability determined using this approach fits better with the production profile and can then be used to evaluate the thief zones in a more quantitative manner.
Completion Design for Sandface Monitoring of Subsea Wells
Authors: MacKay S. , Lovell J. , Patel D. , Cens F. , Escanero S.
Published: June 2010

The expense of subsea well intervention often leads to insufficient reservoir information for accurately understanding reservoir connectivity, drainage, and flow assurance. For those wells requiring sand control, an additional constraint is that sandface sensors must be deployed on a separate completion run. The objective of a recent engineering development program was to create a new deployment system that addressed these constraints directly. Instead of individual gauges on mandrels, digital sensors were miniaturized and distributed along a single spoolable bridle. In addition, a novel inductive coupling mechanism was developed to pass power and data from the upper to the lower completion. In a recent subsea deployment in southeast Asia, such a coupler was attached to the top of a sensor bridle and both were deployed as part of an openhole gravel-pack completion. Standard packers and gravel-pack service tools were used. The system became activated when a mating inductive coupler was landed as part of the upper completion. Surface indication of landing was provided by incorporating mechanical feedback into the lower assembly. With the coupler components in position, the tubing hanger was landed into the horizontal tree. Upon activation of the electrical penetrator, high-resolution temperature data were then immediately available across the length of the sandface, which was an industry first for a subsea producing well. No additional penetrations were required in the tree.

Development of this system required coordination from the operator because of the multiple vendors involved in the project. They supervised multiple qualification and system-integration tests performed over the 2-year development period to ensure ultimate success in the subsea deployment.

Field results showed that the mating inductive couplers provided high-efficiency of power transmission so that industry-standard power settings were sufficient to power a bridle with one sensor per joint of screen. The sandface data were available onshore during the cleanup phase, allowing the operator to monitor the cleanup in real time. Once the wells are brought on line, the sandface data will further enhance the interpretation of flow allocation and reservoir drainage.
An Integrated Geomechanical and Passive Sand-Control Approach to Minimizing Sanding Risk From Openhole and Cased-and-Perforated Wells
Authors: Rahman Khalil , Khaksar Abbas , Kayes Toby
Published: June 2010

The source of sand production is the presence of disintegrated sand grains caused by rock failure at the wellbore and/or perforation walls. Decision for appropriate sand-control strategy requires engineering analysis to evaluate timing and severity of sanding over the life of field conditions. Optimizing well parameters such as well trajectory, perforation orientation, and level of drawdown using geomechanical principles can minimize and delay sand production.

This paper presents a geomechanical modeling approach that integrates production history with information from drilling data, well logs, and rock-mechanics tests. A gas field in south Asia with 11 wells and several years of production experience is used to demonstrate this approach. Core-calibrated rock-strength-log profiles are estimated throughout the reservoir depth for all existing wells. A rock-failure criterion at the sandface is developed as a function of in-situ stresses, rock strength, well trajectory, perforation orientation, reservoir depletion, and drawdown. Sanding-evaluation results are calibrated and verified with production data and evidence of sanding in existing wells. Sand-free operating envelopes and sand evaluation logs are then generated for all existing wells and planned infill wells for the life of field conditions. Sand-prone zones and timing of sanding are established as a function of depletion and drawdown for each well, using production forecasts for the rest of field life. For new infill wells, optimum well trajectories, selective perforation intervals, and optimum perforation orientations are proposed to minimize and delay sand production. Recompletion and using passive sand-control methods including selective and orientated perforations are recommended for a number of existing wells.

This paper is expected to provide well engineers with guidelines to understand the principles and overall workflow involved in sand-production prediction and minimization of sand production risk by optimizing well trajectory, perforation orientation, and selective-perforation strategy.
A New Solution To Restore Productivity of Gas Wells With Condensate and Water Blocks
Authors: Bang Vishal , Pope Gary A. , Sharma Mukul M. , Baran Jimmie R. , Ahmadi Mohabbat
Published: June 2010

During production from gas-condensate reservoirs, significant productivity loss occurs after the pressure near the production wells drops below the dewpoint of the hydrocarbon fluid. Many of these gas reservoirs also have some water accumulation near the wells. This adds significantly to the total liquid blocking.

