bluuebunny/crossref_metadata_2025 huggingface dataset:
Field Application of a Water-Based Consolidation System for Remediation of Proppant Flowback
Authors: Cooper J. C. , Nguyen P. D. , Magill D.
Published: February 2011

Post-stimulation proppant-flowback problems have been a major issue in both conventional and unconventional reservoirs. In coalbed methane-gas (CBM) wells that use pumps and plungers to dewater coal, proppant flowback with produced fluid could lead to well downtime because the pumps can get sanded off. This is costly and challenges well economics because losing production and replacing the pumps repeatedly can be expensive. A low-cost solution to this uncontrolled sand production is to clean the well with a workover rig or coiled tubing (CT), identify the zone (or zones) from which the proppant is being produced, isolate the zone (or zones), and pump a remedial proppant flowback-control treatment. Two types of proppant-consolidation remedial-treatment fluids have been successfully used—one is the low-viscosity, solvent-based curable resin, and the other is a new, water-based consolidation system.

A water-based consolidation system was successfully developed to overcome the operational, safety, and fluid-compatibility issues that most current solvent-based resins experience during field treatments. This paper presents the results of laboratory development and field testing of this consolidation system for proppant flowback. Extensive laboratory testing has indicated that an optimum concentration of coating is necessary to maximize the bonding between proppant grains. This allows the proppant pack to withstand high production flow rates and to overcome the effects of stress cycling while minimizing any reduction in its permeability. Field-study results in both sandstone and CBM reservoirs showed that the water-based consolidation system was successfully applied in treating proppant and formation solids in the near-wellbore region to lock them in place without damaging production flow paths. In these field tests, intervals in excess of 300 ft were treated effectively with the bullhead-squeeze method using consolidation treatment fluids that were foamed to a quality of 75% or higher to aid in diverting treatment fluids and extending treatment volumes.

The new system uses small treatment volumes to impart excellent consolidation properties, while at the same time retaining formation permeability. This makes the treatment system simple to deploy and economically viable. In addition to providing the results, this work discusses the criteria for identifying remedial candidates, optimal placement procedures, and the lessons learned from these treatments.
Dealing with Risk Analysis for Integrated Asset Modelling
Authors: Binda A. , Giliberti S. , Preti A. , Rossi R.
Published: February 2011

The evaluation of the risk associated to a development plan taking into account reservoir uncertainty has become a standard procedure. The integrated dynamic simulation of different assets considering mutual dependencies due to the production network is nowadays a standard procedure too. Integrated Asset Models (IAM) are usually simulated with a deterministic approach (one production profile for each network scenario). A methodological approach to take into account uncertainties together with different development scenarios (network and pipeline characteristics, infill wells, work-over...) is described in this paper.

Reservoir numerical models have to be simplified (material balance models instead of full 3D simulations) to manage probabilistic simulations directly in the network facility model.

The main phases of the methodology are:

– Understanding of the asset and its model – Definition and evaluation of reservoirs and asset uncertainties – Simplification of full 3D reservoir models with material balance – Montecarlo simulation via spreadsheet – Statistical analysis of the results

An easy interface link has been developed to manage input and output in an uncertainty environment. The IAM is simulated by applying the standard software used in the company. The interface is able to set as uncertainty any input data defined in the models.

This work-flow was applied on a dry gas offshore asset, which exploits many reservoirs (including multi-stacked sands) tied back to a central processing facility through a common pipeline network.

The applied methodology proved to be manageable in terms of CPU time, effective and reliable.
Openhole Gravel-Pack Case Histories in Wells Drilled With a Synthetic Mud: Successful Implementation of an Alternative Method in Oyo Field, Nigeria
Authors: Ripa G. , Rossi M. , Staltari D. , Ilobi M. , Lawal T. , Beldongar M. , Douglas T. , Wassouf P. , Jones A. , Parlar M.
Published: February 2011

Openhole gravel packing is a popular completion technique in challenging, high transmissibility reservoirs. Many of such wells are drilled with synthetic fluids and completed with either a single- or a two-trip technique.

