bluuebunny/crossref_metadata_2025 huggingface dataset:
Balancing Lithology and Low-Pressure Hydrocarbon Effects: Evaluation of Low-Pressure Reservoirs Utilizing Magnetic Resonance in the Alaska Cook Inlet
Authors: Toumelin Emmanuel , Voorhees Brent , Shafer David , Jebutu Segun , Manning Michael , Coope Daniel
Published: October 2009

Two mature offshore fields, Granite Point Field and Grayling Gas Sands, were recently re-drilled in the Alaska Cook Inlet where oil and gas are accumulated in thousands of feet of lower-Tertiary, stacked fluvial sand/shale/coal cycles. Common challenges in the two fields suggested their characterization could be improved with nuclear magnetic resonance (NMR) logging, namely: detection of conglomeratic sands, deciphering of complex neutron/gamma-ray responses, quantification of gas saturation, and even detection of low-resistivity pay. However, these formations exhibit properties that limit classic NMR logging interpretation, including abnormally high T1/T2 ratio, high free-fluid T2 cutoff, and low pore pressure. Low-gradient LWD NMR was employed to evaluate the new wells and solved these challenges.

Given the low gas pressure, traditional gas identification using dual wait times or high-relaxation cutoff was ineffective and a density/magnetic resonance (DMR) method was used to quantify gas in place. This method led to substantial porosity corrections, compared to usual practices. Low-resistivity gas zones were also clearly delineated regardless of gamma-ray and neutron lithology effects. Main lithology (sand, conglomerate) could then be inferred from the corrected formation properties by comparison with documented trends from legacy core data.
Accuracy of Fluid Property Estimates for Calculating Seismic Properties
Authors: Sutton Robert P. , Hamman Jeffry G.
Published: October 2009

Modeling seismic responses in reservoir rock requires the accurate determination of fluid density, modulus or its reciprocal, the adiabatic compressibility and acoustic velocity. The geophysics community has developed methods to estimate these properties for subsurface oil and gas accumulations at reservoir conditions. Similarly, the engineering community has developed methods to estimate density and isothermal compressibility. The goal of both groups is the accurate characterization of these PVT properties at elevated pressure and temperature especially at the extreme conditions encountered in frontier reservoir environments and newer discoveries and for the quantitative interpretation of 4D seismic. A large and diverse database consisting of 1099 worldwide oil PVT reports with 11,960 density measurements was used to evaluate the various fluid property correlations. The database encompasses oil with API gravity ranging from 10.6-63 along with solution gas-oil ratios of 5-4,631 SCF/STB resulting in saturation pressures ranging 60-10,326 psia at temperatures over the range 50–332 °F. The PVT reports provide a measure of isothermal compressibility; therefore, heat capacity ratio must also be addressed in the comparison with adiabatic compressibility methods. In this work, gas property correlations were tested against methane PVT data derived from the National Institute of Standards and Technology (NIST) which ensured consistent results over a wide range of pressure and temperature conditions. The principle of corresponding states can then be used to examine the suitability of using these correlations for gas-condensate systems. Results of the study detailing the accuracy of the oil and gas PVT correlations are presented.
New Class of Logging While Drilling Tools Extends Possibilities for Trajectory and Stratigraphic Control While Drilling in Deep, HT/HP Wells
Authors: Mazzoni S. , Borghi M. , Affleck G. , Christie R. , Troiano M.
Published: October 2009

The positive experience and results obtained by using a new class of high temperature / high pressure (HT/HP) logging while drilling (LWD) tool in a slimhole (5-3/4-in.) exploration well in Italy's Po Valley opens new possibilities for trajectory and stratigraphic control while drilling in deep, HT/HP wells. Using the LWD suite, the operator was able to acquire real time, continuous temperature, gamma ray and resistivity data for analysis and correlations at 180°C (356°F) and 16,780 psi – conditions previously unachievable. As a result, the operator pinpointed the stratigraphic position of a main direct fault that raised the upper reservoir above the prognosis estimation and was able to: achieve critical placement of the casing shoe to avoid a well control hazard posed by drilling into a partially depleted reservoir;drill continuously without having to pull the bottomhole assembly out of the hole and change bit types for better, unaltered cuttings; andidentify a carbonate sequence in the lower section, which ultimately led to the decision to plug and abandon the lower section and produce the upper reservoir, with very good results.

Real time annular temperature measurements provided accurate temperature data for mud program optimization and operational considerations that are not usually available in exploration wells.

This paper will discuss the characteristics and operating limitations of the Villafortuna-Trecate HT/HP field; the objectives of the Cascina Cardama 1 Dir well; the LWD planning and implementation, and the operations, logs and results.