Experiments were conducted using both outcrop sandstone and reservoir cores to measure the effect of liquid blocking on gas relative permeability. A chemical treatment was developed to reduce the damage caused by condensate and water blocking. The treatment is composed of a fluorinated material delivered in a unique and optimized glycol-alcohol solvent mixture. The chemical treatment alters the wettability of water-wet sandstone to neutral-wet and increases the gas relative permeability.

The increase in gas relative permeability was quantified by comparing the gas relative permeabilities before and after treatment. Improvements in the gas relative permeability by a factor of approximately two were observed. The alteration of wettability after the chemical treatment was evaluated by measuring the USBM wettability index of treated reservoir cores. Measurements show that a significant amount of the surfactant is adsorbed on the rock surface, which is important for the durability of the treatment.

Many attempts have been made to develop effective chemical treatments to mitigate the damage caused by condensate and/or water blocking with little success until now under realistic reservoir conditions. Using inexpensive, safe, and effective solvents was one of the keys to the success of our new approach. Other researchers have mostly tried reactive materials that are subject to complications in downhole applications. We use a nonreactive, nonionic polymeric surfactant that has none of these problems and is robust across a wide range of temperature, pressure, permeability, and brine salinity.

We have developed a chemical treatment for liquid blocking that shows great potential to increase production from gas-condensate wells. Compositional simulations indicate that the economics of this treatment process is likely to be very favorable.
SAGD Gas Lift Completions and Optimization: A Field Case Study at Surmount
Authors: Handfield T.C. , Nations T. , Noonan S.G.
Published: June 2010

Gas lift completions for steam-assisted gravity-drainage (SAGD)(1) producers are unique. Conventional gas lift valves and mandrels with a packer completion cannot be used because of the extreme temperatures of the downhole environment. Most lift gas enters the production stream downhole through open-ended tubing or nozzles, which if not properly sized can result in operational issues such as fluid/gas slugging and pressure instabilities that negatively impact the overall lift efficiency.

In 2006, ConocoPhillips conducted a study to design a gas lift system for the Surmont SAGD development that would allow better control of lift gas into the production string. In late 2007, the wells completed with gas lift were placed on production. This paper covers the data-collection effort and analysis completed to determine the efficiency of the two types of gas lift nozzles used in the completions, the methodology for optimization of SAGD gas-lift systems, and recommendations for future improvement.

Background

Surmont, an in-situ oil-sands project, is located approximately 60 km southeast of Fort McMurray in the Athabasca oil sands (Figure 1). This multiphase SAGD project is a 50:50 joint venture between ConocoPhillips Canada Ltd. (CPC) and Total E&P Canada Ltd., with CPC as the operator. The Surmont pilot began injection of steam in 1997. The pilot comprises three SAGD well pairs that use a variety of artificial-lift methods. These wells have been tested to determine the preferred method of artificial lift for the first commercial phase.

Steam injection, for Phase 1A of the commercial development, was initiated in mid-2007. Conversion to full SAGD production followed in late 2007. Phase 1A comprises 20 well pairs in which all the producers have been completed to produce through gas lift for the initial life of the well. Phase 1 (A, B, and C) has a capacity of 3,975 m3/d (25,000 B/D) and is expected to reach peak production in 2012. A second phase is slated for commercial startup before the middle of the next decade. Upon completion and full ramp-up, it is estimated to bring peak production from both phases to 15,899 m3/d (100,000 B/D). Additional phases at Surmont are also under study.
PRISE Validates Resource Triangle Concept
Authors: Martin S.O.. O. , Holditch S.A.. A. , Ayers W.B.. B. , McVay D.A.. A.
Published: June 2010

As conventional gas (CG) resources are depleted, unconventional gas (UG) resources (gas from tight sands, coalbeds, and shale) are becoming increasingly important to US and world energy supply. The volume of UG resources is generally unknown in most basins outside North America. However, in many mature North American basins, UG resources have been produced for decades, and resources and reserves are well characterized. The objective of this work was to determine the quantitative relations between known conventional and unconventional hydrocarbon resources in mature North American basins, with the ultimate goal of using these relations to estimate UG resources in frontier basins outside North America.