In single trip approaches, the entire wellbore is displaced to water-base fluids before running screens and subsequent gravel packing. Although successful in some cases, this technique has been problematic in reactive shale environments, due to problems in screen installation to target depth, resulting from shale swelling and/or collapse. Such problems led operators to a two-trip approach, where a predrilled liner is installed in synthetic-base mud (SBM), displacements performed to water-base fluids and the screens are run in solids-free water-base fluids environment, followed by gravel packing. In recent years, another approach was introduced, in which the displacements to water-base fluids are performed after the screens are installed in conditioned mud and the packer is set, followed by gravel packing with a water-base fluid. Although this approach eliminates the difficulties associated with screen installation as well as allowing a single-trip completion (no predrilled liner), it cannot be used in cases where conditioning is impractical.

In this paper, we present case histories, where screens were installed after the openhole was displaced to a solids-free SBM and cased hole to completion brine, and gravel packing was performed using a water-base carrier fluid. This approach provides a cost-effective alternative to displacement of the entire wellbore to solids-free SBM as well as eliminating the risk of screen plugging, and was successfully implemented on two oil producers in Oyo field. Details of design, execution and evaluation for drilling and completion stages, as well as well productivity measures are provided, along with a discussion of a continuous circulation device successfully used during drilling.
Cementing In Unconsolidated Sand West Delta Deep Marine Fields, A Case History
Authors: Farag Hossam , Shaaban Sherif , Eid Ramy , Hesketh Mark
Published: February 2011

Past experiences in the Sapphire location in the Mediterranean, have witnessed wells which suffered damage in various storms; being pulled over to at least 2.5° inclination by the attached riser. With the increasing rental rates for semi-submersibles, the challenge was to cement the conductor casing in highly unconsolidated shallow sands, while eliminating the need for time consuming Top-up jobs, causing rig time loss with hefty rig rates.

The objective was to formulate an unconventional, quick-setting light weight cement slurry, with high compressive strength, thus providing adequate axial capacity for landed-off casing weights., while preventing cement subsidence after placement. Extensive Laboratory testing and Field results indicating the rate of success of this technique will be covered within the scope of this paper.

In this paper, the authors will discuss the cause of the problem, the approach taken forth by all participating parties and the overall approach taken to achieve success in minimizing rig time lost and achieve axial support.

This technique can be applicable for cementing conductor casing in most deep water environments, where very low temperatures are experienced at seabed. The field verified rate of success was mainly attributed to proper data collection and proper testing procedures.
The Development of Subsea Boosting Capabilities for Deepwater Perdido and BC-10 Assets
Authors: Gilyard Dustan , Brookbank Earl B.
Published: February 2011

Significant advancements in deepwater subsea boosting technology, operations, and surveillance are represented by two Shell world-class developments: Perdido in the Gulf of Mexico (that will begin production in 2010) and BC-10 offshore Brazil (on stream since July 2009). These novel projects continue the long tradition of Shell's leadership in the challenging deepwater environment by development and application of a novel seafloor boosting system.

The subsea boosting system utilized by both the Perdido and BC-10 assets for increased ultimate recovery and higher production rates is based on the application of electric submersible pumps (ESP) located in a shallow seafloor caisson. These caissons collect production fluids from the manifolded subsea wells and prevent significant loss of ESP performance due to excessive gas production by passive liquid/gas separation.

Extensive testing and qualification of the subsea boosting system was undertaken prior to final configuration selection including construction of the world's only 1500-hp ESP test facility capable of controlling multi-phase fluid viscosities and temperatures. A comprehensive suite of tests was performed in conjunction with Baker Hughes Centrilift replicating the expected conditions and performance requirements for both deepwater assets. This paper describes the subsea boosting system maturity process, and discusses the current status of each development and related key learnings.
Pushing Portland Cement Beyond The Norm Of Extreme High Temperature
Authors: Doherty Dale R. , Brandl Andreas
Published: February 2011

For a recent project in Australia, Portland cement was modified to withstand contact with temperatures above 800 °C. This High Temperature (HT) cement system is applied to cement casing strings used as injection and production wells in a process known as Underground Coal Gasification (UCG). In its simplest form, this process involves drilling a production well and an injector well into an existing coal seam. Once drilling and cementing of the wells are complete the coal is ignited underground, and air and water are then introduced through an injector well. The air reforms with the combustion materials and forms a synthesis gas (syngas) containing carbon monoxide, hydrogen and methane (as a minor component), that moves under pressure through the coal seam to the production well, where it travels uphole to the downstream facility. Since coal typically resides at shallow depths, it was necessary to have cement that would set at relatively low bottomhole static temperatures of less than 39 °C and have the ability to withstand the extreme temperatures of the advancing combustion front, which can exceed 800 °C.