Based on the experience and results of this well, the operator will continue to use the high temperature LWD suite to drill future wells and projects.
Predicting Relative-Permeability Curves Directly From Rock Images
Authors: Silin Dmitriy , Patzek Tad
Published: October 2009

The objective of this study is determination of relative permeability curves from an analysis of the pore space geometry. The main assumptions are that the capillary pressure determines the fluid distribution and the rock is water-wet. Maximal inscribed spheres computations characterize the portion of the pore space occupied by each fluid at a given saturation. Numerical solution of the Stokes equations evaluates the pore-scale flow field, which is averaged to estimate the permeability to each fluid. The computed relative permeability curves are in good agreement with published data.

The input for the proposed procedure can be either a computer tomography image of a sample of the rock of interest, or a computer-generated image based on depositional simulations. Partitioning of the entire domain into parts significantly improves the convergence and makes feasible implementation of the computational procedure on a desktop computer. The stability of the results with respect to the choice of computational parameters makes the proposed method suitable for routine applications. The model admits generalizations relaxing the requirement of water wetness of the rock. This model can be applied to evaluate the evolution of the rock flow properties under deformation, damage, mineral dissolution and precipitation.
Development of a Successful Chemical Treatment for Gas Wells with Water and Condensate Blocking Damage
Authors: Bang Vishal , Pope Gary A. , Sharma Mukul M. , Baran Jimmie R.
Published: October 2009

Significant productivity loss occurs in gas condensate reservoirs due to condensate and water accumulation near the production well. Our experimental study shows that gas relative permeability decreases by more than 95% due to liquid blockage (high water saturation along with condensate accumulation) and the reduction is even more pronounced in presence of mobile water.

Significant advances have been made during this study to develop and extend a chemical treatment to reduce the damage caused by liquid blocking in gas condensate reservoirs. The treatment is composed of a non-ionic polymeric fluorochemical in a glycol/alcohol or glycol ether/alcohol solvent mixture. The chemical treatment alters the wettability of water-wet sandstone to neutral wet and increases the gas relative permeability. It also reduces the liquid trapping in pores, which increases the relative permeability to oil or condensate and makes the removal of water blockage from treated zone easier. Selection of solvents to deliver the fluorochemical to the rock surface is critical to the success of the treatment, especially in the presence of high water saturation and high salinity brine.

The treatment improved the gas and condensate relative permeabilities by a factor of about 2–4 on liquid blocked outcrop and reservoir sandstone rocks. The improvement in relative permeability after chemical treatment was quantified by performing coreflood experiments at reservoir conditions. The treatment also shows good durability against flowing gas, condensate, brine and solvent.

We have developed a chemical treatment that shows great potential to increase production from liquid blocked gas wells with relatively small treatment volumes since only the near-well region needs to be treated.
A Next-Generation Reservoir Simulator as an Enabling Technology for a Complex Discrete Fracture Modeling Workflow
Authors: Lim Kok-Thye , Hui Mun-Hong , Mallison Bradley
Published: October 2009

We present an innovative workflow for reservoir characterization, gridding, discretization, and simulation of discrete fractures embedded within a single-porosity continuum. This discrete fracture modeling (DFM) workflow provides the capability to realistically model the impact of fractures on recovery without incurring the simplifying assumptions of traditional dual-porosity models. We represent the matrix of the unstructured DFM using 3D polyhedral cells including tetrahedra, pyramids, and prisms. The fractures are represented as polygonal interfaces between matrix cells.

The workflow is enabled by a next-generation reservoir simulator that is designed for robust solution of unstructured grid models. The simulator supports parallel computation on distributed and shared memory machines without manual user intervention. The efficiency of the simulator is due primarily to a parallel linear solver that is designed specifically for unstructured grids. This results in a very efficient and robust reservoir simulator for highly heterogeneous DFMs.

We demonstrate the practicality of this technology by performing a design of experiments (DoE) study that involves a suite of sector models representing multiple discrete fracture realizations of an actual carbonate reservoir. We also show the feasibility of a full-field simulation including over ten thousand discrete fractures, more than a hundred wells, and 3.65 million simulation cells. These simulations are challenging due to the high contrast in matrix and fracture properties, multiphase flow, and the inclusion of complex physics (e.g., rapid gravity segregation in fractures, first- and multi-contact miscibility).