We used assessments by the US Geological Survey (USGS), Potential Gas Committee (PGC), Energy Information Administration (EIA), National Petroleum Council (NPC), and Gas Technology Institute (GTI) to evaluate relations among hydrocarbon-resource types in the Appalachian, Black Warrior, Greater Green River, Illinois, San Juan, Uinta-Piceance, and Wind River basins. We chose these seven basins for initial analysis of relations between CG and UG resources because they are mature basins for both conventional and unconventional oil and gas production. To conduct this analysis, we wrote a computer program that we call Petroleum Resources Investigation Summary and Evaluation (PRISE). Input data for PRISE, obtained from published data sources and resource assessments, were values of technically recoverable resources, consisting of the following resource categories: (1) cumulative production, (2) proved reserves, (3) probable and possible reserves and contingent resources (PPC), and (4) prospective resources. We then analyzed these data in each of the seven basins to assess the relationship between conventional- and unconventional-resource volumes.

For the seven basins studied, we found that approximately 10-20% of the total recoverable hydrocarbon resources are conventional oil (CO) and CG, whereas 80-90% of the recoverable hydrocarbons are UG resources. We suggest that the results of this study may be used to estimate recoverable resources from UG reservoirs in frontier basins worldwide, where CO and CG resources are known but UG resources have not been evaluated.
Uncertainty Quantification in Reservoir Performance Using Distances and Kernel Methods—Application to a West Africa Deepwater Turbidite Reservoir
Authors: Scheidt Céline , Caers Jef
Published: June 2010

Stochastic simulation allows generating multiple reservoir models that can be used to characterize reservoir uncertainty. In many practical situations, the large computation time needed for flow simulation does not allow an evaluation of flow on all reservoir models. In this paper, we propose a method to select a subset of reservoir models reflecting the same uncertainty in flow response as the full set. Using the concept of distance, we map the reservoir models to a low-dimensional space where kernel clustering is applied to identify a subset of representative reservoir models of the entire set. Flow simulation and subsequently uncertainty quantification are performed on this subset. A case study is presented of an architecturally complex deepwater turbidite offshore reservoir with large uncertainty in the type of depositional system present.
Experimental Study of Electrical Properties of Oil-Based Mud in the Frequency Range From 1 to 100 MHz
Authors: Patil Parimal A. , Gorek Matthias , Folberth Martin , Hartmann Andreas , Forgang Stan , Fulda Christian , Reinicke Kurt M.
Published: June 2010

Formation-resistivity measurements in boreholes require accurate knowledge about the electrical properties of drilling fluid to exclude any measurement misinterpretations. For many drilling applications, oil-based mud is the preferred drilling fluid because of properties that include excellent shale stability, corrosion inhibition, lubricity, reusability, resistance to contamination, and higher rate of penetration. Although the electrical resistivity of oil-based mud is generally high, it depends on many parameters. We studied electrical resistivity and dielectric permittivity of oil-based muds as a function of frequency and temperature with varying oil and salt content and varying oil/water ratio. Measurements were performed by use of a coaxial test fixture and an impedance analyzer. The accuracy of the measurement system has been determined using standard materials such as air, deionized (DI) water, methanol, n- butanol, and n-octanol. The analysis shows that published models dealing with electrical properties of rocks can be compared well with those of oil-based muds. Resistivity and relative permittivity decrease with increasing temperature and frequency. No clear relationship is revealed between resistivity and water content, but relative dielectric permittivity does depend on water content of oil-based muds. Oil and salt content are of secondary importance. The study shows that the relative dielectric permittivity is related exponentially to the oil/water ratio of oil-based muds, which provides a means of estimating dielectric permittivity of oil-based mud if the oil/water ratio is known.
Control Requirements for Automatic Managed Pressure Drilling System
Authors: Godhavn John-Morten
Published: June 2010

Automatic control solutions for drilling are expected to become widely used in the future. Both basic and more advanced control tools are well established in other communities such as offshore processing facilities and oil refineries. Drilling systems, however, have traditionally been operated manually. There is a great economic potential for the introduction of automatic control providing reduced drilling time, increased regularity, and improved performance, especially for wells with very narrow pressure margins. One example of automated drilling is automatic control of the downhole pressure by topside choking in managed-pressure-drilling (MPD) operations. Narrow drilling margins, especially in depleted reservoirs, ask for highly accurate pressure control.

