bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimizing Mature Gas Wells in South Texas—A Team Approach
Authors: Harms Larry , Urlaub John , Carrier Bruce , Cremar Billy 
Published: October 2009

AbstractA multi-discipline team was commissioned to bring the right technology and resources to bear to optimize production in a pilot area (67 mature gas wells) in the Lobo field in South Texas. The team used a more aggressive approach towards artificial lift, minimizing pressure and monitoring well performance. The team's work resulted in a 10% production increase with essentially no decline and 3.2 BCF incremental gas over a 2.5 year period. Details of what was done including increased focus on the natural work team, production monitoring, data collection, well automation, debottlenecking, additional plunger lift installations, siphon strings, foamer use, wellhead compression, lowering field pressure and reducing pressure variability are presented. Overall costs and production results are shown along with results from representative wells.
Intelligent Well Systems—Providing Value or Just Another Completion?
Authors: Sun Kai , Constantine Jesse , Tirado Ricardo , Eriksen Frank , Costa Luiz 
Published: October 2009

Abstract
This work reviews several typical intelligent well systems (IWS) completed, including a gas producer, oil producer, auto-gas lift oil producer, multilateral IWS producer, and horizontal openhole multi-isolation producer. For each case, the wellbore modeling, completion design, choking operation strategies, and estimated performance will be introduced.
Case histories based on the analysis of the well modeling results at the design stage of the IWS completion, including well performance along with real-time data, will demonstrate:
Was value realized by using an IWS? How did the IWS completion, downhole choking, and monitoring contribute to adding value in accelerating hydrocarbon production, managing production allocations, delaying or minimizing water production, increasing recovery, and decreasing CAPEX or intervention costs?
In conclusion, this paper will show how modeling technologies were developed to derive the IWS well and equipment design such as tool selection, customized choking positions, erosion protection, and tubing movement estimation. It will cover lessons learned through our experience in intelligent well systems, including flow modeling, erosion analysis, tool selection, and crossover control, and how we expect the future movement of this technology. to evolve.
A New Approach to Compositional Modeling of CO2 Injection in Fractured Media Compared to Experimental Data
Authors: Moortgat Joachim , Firoozabadi Abbas , Farshi Mohammad Moravvej 
Published: October 2009

Abstract
In a recent PhD dissertation (Darvish 2007), data and modeling are presented from an experiment in which CO2 is injected in a tall vertical core, surrounded by fractures. After injecting CO2 for 22 days, 65% of the oil in place is recovered (and still increasing). However, the modeling with a commercial simulator results in only 12% recovery, despite adjusting parameters. We will discuss inherent flaws in current simulators that impede realistic simulation of CO2 injection in fractured media, even at laboratory scales. These issues include: problems in accounting for phase behavior effects and Fickian diffusion in dualporosity models, and excessive numerical diffusion in all simulators that use the finite difference methods. To improve on these weaknesses, we use a higher-order algorithm based on the combined discontinuous Galerkin, mixed hybrid finite element and discrete fracture techniques. We extend that model here to include a self-consistent model for Fickian diffusion, and time splitting in an improved-implicit-pressure-explicit-composition (IIMPEC) scheme. With this new approach, we can reproduce all experimental results in Darvish (2007). The results further confirm the prospects of CO2 injection for enhanced oil recovery in fractured reservoirs.
Measuring Hydraulic Fracture Growth in Naturally Fractured Rock
Authors: Jeffrey R. G. , Bunger A. P. , Lecampion B. , Zhang X. , Chen Z. R. , van As A. , Allison D. P. , de Beer W. , Dudley J. W. , Siebrits E. , Thiercelin M. , Mainguy M. 
Published: October 2009

Abstract
A field experiment was carried out to measure hydraulic fracture growth in naturally fractured rock. Hydraulic fracture interactions with pre-existing natural fractures, shear zones, veins, and adjacent hydraulic fractures were measured and mapped during the project. Tiltmeter and microseismic arrays were installed to test the performance of these monitoring methods in determining the fracture geometry, which was eventually revealed by the mine-through mapping. The physically mapped fractures were oriented approximately horizontally, perpendicular to the minimum stress direction. They crossed natural fractures and shear zones, but were offset by some shear zones, most often oriented with an approximate 45° dip. The analysis of the tiltmeter data correctly predicted fractures to be horizontal. Microseismic monitoring, although a proven method for imaging hydraulic fractures, did not resolve the fracture orientation or size for conditions at the E48 Northparkes site because of a lack of recorded micro-seismic events. The hydraulic fractures grew through solid rock, along natural fractures and stepped along inclined shear zones. Proppant was distributed throughout the fractures, including in the offset portions. Initial modeling indicates higher treatment pressure and slower extension rate for a stepped 2D hydraulic fracture compared to a straight fracture.
Real Time Diagnostics of Gas Lift Systems Using Intelligent Agents: A Case Study
Authors: Stephenson G. , Molotkov R. , De Guzman N. , Lafferty L. 
Published: October 2009