Portland cement with a silica source has been used in geothermal wells in which production temperatures can reach 380 °C or more, but recent testing showed that it can completely disintegrate around 450 °C. The final HT cement system design easily tolerates the elevated dry temperatures at the combustion front and maintains compressive strength in normal API compressive strength (CS) tests at 350 – 450 °C. The slurry mixes and pumps in the field as one would expect any slurry properly prepared to do while following API methods. Fluid loss control was adjusted with common liquid additives. Since the welfare of our planet is dependent on our ability to develop more environmentally friendly alternatives, the UCG process may become the preferred method to extract the energy contained within coal. The new HT cement system design enables a cost- efficient, logistically simple cementing method/material for this application where none existed previously.
Rapid Assessment of Potential Recovery Factor: A New Correlation Demonstrated on UK and USA Fields
Authors: Wickens Laurence M , Kelly Roy
Published: February 2011

A new correlation between recovery factor and a reservoir complexity index has been developed and is demonstrated on UK and USA fields.

The correlation allows rapid assessment of the potential recovery performance of reservoirs. It also enables the extent of reservoir underperformance to be assessed. The applications of this approach extend from a rapid evaluation of a field when time is limited to a comparison of fields for benchmarking purposes. The correlation includes a number of key parameters such as in-situ viscosity, structural compartmentalisation, reservoir heterogeneity and may be easily expanded to include other parameters as necessary.

Results are presented for a large number of identified UK and USA fields with a wide range of complexity and a variety of reservoir and fluid types. This information helps structure comparison of specific fields with others and facilitates the development of analogues. The data shows a clear upper limit to reservoir performance for a given reservoir complexity.

Detailed information on the fields in the form of a complexity index is published, enabling others to use and further develop the approach and add their own data.

The approach extends aspects of a previously published complexity index. It is based on sound reservoir engineering parameters that minimize the problems associated with qualitative judgments of parameter values.
Inversion of Surface Subsidence Data to Quantify Reservoir Compartmentalization: A Field Study
Authors: Fokker P. A. , Visser K. , Peters E. , Kunakbayeva G. , Muntendam-Bos A. G.
Published: February 2011

The Roswinkel gas field in the northeastern part of the Netherlands has been in production between 1980 and 2005. Located at about 2100 m depth, it is a severely faulted anticlinal structure, constituting up to 30 reservoir compartments. Due to the complicated nature of this field, there are large uncertainties in both the fault transmissibilities and the strength of the connected aquifer. Consequently, there is a possibility of undepleted compartments in the reservoir.

Pressure depletion due to gas production results in compaction of the reservoir sandstones leading to surface subsidence. The gas production in Roswinkel has induced subsidence of approximately 17 cm above the centre of the field. The subsidence at any point on the surface is a result of compaction over a large area within the reservoir.

We estimated the compaction in the reservoir using subsidence data in order to reduce the uncertainties in fault transmissibility and aquifer connection. We employed a previously developed Bayesian inversion method in which prior knowledge is combined with observations. The prior knowledge on the compaction and the associated uncertainties were generated by Monte Carlo simulations of the reservoir in which the fault transmissibilities were varied. In the mean time the geological reality was maintained and the production history was honored. The average prior compaction field is a relatively smooth field extending well into the aquifer, with a typical uncertainty of 40%.

Our inversion results show a reservoir in which certain large faults are dividing the reservoir in compartments containing different pressure histories. Furthermore, the aquifer activity appeared to be much weaker than the average prior knowledge suggested. The posterior uncertainty of the compaction levels was reduced to about 10%. Our study demonstrates that a carefully executed inversion exercise can considerably reduce uncertainties, thus giving scope for the identification of undepleted compartments in the reservoir.
Sand Prediction: A Practical Finite-Element 3D Approach for Real Field Applications
Authors: Volonté G. , Scarfato F. , Brignoli M.
Published: February 2011

Sand production is a critical issue in Oil & Gas industry. During the production of a well, sand production may have negative consequences such as risk of well failure, erosion of pipelines and surface facilities and need for sand separation and disposal. Knowing the conditions for the onset of sand production allows optimizing sand free production and, eventually, avoiding or delaying the use of sand control methods.