The successful application of the DFM workflow is largely due to the availability of the next-generation technology for reservoir modeling. We could not perform this work using existing simulation technologies designed for structured grids. Our DFM work facilitated the understanding of recovery mechanisms and contributed to business decisions toward optimal development of the carbonate reservoir.
Geomechanical Modeling Helps Designing the Wells in the Neuquén Basin, Argentina
Authors: Araujo Ewerton , Casalis Daniel , Ward Chris , Sheridan Judith
Published: October 2009

This paper shows how a geomechanical model helped to reduce risks and non-productive time experienced in the past in a field in the Neuquén Basin (Argentina) operated by Petrobras Energia S.A. (PESA). Tight hole and stuck pipe were common problems in spite of the tight and strong formations in the field. Gas inflows were also experienced when drilling through the overpressured formations. All these events made the decision of building a geomechanical model for the field in order to optimize the drilling time.

Pore pressure, stresses and mechanical rock properties were constrained based on good quality data set from eight wells. After that, the geomechanical model was validated using the caliper data and drilling experience. A key part of the model building was the estimation of pore pressure using wireline logs, gas inflows during the drilling, production data and minifrac tests. Overpressured zones were identified improving the design of the casing depths for new wells, minimizing the risks of kicks while maintaining the wellbore stability. Based on the remaining uncertainties of the model, an update phase was recommended to be done after the collection of new data such as image logs in the well to be drilled.

After drilling the new well using the recommendations of the geomechanical model, the drilling experience showed that the well was drilled almost without non-productive time (NPT) through the same formations where in the past tight holes and stuck pipes were experienced. A good image data collected in the drilled well showed that the breakouts stayed below the catastrophic limit, confirming that the mud weight was correctly recommended in the phase 1, maintaining the wellbore stability without reducing the ROP. Also, the observed breakout orientation and width confirmed the orientation and magnitude of the maximum horizontal stress constrained in the phase 1.
Proactive Optimization of Oil Recovery in Multilateral Wells Using Real Time Production Data
Authors: Alghareeb Zeid M. , Horne Roland N. , Yuen Bevan B. , Shenawi Shamsuddin H.
Published: October 2009

Smart wells provide great potential to improve the recovery from hydrocarbon resources. Smart wells provide the ability to control uncertainties associated with reservoir heterogeneity. One example is to mitigate unexpected water production due to fractures and hence increase the ultimate recovery. This is achieved by selectively controlling production from multiple laterals. Due to subsurface communication between laterals that have different productivity indices, it is difficult in practice to optimize production from smart wells. The optimization of smart wells involves adjusting parameters including the settings of the downhole inflow control valves (ICV) that act as subsurface chokes.

This paper focused on the reservoir engineering aspects of finding the optimum ICV configuration that optimizes reservoir performance parameters such as recovery factor and net present value. Also, the work studied the effect of heterogeneity, mainly fractures, on the optimization process. This paper also proposes a technique to quantify the effect of fractures on the optimization process and to provide recommendations of further analysis.

Genetic algorithm (GA) was used as the main optimization engine to find the optimum ICV configuration. The GA was accompanied by a data library (proxy) to reduce the number of required simulation runs. A commercial reservoir simulator was used as the objective function evaluator that assesses the outcome of candidate ICV configurations.

Several examples are presented to show the improvement in reservoir performance made using the optimization process. These examples include a synthetic model, and a real onshore model. Various objective functions were optimized such as water cut, and net present value.
A Novel Approach to Identifying Refracturing Candidates and Executing Refracture Treatments in Multiple Zone Reservoirs
Authors: Barba Robert E.
Published: October 2009

Refracture candidate selection and treatment execution has always presented four main challenges to the industry when multiple pay zones are involved. The first challenge is determining the underlying cause of the poor production performance (poor reservoir quality, an ineffective original stimulation treatment, or both). The second challenge is the identification of the specific zones with significant remaining reserves that have been poorly stimulated. The third challenge is determining the current reservoir pressure in all of the prospective refracture candidate zones. The fourth major challenge is selectively stimulating the target zones in the wellbore when there are existing perforations above the target zones.

The first and second challenges are addressed using the "Completion Efficiency" (CE) or "Recovery Factor" (RF) techniques discussed in SPE 90483.1 These techniques use an integrated petrophysical, reservoir, and completion model to evaluate well and zone performance. The techniques has been employed on over 3000 zones to date in a wide variety of reservoirs with excellent results. The CE and RF analysis can be supplemented by rate-transient production decline analysis if adequate producing time has elapsed. The third challenge is addressed using selective zone buildup and/or injection tests to obtain reservoir pressure and permeability. The recommended technique uses a service rig and a low rate pump truck, tubing, packer, bridge plug, and a surface readout pressure gauge with downhole shutin. This technique has recently been employed on over 60 zones in the last two years in the Hugoton field in Kansas with excellent results. The fourth challenge is selectively isolating individual perforated intervals for the refracture treatments. The most efficient technique involves the use of openhole packer hardware set inside the cased hole. The openhole packer technology has been primarily deployed in horizontal openhole wellbores to date, however the hardware is readily adaptable to cased holes and has been used on a number of vertical cased holes to date (Table 1). The integration of these proven techniques (CE, RF, downhole shutin surface readout testing, and openhole packer hardware) provides the means to meet all of the main challenges of refracturing multiple zone wells. Field examples are provided to demonstrate the viability of the concept, and a methodology is proposed for "best practices" in the implementation of the techniques.
Lumping and Delumping for Integrated Compositional Modeling
Authors: Rastegar Reza , Jessen Kristian
Published: October 2009