Statoil applied automatic MPD successfully offshore at the Kvitebjørn field in the North Sea in 2007. This paper presents some MPD results from Kvitebjøm and discusses automatic control requirements for drilling operations. The requirements for MPD operations include a specified accuracy for a set of normal operations, such as rate changes and set point ramping during connections, surge and swab, and some failure operations, such as power loss, gas kicks, and blocked choke. The paper also includes some ideas for the future of intelligent-drilling operations with increasing automation.
Acid-Etched Channels in Heterogeneous Carbonates—a Newly Discovered Mechanism for Creating Acid-Fracture Conductivity
Authors: Mou Jianye , Zhu D.. , Hill A.D.. D.
Published: June 2010

In the acid-fracturing process, the fracture conductivity created by acid etching of the fracture walls is because of the surface roughness created by the acid's nonuniform dissolution of the fracture surfaces. The acid-fracture conductivity is dependent on surface etching patterns, which are determined by permeability and mineralogy distributions. That is, the spatial distribution of fracture roughness affects the fracture conductivity, which cannot be considered in laboratory measurements of acid-fracture conductivity, which use core samples that are too small to observe such macroscale heterogeneities, or in typical acid-fracture simulators, in which the gridblock size is much larger than the scale of local heterogeneities.

An accurate prediction of acid-fracture conductivity necessitates the detailed description of the acid etching profiles on the fracture surfaces, which depend on acid transport in the fracture, leakoff because of local permeability, and acid/rock reactions. In this paper, we developed a 3D intermediate-scale acid-fracture model with gridblock sizes small enough (gridblock sizes comparable to the core-sample size in experiments) and total dimensions large enough (the total dimensions comparable to a gridblock size in an acid-fracture simulator) to capture local and macroscale heterogeneity characteristics. The model predicts the pressure field, the flow field, acid concentration profiles, and fracture-surface profiles as functions of acid injection volume. In the model, we use a front-fixing method (Crank 1984) to handle the irregular, moving boundaries in numerical simulation. Spatially correlated permeability and mineralogy distributions were generated by using a semivariogram model.

The model was validated by comparing simulation results with experimental results from an acid-fracture conductivity cell. With the model, by extensive numerical simulation, we analyzed the relationship among fracture-surface-etching patterns, conductivities, and the distributions of permeability and mineralogy. We also illustrated the formation characteristics necessary for acid to create channel-caused high acid-fracture conductivity. We found that a fracture segment with channels extending from the inlet to the outlet of the segment has high conductivity because fluid flow in deep channels causes a very small pressure drop. Such long and highly conductive channels can be created by acids if the formation has heterogeneities in either permeability or mineralogy or both, with high correlation length in the main flow direction, which is the case in laminated formations.
Model-Based Integration and Optimization—Gas-Cycling Benchmark
Authors: Juell Aleksander , Whitson Curtis H. , Hoda Mohammad Faizul
Published: June 2010

A benchmark for computational integration of petroleum operations has been constructed. The benchmark consists of two gas/ condensate reservoirs producing to a common process facility. A fraction of the processed gas is distributed between the two reservoirs for gas injection. Total project economics is calculated from the produced streams and process-related costs. This benchmark may be used to compare different computational integration frameworks and optimization strategies. Even though this benchmark aims to integrate all parts of a petroleum operation, from upstream to downstream, certain simplifications are made. For example, pipe flow from reservoir to process facility is not included in the integrated model.

The methods of model integration and optimization discussed in this paper are applicable to complex petroleum operations where it is difficult to quantify cause and effect without comprehensive model-based integration. A framework for integration of models describing petroleum operations has been developed. An example test problem is described and studied in detail. Substantial gains in full-field development may be achieved by optimizing over the entire production system.