Abstract
This paper describes a new method to continuously monitor and diagnose the condition of wells producing via continuous gas lift. The paper describes the application of this system in a mature onshore gas lift field in the Western United States and the results obtained therein. A central problem related to the operation of gas lift wells is the ability to identify underperforming wells and to address the underlying issues appropriately and in a timely manner. This problem is compounded by the trend toward leaner operations and relative scarcity of application specific domain knowledge. The purpose of this method is to address these issues by leveraging real time data, gas lift domain expertise and proven steady state analysis techniques in a desktop software application.
This system performs four key functions: monitoring the wells’ condition by collecting data; assessing the meaning of this data; recommending actions for correcting problems and responding to threats; and explaining their recommendations.
The performance of the system has met initial expectations and provided additional unforeseen benefits. This paper sites specific cases which compare agent predictions to expert diagnoses and quantify the benefits of taking the recommended actions. What was found was that while the correct diagnoses of well performance issues was beneficial, the real benefit was in allowing production engineers to analyze a greater number of wells in far less time. To that end, the paper will discuss the role of this system as it relates to the overall production management workflow.
The success of this project has demonstrated that intelligent agents can be used to effectively perform functions which were historically performed by a handful of experts. The paper will discuss key system design features which enable this level of functionality as well as other potential areas where the technology can be extended in the future.
Mechanistic Modeling of Emulsion Formation and Heat Transfer During the Steam-Assisted Gravity Drainage (SAGD) Process
Authors: Azom Prince N. , Srinivasan Sanjay 
Published: October 2009

Abstract
Even in the absence of flow barriers and other reservoir heterogeneities, current SAGD models underestimate heavy oil recovery, and are generally seen to be inaccurate in predicting important production characteristics like steam oil ratio (SOR) and water oil ratio (WOR), when compared against experimental or field data. It has been hypothesized by some researchers that water-in-oil emulsions are formed at the steam-oil interface. It is our premise that transport of these emulsion droplets into the bitumen phase facilitates convective heat transfer resulting in improved recovery. Incorporating these effects is key to accurately modeling the SAGD process.
Unfortunately, the physics of emulsion formation and transport in porous media is not well understood, and current simulators do not have the capability to directly model such effects. A new approach that models the emulsion droplets as chemical species and accounts for the dispersion and adsorption phenomena is implemented in this paper. This model utilizes the features available in most commercial simulators in order to model emulsion generation, propagation and coalescence in porous media. The results from such a mechanistic simulation are compared against published SAGD experimental data. Our results show significant improvement from previous SAGD models and bolster the argument that emulsions are responsible for a key heat transport mechanism during SAGD. The simulation is also being used currently to design laboratory experiments to verify the formation of emulsions and their net effect on heat transfer.
High Resolution, Real-Time Casing Strain Imaging for Reservoir and Well Integrity Monitoring: Demonstration of Monitoring Capability in a Field Installation
Authors: Pearce J. G. , Rambow F. H. K. , Shroyer W. , Huckabee P. , de Jongh H. , Dria D. E. , Childers B. A. , Hall T. S. , Dominique T. 
Published: October 2009

Abstract
Casing deformation can be used as a direct indicator or measurement of reservoir geomechanical strain, such as may occur with
Vertical compaction accompanying pressure depletion of high-compressibility hydrocarbon reservoirs; Vertical strain dilation due to stress arching; Shear events associated with fault movement and reservoir bed boundary movement during subsidence; Localized strain events such as pipe ovalization due to highly anisotropic loading or formation strain anisotropy; and Pressure changes due to depletion of or injection into reservoirs.
Identifying and quantifying these events early can help an operator remedy a potentially damaging production scenario, apply the correct seismic transit time correction during time-lapse reservoir seismic monitoring, or monitor production, injection, and pass-through zones for pressure depletion effects.
We have installed, in an industry first, a high-resolution fiber-optic strain imaging system in a producing well. The theoretical, experimental and early deployment test trial details of this technology were reported in SPE 109941, presented at the 2007 SPE ATCE. In this paper, we will report high-resolution strain monitoring results obtained on a set of casing joints which were instrumented with several thousand fiber-optic strain sensors, deployed as a single fiber cable in an onshore production well, installed using normal rig equipment. Of particular interest at this early stage in the well's life is the demonstration of the strain measurement resolution and sensitivity, as evidenced by our ability to monitor the differential pressure between the inside and outside of the casing while circulating prior to cementing, during the cementing operation and while the cement was curing. This monitoring yielded excellent results while cementing the instrumented intermediate casing string, as well as while cementing the production casing string. Cemented at a measured depth of 8000 feet in an unconventional gas well, the strain-instrumented casing joints in conjunction with a distributed temperature sensor and external pressure gauge have continued to provide strain, temperature and behind-casing pressure readings through the remainder of the well construction, completion, hydraulic fracturing and the current, early production operations some six months after initial installation.
Expandable Tubulars Enable Multi-Zone Frac-Packing in the Open Hole
Authors: York Patrick , Gandikota Raju 
Published: October 2009