Compositional reservoir simulation of gas injection processes is commonly performed with a reduced number of components to minimize computation time. However, in simulations of downstream processes, more detailed fluid descriptions are required to design and optimize separation processes. To connect up and down-stream processes, delumping approaches have been proposed to deconvolute the well/production streams from a reservoir simulator into a more detailed fluid description. The accuracy of delumping is closely tied to the lumping approach that is used to generate equation of state (EOS) input for the reservoir simulator. To this end, we have previously introduced a flow-based lumping scheme that includes information from the dynamics of a given displacement process into the grouping of detailed components. In this paper, we investigate the accuracy of the delumped production streams from various gas injection processes and compare results from different lumping schemes. We investigate the benefit of applying flow-based lumping schemes in the selection of pseudo-components for compositional reservoir simulation and find an improvement in terms of uniqueness and overall accuracy of the composition of the delumped well streams. Examples are provided from 3D displacement calculations of enhanced recovery by CO2 and separator gas injection for multicomponent reservoir fluids where a substantial amount of PVT data is available (CME, DDE, swelling test and slimtube MMP). Using a commercial reservoir simulator, the delumped compositions of the produced fluids are compared to detailed displacement calculations for three different lumping schemes and two different gas injection processes. We demonstrate that the proposed lumping/delumping strategy provides additional control of the predictive quality over currently available lumping/delumping approaches. In addition, the proposed workflow provides a unique answer to the question of how to lump a detailed fluid description for displacement calculations. A majority of oil fields currently under production as well as new developments are candidates for EOR processes such as gas floods. The approach presented in this paper are directly applicable to the study and design of such EOR processes an offers an improved workflow for integration of up and down-stream processes. This is, to our best knowledge, the first paper that presents a comparison of delumping results for flow-based lumping schemes in the context of gas injection processes in with emphasis on the accuracy of delumped production stream relative to other available lumping/delumping methods.
A Survey of Industry Models for Perforator Performance: Suggestions for Improvements
Authors: Behrmann L. , Grove B. , Walton I. , Zhan L. , Graham C. , Atwood D. , Harvey J.
Published: October 2009

For perforated natural completions, well productivity is dependent on the depth of the perforation tunnels extending beyond the drilling damage (all other things being equal). It is therefore important to accurately predict perforation depth at downhole conditions, in order to enable accurate prediction of well performance.

Most industry penetration models in use today are based largely on laboratory experiments conducted during the 1960's through the 1990's. Over the past decade or so, it has been observed that the accuracy of these models has not kept up with the true downhole performance of modern shaped charge perforators. Furthermore, different models can give quite different predictions of penetration performance of the same perforating system, in the same downhole environment.

To address this situation, the authors have recently conducted an extensive series of laboratory experiments, the results of which are enabling improved prediction of penetration performance in the field. Several hundred modern charges of different sizes have been shot into multiple rock types under simulated downhole stress conditions.

The primary conclusions of this work include: (1) historical penetration models tend to overpredict penetration at downhole conditions; (2) some industry models overpredict to a greater extent than others; (3) the discrepancy is partly due to the industry's continued reliance on performance into surface concrete targets. In addition, we observe that historical models tend to treat all charges equally, imposing the assumption that increased performance in one target (i.e. surface concrete) always and everywhere ensures increased performance in all targets (i.e. various stressed rocks). While this intuitive assumption is proven true as the "rule" on average, we find some significant exceptions. Although these exceptions complicate predictive modeling efforts, they do suggest opportunities to optimize charges for certain targets preferentially over others.

Our conclusions have led to ongoing work including (1) the development of improved penetration models, which rely exclusively on stressed rock, rather than unstressed concrete, performance; (2) the development of perforators optimized for downhole conditions, rather than for surface concrete.
Novel Enzyme Stabilizers for Applications at Extreme High Temperatures
Authors: Samuel Mathew , Mohsen Abdul Hameed , Ejan Aziz Bin , Ooi Yean Sang , Ashraf Shameed , Nasr-El-Din Hisham A.
Published: October 2009

Cleanup of drilling fluid filter cake in long horizontal and multilateral wells is a difficult task. Both mechanical and chemical means (acids, oxidizers, chelating agents, and enzymes) have been used in the field. However, these methods have serious limitations and can adversely affect well performance. Acids and oxidizers are very reactive, but are nonspecific. Enzymes can be used to degrade starch and xanthan polymers. The major limitation of enzymes is their inability to stay active at temperatures above 200°F.