All models and data in the benchmark problem are made available so that different software platforms can study the effects of alternative integration methods and optimization solver strategy. The project itself can, and probably should, be extended by others to add more complexity (realism) to the reservoir, process, and economics modeling.
Surfactant-Assisted Synthesis of Metal-Phosphonate Inhibitor Nanoparticles and Transport in Porous Media
Authors: Zhang Ping , Shen Dong , Fan Chunfang , Kan Amy T. , Tomson Mason B.
Published: June 2010

A surfactant-assisted synthesis route was developed to form nanometer-size metal-phosphonate particles. The purpose is to develop a new treatment method for scale control. Aqueous solutions of calcium chloride and zinc chloride were mixed with a basic solution of either diethylenetriamine-penta (methylene phosphonate) (DTPMP) or bis-hexamethylenetriamine penta (methylene phosphonate) (BHPMP) in the presence of tetradodecylammonium bromide (TTAB) or sodium dodecyl sulfate (SDS) surfactant to form nanometer-size particles. The physical and chemical properties of the fabricated nanoparticles have been evaluated carefully. A large number of fabrication procedures are screened, and only those that yield metal-phosphonate particles of 50–200 nm in diameter are evaluated further. Furthermore, these nanoparticles should meet the criteria of forming stable suspension for more than 1 week at 70°C in 2% KCl solution. The nanoparticles can travel through the porous media and be deposited into the formation during a shut-in period. When production resumes, the inhibitor nanoparticles are dissolved into the produced fluid to prevent scale formation. The potential application of synthesized nanoparticles in scale treatment in oil fields has been tested by laboratory squeeze simulations, in which the nanoparticles were placed a distance away from the injection port, retained by the porous media, and returned slowly during flow-back with synthetic brine. The retention and long-term-flowback performance of metal-phosphonate particles is reported.
Development of a Methodology for the Optimization of Dehydration of Extraheavy-Oil Emulsions
Authors: Dalmazzone C. , Noik C. , Glénat P. , Dang F.
Published: June 2010

With the increasing development of heavy- and extraheavy-oil (EHO) fields, separation operations are becoming increasingly challenging compared to separation for conventional oil fields. For in-situ bitumen, EHOs produced by thermal-process dehydration require solvent addition, injection of a large amount of demulsifier additives, relatively high operating temperature, and long retention times inside the separators. So, in order to respect specifications on crude oil and water quality at lower cost, an optimization of the different parameters involved in the whole process of separation becomes necessary.

In the case of EHOs, the presence of polar heavy components, such as asphaltenes, structured as a rigid film at the water/oil interface, limits the coalescence phenomena and, consequently, limits the efficiency of separation by gravity or by using conventional electrocoalescence.

The paper presents a methodology that permits the optimization of water and oil separation in the case of an in-situ EHO (produced by thermal process). The crude oil was first characterized in terms of rheological behavior and interfacial properties. The dilatational viscoelastic properties of the interface were determined from measurements performed with an oscillating oil-drop tensiometer. Properties of emulsification were also investigated by using a specific device called a dispersion rig that allows the reconstitution of crude-oil emulsions under controlled hydrodynamic conditions. Then, a laboratory procedure based on electrical stability tests (ESTs) was applied to optimize the concentration of demulsifier required for effective water separation.

Finally, the optimal electrical parameters were determined in an electrocoalescer device in the presence of the selected concentration of additive. The efficiency of coalescence was measured by following the growth of dispersed water droplets inside the emulsion using differential scanning calorimetry (DSC).

This methodology may be used advantageously as a useful base for further scaleup studies concerning field separation facilities.
How To Apply the Flow Velocity as a Design Criterion in RPM Treatments
Authors: Stavland Arne
Published: June 2010

The effect of water control using relative permeability modification (RPM) depends strongly on the well's flow rate because the permeability reduction decreases as the flow velocity increases. This will affect the volume and the properties of the injected RPM fluid. This paper discusses how the velocity-dependent permeability reduction can be accounted for in the job design. The approach is to introduce a velocity-dependent permeability reduction and to solve the Darcy law for non-Newtonian flow.

Coreflood experiments report permeability reduction as residual resistance factors (RRFw and RRFo). In scaling up to field situations, the reduction in productivity is a better measure. Designing an RPM treatment to a fixed reduction in water productivity demonstrated that low-volume, high permeability reduction is better than larger volumes with lower permeability reduction. In highly productive wells, there may be situations where certain RPM systems fail to reduce the water productivity adequately. By including pressure constraints on the injection of the RPM fluid, the planned pumping schedule is derived.