The aim of this work is to establish a reliable workflow for the estimation of the conditions for sand production, in real field cases, by means of Finite Element Modelling. With this respect, the fundamental requirement is to set-up a 3D coupled model that can be easily adjusted the most complex conditions (e.g. stress anisotropy, deviated wells, complex perforations patterns).

The most suitable geometries and associated meshing strategies to describe the wellbore, the perforation tunnels and the surrounding formation are analyzed. The drilling and completion phases were also simulated to compute the correct stress distribution before the production. Fluid flow and rock deformation are simulated in a fully coupled way to investigate accurately the effect of drawdown.

Shear failure of reservoir rock, considered as an elasto-plastic medium, is the main sand production mechanisms analyzed and the damage of the rock around the perforations is evaluated by analyzing the distribution of the equivalent plastic strain.

A real field case is simulated and the results of the Finite Element model are consistent with the ones obtained by means of an analytical model and with field observations. Moreover, this numerical approach allows quantifying the spatial distribution and the severity of the damage of the rock around the perforations, facts that are either oversimplified or not considered at all in analytical models.

For future applications, this model can be straightforwardly extended to more complex conditions and can also be improved to provide volumetric sand prediction.
Enhanced Seismic Velocity Processing to Improve 3D Geopressure Evaluation
Authors: Cibin Patrizia , Della Martera Mauro , Andreoletti Clara , Bellucci Niccolò
Published: February 2011

Geopressure evaluations are key considerations for successful well planning and drilling. The necessity to satisfy the world needs of oil & gas presses Oil Companies to drill in conditions that are getting harder and harder in terms of geopressure environment. The pore pressure prediction accuracy has a large impact on the cost of a project and is especially critical for drilling high-temperature/high-pressure (HP/HT) wells where there is a small margin between pore and fracture pressures. This paper outlines the most accurate methodologies to estimate seismic velocities to be used for the pore pressure prediction.

In exploration, pore pressure prediction is critical for the evaluation of vertical and lateral sealing, the estimation of maximum possible column of hydrocarbons in place, and consequently to rank the prospects and evaluate the economics. As far as concerns drilling, the geopressure information is important to define the best well design in order to reduce costs, NPT (Not Productive Time), wellbore stability, sand production and reservoir damages.

Generally, in complex and deep areas, conventional velocity fields derived from seismic time processing are often not accurate enough to make a correct pore pressure prediction. For this reason, several methods have been developed trying to obtain more appropriate velocity fields. In this paper we compare some of them, mainly CVA (Continuous Velocity Analysis) calculated in the time domain versus Grid Tomography, applied in the depth domain.

In particular, Eni proprietary software based on reflection tomography, able to integrate geological information in the Grid Tomography loop, has been successfully applied in North Africa, where the exploration goal is to reach deep HP/HT targets. Besides, in that region, strong pressure anomalies and pressure compartments are frequently present in the shallower layers, due to compaction disequilibrium and vertical pressure transfer along faults or through windows in salt layer.

These phenomena have created serious problems during drilling operations in the past and a good geopressure prediction can considerably reduce drilling costs and risks. The application of the proposed methodology to build the seismic velocity field has been important both in defining more detailed pore/over pressure volumes and structural models by an iterative pre stack depth migration workflow.
Potential Upside Reserves of Shallow Gas Discovered Within the Early Triassic Mount Goodwin Sub-Group and the Early Permian Torrens and Fossil Head Formations in the Blacktip Gas Field, Bonaparte Basin, Australia
Authors: Wheller Dave , Caudullo Andrea
Published: February 2011

The Blacktip Gas Field is located offshore in the southern Bonaparte Basin, Australia. The main reservoirs are the Early Permian Keyling and Treachery Formations. The field supplies gas to the Northern Territory utility Power and Water Corporation from two deviated gas production wells via an unmanned well-head platform to shore at Yelcherr near Wadeye in the Northern Territory. The field will deliver gas to the Northern Territory's Power and Water Corporation over a period of 25 years.

One of the potential upsides of the gas field is the shallow and previously overlooked Early Triassic Mount Goodwin Sub-Group sandstones and also the Early Permian Torrens and Fossil Head Formations. Eni successfully acquired more data from the drilling of the development wells over these sections, with the objective being to fully assess minor gas shows observed in the original Blacktip-1 discovery well.