The activity of enzymes at 207°F is less than 10% of their activity at 200°F. Previous studies to increase the stability enzymes were aimed at: (1) changing salinity, (2) changing the source of the enzymes, (3) using additives that alter the conformation of enzymes, or (4) chemically modifying the enzymes. These techniques did not maintain the activity of the enzymes above 200°F. For mudcake removal, enzymes have been used globally at higher temperatures, though their activity is known to be much less than 2%.

This paper examines the use of chemicals that work as a stabilizer for enzymes up to 250°F. Optimized concentrations of this stabilizer not only inhibit the coagulation of enzymes at these high temperatures, but also maintain the activity of enzymes at the high temperatures that are encountered in the oilfield. Laboratory studies on the stability, compatibility, and mudcake damage reversal were conducted with the stabilized enzyme formulation.

Experimental results indicated that the new proprietary enzyme stabilizer is very effective in eliminating the deactivation tendency of enzymes at high temperatures. Conventionally, enzymes coagulate above 140°F and char when exposed to temperatures above 200°F, but in the presence of the stabilizer, this precipitation and burning were not observed. When using an enzyme at high temperatures without the stabilizer, the burned residue accumulated on the surface resulting in a thin film that reduced the permeability of the cake even further. Core flood studies using the enzyme stabilizer showed that this film was not formed, which resulted in a cake with much higher retained permeability.
Improving the Process of Understanding Multiprobe Production Logging Tools From the Field to Final Answer
Authors: Frisch G. , Dorffer D. , Jung M. , Zett A. , Webster M.
Published: October 2009

The newest generation of production logging tools consists of multiple sensors in multiple locations around the wellbore that incorporate 12 resistivity and capacitance probes and six spinners. The capacitance array tool (CAT™) determines the water, oil, and gas holdup in the wellbore. The resistivity array tool (RAT™) determines the holdup of hydrocarbons and water. Likewise, the spinner array tool (SAT™) consists of six bowspring mounted micro-spinners that enable the measurement of the velocity profile. These new tools provide a detailed examination of the flowing fluids in all types of wells, including highly deviated and horizontal wellbores, that is not available with the traditional center sample tools because of the wellbore conditions, especially with fluid segregation. With these 30 measurements, a system of quality control and processing was developed to enable both experienced and non-experienced engineers to determine whether or not the data was correct and valid.

A quick analysis tool was developed to enable the field engineer and company representative to enter raw values from the two holdup devices and calibration values, and to determine the holdups from the two sensors. Similarly, entering the raw spinner counts, cable speed, and estimated spinner slopes into the quick analysis tool will provide an estimate of the velocity profile for the SAT spinners and the other spinners that are run. This quick analysis tool graphically shows the holdups and velocity in an easy-to-understand presentation for people who are not production logging (PL) experts.

After the raw data in the field is validated, a complete analysis is provided. This analysis includes horizontal, vertical, and 3D images of holdup and velocity profiles; continuous displays of flow profiles; and a complete flow analysis consisting of the split of oil, gas, and water rates at both downhole and surface conditions. This PL data can be presented in standard log formats, spreadsheets, and other methods as needed. This process can be modified by either the service company or customer. Several examples are provided that show the capabilities of the new logging tools and the interpretation method used to determine the results.
Residual Trapping of CO2 in Aquifers During the Counter-Current Flow
Authors: Nattwongasem D. , Jessen K.
Published: October 2009

The key challenge of CO2 sequestration projects is to ensure that selected formations will provide for long-term storage of CO2 without significant leakage. This is also the case for sequestration projects in saline aquifers, where substantial evidence must be provided that injected CO2 will remain in the target formation. However, the time-scales that characterize the immobilization of CO2 in aquifers are not yet fully understood. In this paper, we investigate the time scale for post-injection immobilization of CO2 and proposed a new dimensionless time scale that includes the contributions of both capillary pressure and gravity forces. The Bond number (NB) is included in the approach to capture the impact of the relevant driving forces. We use numerical calculations to study the interplay between capillary and gravity forces on the predicted evolution of a well-defined CO2 plume in an aquifer. Scaling analysis for 1D and 2D systems is presented for characterizing the plume behavior in different flow regimes as dictated by the relative magnitude of gravity and capillary forces (Bond numbers). A majority of the previous efforts on scaling analysis has focused on processes that are driven by capillary forces alone. However, for sequestration applications the impact of gravity force may be significant. We demonstrate that plume migration at constant Bond numbers may display very different characteristics as a consequence of phase mobilities. The results of our simulations and scaling analysis apply directly to the planning of CO2 sequestration projects and provide new guidelines for estimating the immobilization time of supercritical CO2 as well as the amount of CO2 that can potentially be trapped in a given aquifer.
Decline Curve Analysis for HP/HT Gas Wells: Theory and Applications
Authors: Ilk D. , Rushing J. A. , Blasingame T. A.
Published: October 2009