The criteria for increased oil production are reported as a balance between (1) increased drawdown based on the water-cut reduction and improved lift and (2) reduction in oil productivity. The critical oil productivity depends on the water productivity, initial water cut, density difference between the water and the hydrocarbon phases, and true vertical depth (TVD). It is clearly demonstrated that the potential for increased oil production increases by increasing the ratio between the oil- and the water-productivity reduction (M). In addition, M increases as RRFw increases and the treatment volume decreases.

The time to restore the productivity from the oil zone, the cleanup time, can be understood through the fractional-flow theory. In theory, the cleanup time can be derived from relative permeability curves or the saturation profiles during the oil back production. Also, the cleanup time was reduced by the use of low-volume, high water-permeability reduction.
Milling of Permanent Bridge Plug Performed Successfully on Wireline
Authors: Stragiotti Stephen , Andersen Øyvind , Karlsen Ole Eddie
Published: June 2010

A technological breakthrough within the application of wireline technology has been achieved. In August 2008 on an offshore platform on the Norwegian continental shelf, a wireline tractor and a new wireline milling system were used to mill and remove a permanent bridge plug at 4,147 ft measured depth (MD).

The operator decided to mill out the plug on electric wireline and worked closely with the service company to develop this novel solution. Having developed and tested several bits and milling tools, results showed that by combining the wireline miller with hydraulically provided weight on bit (WOB), it would be possible to mill out the retaining rings of the plug, which would cause the plug to collapse. The milling-control unit allows the WOB to be adjusted for each application and also controls the reactive torque—the force generated when the milling bit engages the plug.

The service company was able to develop the solution within the client's parameters and in accordance with the timeline set out for this project. The offshore operation was completed in 3 days, to the operator's satisfaction.

In another platform well, a permanent bridge plug had been set in 2003 in the sealbore between two screen sections [3-ft seal- bore, 67° well angle, 4.75-in. inner diameter (ID)]. The plug was set in order to isolate the somewhat higher water cut in the lower reservoir zone to prolong oil production from the well. In 2006, the well drowned after a 2-week-maintenance period. Two years later, a coiled-tubing (CT) gas lift operation was carried out with good results. It was then decided to remove the permanent bridge plug to reopen for production before another CT gas lift operation was carried out. A method for milling the permanent bridge plug was developed on the basis of lessons learned from the other plugmilling operation and by extensive testing at the service company's facilities. The operation was completed successfully in 13 days.

This new application for milling completion hardware and other wellbore obstructions offers a cost-efficient alternative to existing methods. The success of the milling operation is a significant achievement and has pushed the limits for what is possible on electric wireline.

This paper will examine two cases of milling bridge plugs on electric wireline and the technical challenges that had to be overcome in offshore operations.The first case used the well stroker as WOB, and the second cased used the well tractor as WOB.
Pore-Network Modeling Dedicated to the Determination of the Petrophysical-Property Changes in the Presence of Reactive Fluid
Authors: Algive Lionnel , Bekri Samir , Vizika Olga
Published: June 2010

A pore-network model (PNM) is an efficient tool to account for phenomena occurring at the pore scale. Its explicit 3D network of pores interconnected by throats represents an easy way to consider the topology and geometry effects on upscaled and homogenized petrophysical parameters. In particular, this modeling approach is appropriate to study the rock/fluid interactions. It can provide quantitative information both on the effective transport property modifications caused by the reactions and on the structure evolution resulting from dissolution/precipitation mechanisms.

The model developed is based on the resolution of the macroscopic reactive transport equation between the nodes of the network. By upscaling the results, we then determined the effective transport properties at the core scale. A sensitivity study on reactive and flow regimes has been conducted in the case of single-phase flow in the limit of long times.