Abstract
Investigation is underway to enhance potential production rates by actualizing a method of frac-packing multi-zone slim holes and sidetracks using solid and slotted expandable casing. This innovative technique replaces the production liner and the cementing and perforating phases in a normal completion. The increased completion ID and flow areas provided by the expandable completion allow a significant increase in the frac-pack sand-screen size and associated production tubulars. The expanded completion liner itself offers more than a ten-fold increase in inflow area over a conventional perforated liner. These two factors, when combined, allow both reliable and improved production rates from 6 in. openhole sidetracked sand control wells requiring frac-packing.
By utilizing these expandable slotted completion liners in conjunction with a newly developed solid expandable openhole packer system, the operator can selectively expand discrete production (or injection) zones and, with an appropriate frac-pack screen design, effectively control flow from the individual zones. Using selectively-expandable isolation devices allows the end user to decide their placement after the well evaluation data has been analyzed. This flexibility enables the end user to optimize the effectiveness of the completion.
This paper will review the completion challenges with perforating and frac-packing inside small completion liners or open holes, the available technologies to perform isolation in the open hole, and the process and features associated with an expandable completion run prior to frac-packing. The results of ongoing testing and field trials of the expandable packer system will be presented and analyzed along with supporting modeling and simulation work.
In effect, the new system allows an operator to perform an open-hole frac-pack inside a 6 in. sidetracked hole, obtain higher sustained production rates, and thereby, improve project economics over conventional techniques. This system, in some cases, will allow additional reserves recovery in difficult sand-control environments and revitalize maturing fields.
History Matching by Simultaneous Calibration of Reservoir Geological Models at Pore-Level and Field Scales
Authors: Barrera Alvaro , Srinivasan Sanjay 
Published: October 2009

Abstract
Reliable predictions of reservoir flow response require a realistic geological model of heterogeneity and an understanding of its relationship to flow performance of the reservoir. This paper presents a novel approach for integrating dynamic data in reservoir models that utilizes the probability perturbation approach for the simultaneous calibration of geological models at field scale and multiphase flow functions associated with pore-level spatial representations of the porous media.
In this probabilistic approach, a stochastic simulator is used to model the spatial distribution of a discrete number of rock types identified by rock/connectivity indexes (CIs). Each CI corresponds to a particular pore network structure with a characteristic connectivity. Primary drainage and imbibition displacements are modeled on the 3D pore networks to generate multiphase flow functions, including effective permeability and porosity of the rock, the relative permeabilities and capillary pressure, linked to the CIs. During the assisted history matching, the stochastic simulator perturbs the spatial distribution of the CIs to match the simulated pressures and flow rates to historic data. Perturbation of the CIs in turn results in the update of all the flow functions.
The results from the integrated history matching procedure are presented for a realistic field example. The convergence rate of the proposed method is comparable to other current techniques with the distinction of enabling consistent updates to all the flow functions while at the same time honoring the geological/sedimentary model for the distribution of petrophysical properties. Consequently, the reservoir model and its predictions are consistent with realistic geological processes and the response obtained for the reference model.
Pore-Level Mechanics of Forced and Spontaneous Imbibition of Aqueous Surfactant Solutions in Fractured Porous Media
Authors: Alshehri Amar J. , Sagatov Ernar , Kovscek Anthony R. 
Published: October 2009