This work formalizes the Arps' D and b -parameters using a semi-analytical flow relation for a well produced at a constant bottomhole pressure in an HP/HT reservoir. The semi-analytical formulation is given in rate-time and rate-cumulative forms, and the definitions of the D and b-parameters are derived directly from the semi-analytical form.

The rationale for this work is the over-dependence that many analysts place on the Arps' D and b-formulations (i.e., the original hyperbolic rate-time model), tuned to specific (i.e., constant) values of the D and b-parameters. The purpose of this paper is to establish guidelines for reserve estimations and for production extrapolations in general. The relations developed in this work can be applied to a number of different HP/HT tight gas and shale gas field cases — in this work we validate our proposed procedure with a simulated example and we apply the methodology to a fractured gas well in an HP/HT reservoir. A comprehensive workflow is provided, as well as the relevant details/formulations of the analytical flow solution for HP/HT gas cases. We also provide decline curve plots/plotting functions to yield reserve estimates and production extrapolations.
Localization of Ensemble-Based Control Setting Updates for Production Optimization
Authors: Chen Yan , Oliver Dean S.
Published: October 2009

In the ensemble-based approach to production optimization (EnOpt), a steepest ascent direction is computed from an ensemble of controls to iteratively improve a set of control settings. The method was shown to work well in maximizing field NPV with an ensemble size of 104 on the Brugge SPE comparative test case for closed-loop optimization which had 84 controllable completion intervals (and total 3360 control variables), but performance of the method with smaller ensemble size or on larger problems might be difficult. Without regularization, the cross-covariance between control variables and the objective function is often likely to be dominated by spurious correlations. Because the update to the control variables is proportional to the covariance, spurious correlations will result in poor control settings.

We propose a localization method that updates the control setting to optimize the field production while reconciling information from each individual well. The proposed localization method reduces the effect of spurious correlations for improved performance. The Brugge test case is used as an example to show that with covariance localization much greater efficiency could be achieved through the use of a smaller ensemble.
Subsea Deployment of Instrumented Sand Screens in High-Rate Gas Wells
Authors: Somaschini G. , Lovell J. , Abdullah H. , Chariyev B. , Singh P. , Arachman F.
Published: October 2009

Arrays of miniaturized temperature sensors were deployed in the lower completion of six subsea wells in Southeast Asia. The novel system allowed the operator to perform batch completion of the wells. A mechanical fluid loss control device included in the lower completion and a temporary plug set above the lower completion after gravel packing enabled the operator to return later with the upper completion. Upon deploying the upper completion, acquisition was activated and cleanup data were transmitted, allowing the operator to monitor flow from individual reservoir zones. Subsequently, production data have been transmitted in real time to the operator headquarters from an offshore production platform, allowing continuous reservoir modeling.

Key to the communication success was the use of mating inductive couplers, with the female coupler just below the gravel-pack packer and the mating male coupler at the bottom of the upper completion. This coupler has been proven reliable in the presence of standard field operations. In some cases, there were multiple activations of the coupler, and all were successful.

Success of the overall system required that each interconnecting component and interface work as designed. For example, each temperature sensor was designed to land on a blank section of the sand-screen joint above the coupling. A special coupling clamp secured each sensor. The intersensor spacing was designed to be slightly longer than the longest anticipated sand screen. At each joint, a rig device applied a small S-shaped bend to the cable between the sensors. As the bend was formed, this shortened the intersensor spacing for precise onsite depth adjustment.

Similar attention to detail was expended on cables and rig handling. The cable allowed inline splices using a welded seal technique adapted to this specific deployment, the first field deployment of this technique. Significant effort was expended in weld development and testing, but nonetheless there were opportunities to continuously improve on process components such as cable handling and splice preparation.