It has been observed that the mean reactive solute velocity and dispersion can vary up to one order of magnitude compared with the tracer values because of the concentration-profile heterogeneity at the pore scale resulting from the surface reactions. As for the reactive apparent coefficient, when the kinetics is limited by the mass transfer, it can decrease by several orders of magnitude with regard to that calculated by the usual perfect-mixing assumption. That is why scale factors should be added to the classical macroscopic transport equation implemented in reservoir simulators to predict accurately the reactive flow effects. For each study case, we also obtained the permeability variation vs. the porosity evolution in a physical way that accounts for reactive transport conditions. It appears that the wall-deformation pattern and its effect on petrophysical properties must be explained by considering both microscopic and macroscopic scales of the reactive transport, each one governed by a dimensionless number comparing reaction and transport characteristic times.

This work helps improve the understanding of surface-reactions effects on reactive flow on the one hand and on permeability and porosity modifications on the other. Using the PNM approach, scale-factor parameters and permeability-vs.-porosity relations can be determined for various rock types and reactive flow regimes. Once integrated as inputs in a reservoir simulator, these relations form a powerful and convenient means of enhancing the modeling accuracy of the change in petrophysical properties during injection of a reactive fluid, such as brine rich in carbon dioxide (CO2).
A Placement Model for Matrix Acidizing of Vertically Extensive, Heterogeneous Gas Reservoirs
Authors: Nozaki M.. , Hill A.D.. D.
Published: June 2010

A critical issue in matrix acidizing of vertically extensive carbonate reservoirs is the acid distribution along the wellbore. This estimation is very important, especially for the case where the reservoir properties (permeability and damage distribution) vary along the wellbore. Several acid-placement models for oil reservoirs have been developed and applied in the field successfully. However, when evaluating acidizing in a gas well, the models are not adequate because of the viscosity contrast between the reservoir fluid (gas) and the injected fluid (acid) and because of relative permeability effects. We have developed an acid-placement model for acid injection into vertically extensive gas wells in heterogeneous carbonate reservoirs that includes gravity segregation in the wellbore, viscosity contrast, relative permeability effects, and a wormhole model. The effects of all these factors on the local injectivity during acid injection are incorporated into a dynamic-skin-factor model.

To test this new model, we analyzed coreflooding data in the literature. The analysis showed that differential pressure across a gas-saturated core did not linearly drop during acidizing, but instead increased during a large part of the acid-injection period. From this analysis, we determined that the pressure drop in a spent-acid zone ahead of the wormholes dominates the overall pressure-drop behavior.

Applying this model to typical field conditions, we find that a natural viscous diversion takes place in heterogeneous gas reservoirs because of the viscosity contrast between the gas and the injected acid. In particular, we have modeled thick carbonate gas reservoirs having a few thin, very-high-permeability thief zones. Before worm-holes break through the damage zone in the high-permeability parts of the reservoir, this viscous-diversion effect distributes acid more uniformly than expected. However, after wormholes break through the damaged zone, thief zones will take a large portion of the injected acid. Another important prediction with this model is that the injection pressure often increases during acid injection into gas wells. Without an understanding of the role of mobility contrast in the injection-pressure response, operators may conclude incorrectly that the injected acid is not stimulating the formation.
Three-Phase Flash in Compositional Simulation Using a Reduced Method
Authors: Okuno R.. , Johns R.T.. T. , Sepehrnoori K..
Published: June 2010

CO2 flooding at low temperatures often results in three or more hydrocarbon phases. Multiphase compositional simulation must simulate such gasfloods accurately. Drawbacks of modeling three hydrocarbon phases are the increased computational time and convergence problems associated with flash calculations. Use of a reduced method is a potential solution to these problems.

We first demonstrate the importance of using three-phase flash calculations in compositional simulation by investigating difficulties with two-phase equilibrium approximations proposed in the literature. We then extend an algorithm for reduced two-phase flash calculations to three-phase calculations and show the efficiency and robustness of our algorithm. The reduced three-phase flash algorithm is implemented in a multiphase compositional simulator to demonstrate the speed-up and increased robustness of simulations in various case studies.

Results show that use of a two-phase equilibrium approximation in reservoir simulation can result in a complete failure or erroneous simulation results. Simulation case studies show that our reduced method can decrease computational time significantly without loss of accuracy. Computational time is reduced using our reduced method because of the smaller number of equations to be solved and increased timestep sizes. We show that a failure of a flash calculation leads directly to reduced timestep sizes using the UTCOMP simulator.