Abstract
Water flooding typically recovers about 50% of the original oil in place leaving much oil in the reservoir. Recovery efficiency in fractured reservoirs can be dramatically lower in comparison to conventional reservoirs because water channels selectively from injector to producer leaving considerable oil within the matrix and uncontacted by injected water. An enhanced recovery process is needed to access such oil held in the reservoir matrix. Addition of aqueous surfactants to injection water dramatically reduces oil/water interfacial tension and surfactant may adsorb to oil-wet rock surfaces inducing a shift in wettability that improves the imbibition of water. At the pore level, capillary forces are responsible for oil trapping and generally dominate over viscous and gravitational forces. Because of the reduction in interfacial tension between oil and water with the addition of surfactant, the role of capillary forces on fluid flow can be minimized. When gravity parameters are large enough to give a Bond number (ratio of gravity to capillary forces) greater than 10, gravitational forces become more dominant and oil held with rock matrix by capillarity may be released as a result of buoyancy. In this work, we use experiments conducted in two-dimensional micromodels to investigate the effect of gravity at low interfacial tension. The micromodels have the geometrical and topological characteristics of sandstone and the network is etched into silicon. Porelevel mechanics are observed directly via a reflected-light microscope. A screening study of sulfonate and sulfate surfactants was conducted to choose an appropriate system compatible with the light crude oil (27°API). A variety of flow behavior through the microscope is investigated including forced and spontaneous imbibition. Results are illustrated via pore-level photo and image analysis of microscopic pictures of the micromodel. Forced displacements are conducted at realistic flow rates to maintain a 1 m/day Darcy velocity and at surfactant concentrations of 0.9% to 1.25%. Forced displacement with a horizontal or vertical positioning of the micromodel yields dramatic improvement of recovery for surfactant injection cases. Most of the oil retained after a waterflood was recovered by tertiary injection of surfactant solution. In comparison, about 25% oil saturation remained after a waterflood.
Methodology to Compare Smart and Conventional Wells
Authors: Schiozer Denis J. , da Silva Joäo Paulo Q. G. 
Published: October 2009

Abstract
Smart wells are being used recently to add operational flexibility to petroleum production. Considering offshore fields with water injection, smart wells can be very useful to control water production and to improve oil production. The advantages of smart wells are that they have devices like valves and sensors are able to monitor and control production, in real time, adding flexibility to the operation.
However, the effect of smart wells on the net present value (NPV) of the project has to be carefully quantified because of the additional investments. The expected gain is a function of several parameters, especially operational controls and economic parameters. Therefore, a fair comparison between these two wells requires a methodology of production strategy optimization especially designed to capture the details in the performance of these wells. The differences are even more complicated to be quantified in the presence of uncertainties.
Therefore, the objective of this work is to present an example with a comparison between smart and conventional wells, considering uncertainties in the geological and economic models.
A methodology of production strategy optimization, presented in a previous work (Silva and Schiozer, 2009), considering the availability of different production capacities, is used in this work. The main parameters altered are: position and number of wells, water cut and schedule of well's drilling.
The results showed small differences between the two alternatives. Smart wells were able to improve oil production and reduce water production but, in most cases, the NPV indicated that the use of conventional wells was slightly more advantageous. Also, the operational conditions, such as platform capacities, have a high impact on the results. The results are also very dependent on the economic model and additional investments required to use smart wells.
Assisted History Matching in an Offshore Turbidite Reservoir with Active Reservoir Management
Authors: Rey Alvaro , Ballin Paulo , Chick Vitalis , Park Jeff , Kim Jong-UK , Datta-Gupta Akhil 
Published: October 2009

AbstractStreamline-based assisted and automatic history matching techniques have shown great potential in reconciling high resolution geologic models to production data. Several field applications have demonstrated the efficiency of streamline-based sensitivity calculations together with the generalized travel time inversion (GTTI) for history matching. However, a limitation of the current GTTI based production data misfit calculations is that it is best suited for continuous and monotonic production histories. Field applications very often include active reservoir management decisions that involve well shut-in, recompletions and pattern conversions. These introduce significant discontinuities and non-monotonic effects in the production response.In this paper we propose an efficient and novel technique that handles production discontinuities through a transformation of the production data and by eliminating high frequency details in the transformed domain. The technique also reduces nonmonotonic behavior and results in a response more suitable for the GTTI based misfit calculations. Our proposed approach has been applied to an offshore turbidite reservoir with active reservoir management and highly detailed production information. The static model contains more than three-hundred-thousand cells, complex sand depositional distribution combined with fault structures, four pairs of injector, deviated producing wells and more than 8 years of production history. Previous history matching attempts using traditional approaches had difficulties matching production response at the individual well level. With our proposed modification to the GTTI approach, a significant improvement on the well match quality was obtained. Most importantly, by visualizing the streamlines and the dynamic adjustment of flow paths during history matching, we could easily identify the areas of inconsistency between the geologic model and the production data. The calibrated geologic model suggests communication within sand channels, differences in flow paths and barriers that have not been included in the previous geologic and seismic interpretation.