The proven robustness of the system has led to alternative completion configurations such as monitoring the sandface of wells using electric submersible pumps for enhanced recovery.
Deepwater Developments: Successful Application of New Technology
Authors: Brandt Håvard , Isaksen Stefan , Friedemann Siri Helle
Published: October 2009

The oil and gas industry continues to explore deep and ultra-deep water development. However, these deep water developments introduce both technical and operational challenges not encountered in more shallow water developments. Further, the industry is continuously evaluating novel technologies, often with limited track records, to enhance the profitability and possible enable some of these technically challenging projects. While rigorous qualification programs often are introduced, there is significant uncertainty related to the performance of these systems.

The opportunities related to applying novel technology can be significant, however the uncertainty related to the reliability of these new systems may be difficult to assess. As a consequence the business impact and commercial performance of adopting these new systems is not fully understood. For conventional systems, Reliability, Availability, and Maintenance (RAM) analysis can successfully be applied to demonstrate the commercial performance of a given concept. A RAM model is a probabilistic simulation model which represents the expected performance of a system or a process. These models can be used to evaluate different development scenarios and assess the expected performance of alternative design options. These models do however require experience data which may be difficult to obtain or justify when applying novel technologies.

To better manage and understand the commercial impact of applying novel technologies, DNV has in cooperation with the industry and with the support from The Norwegian Research Council developed a guideline which combines Technology Qualification and Reliability and Performance Simulation. This process provides a better basis for decision support when evaluating novel technologies, and builds confidence in technology which truly has a strong business potential for a given project. This paper provides an outline of this new work process, and through case examples demonstrate the additional requirements on the technology qualification process required to establish confidence in reliability performance of the novel technology.
Comparing the Benefits: Use of Various Well Head Gas Coning Control Strategies to Optimize Production of a Thin Oil Rim
Authors: Nennie E. D. , Savenko S. V. , Alberts G. J. N. , Cargnelutti M. F. , van Donkelaar E.
Published: October 2009

With an increasing number of smart well applications being installed in the field, more knowledge is required to optimize their operation. This paper compares the benefits of various wellhead gas coning control strategies to optimize production of a thin oil rim. This study is performed within the "Integrated System Approach Petroleum Production (ISAPP)" knowledge center of TNO, TU Delft and Shell.

For this study a field case model is used, which has been validated with field data. The field case is a thin oil rim with a horizontal well. Due to the location of the horizontal well in the oil rim, the well is particularly susceptible to gas coning. Besides gas coning, wax precipitation is a second production constraint. This makes this well challenging to operate. Different production strategies are investigated and compared against each other: intermittent production and continuous production with pressure differential control.

The results of the different production strategies are presented by analyzing the advantages and disadvantages for the different gas coning control strategies, satisfying the given constraint of gas influx. This study reveals the difference in the cumulative production between the two strategies. The use of a closed loop control strategy can lead to a larger oil production in the same amount of time.

This paper shows the viability of using dynamic simulation models to quantitatively assess the benefits of various production optimization strategies. This allows operators to compare emerging smart well technologies, and increase trust in specific technologies that could be of an added value to their operation. Even though much has been published about the potential benefits of a smart field philosophy, few published field cases are available. This paper offers a field case testimony of the comparison of various feedback control strategies for purpose of production optimization.
Proppant Transport in Slick-Water Fracturing of Shale-Gas Formations
Authors: Dayan Adam , Stracener Shaun M. , Clark Peter E.
Published: October 2009

Since proppants were first used in hydraulic fracturing, the question of placement in the fracture has remained, for the most part, unanswered. Prediction of proppant transport is important in both treatment design and post-treatment analysis. The transport process has been studied since the late 1950s and a great deal has been learned from the simple laboratory models used in these studies. There are, however, a number of factors that have been overlooked in these studies that we believe are of primary importance. There are indications that fracturing in gas shale plays can produce complex fracture networks. Little is known about the propensity of the slurry to travel through the network. To examine this question, we have constructed a small one-dimentional fracture model with a bifurcation with each wing having equal length and cross-sectional area. We have also constructed a larger three-dimensional slot model to study the process more complex flow field. Results from the small model indicate that flow into the side slot does not occur below some threshold flow rate. This paper summarizes the work that has been done in the area of proppant transport in settling fluids and reports new data on the transport of proppant in multiple fractures.
A Field Demonstration of a New Chemical Stimulation Treatment for Fluid-Blocked Gas Wells
Authors: Butler Mark L. , Trueblood John B. , Pope Gary A. , Sharma Mukul M. , Baran Jimmie R. , Johnson Doug
Published: October 2009

The loss of productivity due to liquid blockage in gas wells is a common problem. Dropout of condensate from gas and/or water accumulates in the pores of the rock near a producing well or within a hydraulic fracture, causing a significant reduction in gas relative permeability, curtailing production. As a solution to this problem, we have developed a chemical treatment designed to increase flow rates of blocked gas wells. The treatment alters the wettability of the solid surface, minimizing capillary pressure and increasing the relative permeabilities of gas and condensate. In laboratory core flood experiments, application of this chemical treatment increased flow rates by a factor of about 2 for two-phase flow of gas and condensate, gas and water, and gas and volatile oil. To bring this technology from the laboratory into the field, we stimulated a blocked gas well. The initial results of this field trial are reported in this paper and demonstrate the treatment was highly effective.
Haynesville Shale—One Operator's Approach to Well Completions in this Evolving Play
Authors: Pope Charles , Peters Billy , Benton Tim , Palisch Terry
Published: October 2009

The Haynesville-Bossier (HB) Shale is an extensive gas resource that has received significant publicity over the past two years, and is currently being developed by numerous operators. Since the HB is a relatively new play, it is anticipated that there will be many learnings in the future that will further improve well completions. However, the more quickly data-sharing and adoption of best practices occurs, the more effectively this tremendous resource will be developed.

This paper will describe some of the reservoir and completion concerns that have driven this operator's current completion philosophy, particularly as they affect well stimulation. Some of the topics described in the paper include: Consideration of vertical and horizontal wellboresHorizontal lateral placement within the vertical pay sectionOrientation of wellbores with respect to anticipated fracture azimuthFracture stage isolation considerationsPerforation strategyDesign and implementation of hydraulic fracture treatmentsConsiderations to accommodate elevated temperatures and stresses in the frac designManagement of closure stresses on proppant

Hydraulic fractures are the key to unlock the potential of most low permeability shale reservoirs such as the Haynesville Shale, and many drilling and completion decisions must be made to ensure successful placement of the stimulation treatment. Although the approach used on initial wells is expected to evolve with future experimentation and optimization, it is hoped that this early discussion of current design philosophy will be useful to the SPE audience, and allow the industry to optimize their Haynesville completions in a timelier manner.
Bidirectional Downhole Barrier Valve for Lubricator Applications
Authors: Andrews Thad , Sloan Jim
Published: October 2009

Bottomhole assemblies (BHAs) are becoming much longer to carry equipment to the bottom of the hole. In many instances, these BHAs can be many hundreds of feet in length and may need to be passed into a live well. Under traditional conditions, a top-side lubricator is used and mounted directly to the wellhead to contain well pressure as tools are run into the hole. However, with today's longer-length BHAs, it becomes impossible to provide a lubricator with enough length to place on top of the wellhead to run tools.

As a result of the more common use of extremely long BHAs, a solution is desired to provide a barrier valve that is resident in the tubing string that allows the section of tubing between it and the wellhead to act as the lubricator. This barrier valve must be bidirectional in sealing capability to hold pressure from both above and below the valve.

This paper discusses a new barrier valve that can be used as a lubricator valve and has a unique closure mechanism that allows it to seal pressures of 10,000 psi and potentially higher, from both above and below. It is operated hydraulically from the surface via dual control lines with one port used to manipulate the valve into the open position and the other port to manipulate it to the closed position. In this scenario, the valve control system is neutrally balanced and pressure only needs to be applied during shifting of the valve to the appropriate position. In addition, the valve control system is tubing-pressure-insensitive, which allows for extremely low shifting pressures that are typically well below tubing pressure.

This paper presents the design considerations for such a valve. Test results will demonstrate the capabilities of this new valve with respect to high-pressure sealability across the closure mechanism combined with extremely low operating pressures required for valve control.
Worldwide Deepwater Petroleum Exploration and Development Prospectivity: Comparative Analysis of Efforts and Outcomes
Authors: Iledare Omowumi O.
Published: October 2009

The global search for environmentally friendly energy resources is increasing. However, there is a general consensus that fossil fuel resources will remain a significant component of the global energy supply mix and the status of fossil fuels in the global energy economy does not appear ready to change in the near future. Increasing amounts of petroleum resources must therefore be found and developed to meet the global fossil fuel demand growth. Thus, the search for new fossil fuel resources must be extended to more remote areas than in years past. This paper describes qualitatively the primary factors underlying deepwater petroleum exploration and development prospectivity worldwide. The paper evaluates the attractiveness and prospectivity of worldwide deepwater offshore basins using empirical indicators to describe efforts and outcomes. The empirical indicators derived from deepwater specific data from private and public sources show that the expansion in worldwide Deepwater operations is a predictable response to the growth in global oil demand as the finite nature of petroleum resources onshore becomes more apparent to oil and gas operators worldwide. Further, the paper shows that the evolution of deepwater petroleum development is very pronounced around the three Atlantic Basin deepwater zones (Africa, Latin America, and North America--Gulf of Mexico) and that these regions have become an important element of the offshore oil and gas industry.