The Mount Goodwin Sub-Group Sandstones, Torrens Formation and Fossil Head Formation are a thick sequence of inter-bedded shale, siltstone and very fine sandstones. The intervals are thinly bedded, and this makes conventional wireline difficult to interpret. Acquiring a wireline image log and performing a petrophysical thin-bed analysis has helped define the net sandstone thickness and net pay thickness of these formations. Performing geochemical analyses on mud gas samples collected in isotubes has helped to characterise the gas composition throughout the formations. In addition, the identification of moveable gas and verification of the extent of the gas columns has been achieved through the acquisition of formation pressure points and bottom- hole samples by Modular Formation Dynamic Tester (MDT). The conclusion is that from review of recently acquired data the Mount Goodwin Sub-Group Sandstone, Torrens Formation and Fossil Head Formations show good potential for future development in the Blacktip Field. A comparison between conventional log analysis and thin bed analysis is also discussed, with estimates of net sand and net pay thickness contrasted.

Blacktip Field is 100% owned and operated by Eni Australia.
A Comparison of Hydraulic Fracture Modeling With Downhole and Surface Microseismic Data in a Stacked Fluvial Pay System
Authors: Mohammad Nur Azlinda , Miskimins Jennifer L.
Published: February 2011

This paper presents a study that combines and compares the results of hydraulic fracture mapping and modeling using both downhole and surface microseismic arrays. There were three objectives for the study including 1) developing detailed posttreatment models of hydraulic fracturing treatments in the subject well, Well D1, which was monitored with downhole microseismic tools; 2) developing detailed post-treatment models of the hydraulic fracturing treatments in the subject well, Well S1, which was monitored with surface microseismic tools; and 3) determining the match characteristics of the downhole and surface microseismic data to hydraulic fracture models developed for both Wells D1 and S1.

Input data for this project were obtained from two wells in the Greater Natural Buttes field, Uinta basin, Utah. Ten fracture models were built using five stages each from the two subject wells, Wells D1 and S1, and detailed pressure matches were made. Comparisons of the match characteristics from the multiple inputs were then developed. The hydraulic fracture stimulation models were graphically integrated with the microseismic events using visualization software. This software allowed the final model-simulated fracture geometries to be plotted along with the microseismic events in three-dimensional space thus allowing the viewer to see a full integration of data in a stacked fluvial pay system.

Results from the integration process show good agreement in geometries and depth for most stages in the downhole-monitored well, whereas comparisons of surface microseismic mapping measurements with the simulated fracture geometries yielded variable results. When combined with additional inputs, such as geologic models, the integration methodology used in this project provides an excellent tool for hydraulic fracture modeling and reservoir management in stacked pay systems.
Role of Stress Reorientation in the Success of Refracture Treatments in Tight Gas Sands
Authors: Roussel Nicolas P. , Sharma Mukul M.
Published: February 2011

The redistribution of stresses around a fractured vertical well has two sources: (a) opening of propped fracture (mechanical effects) and (b) production or injection of fluids in the reservoir (poroelastic effects). In this paper, the coupling of both phenomena was numerically modeled to quantify the extent of stress reorientation around fractured production wells. The results have been compared to field data from the Codell tight gas formation and analyzed for their impact on refracturing operations.

For previously fractured wells, a secondary fracture may be initiated perpendicular to the first fracture if a stress reversal region is present. Altered-stress refracturing makes it possible to access zones of the reservoirs that are less depleted, thus increasing well production and reserves.

The results of our model quantitatively agree with previous tiltmeter measurements, confirming the existence of refracture reorientation in the Codell formation. The performance of refracturing treatments has been observed to be highly variable in the Wattenberg field (Colorado) with some wells underperforming while others are restored to initial production rates. Historical production from neighboring wells and initial fracture performance were shown to impact the potential benefits from refracturing predicted by the numerical model.

This paper introduces a three-dimensional model coupling mechanical and poroelastic stress reorientation used to interpret tiltmeter measurements and historical production in the Codell tight gas formation. Guidelines are drawn from the Wattenberg field case study that allow an operator to (a) select candidate wells, (b) choose the timing of the refracture operation in the life of the well, and (c) evaluate the potential increase in well production after refracturing.
Enhancing Sand Screen Reliability: An Innovative, Adaptive Approach
Authors: Yeh C. S. , Moffett T. J. , Barry M. D , Hecker M. T. , Howell D. A. , Green A. , Gillespie G. A , Hall C. A. , McNamee S.
Published: February 2011

Sand control reliability becomes increasingly important when combining challenging well conditions with the expectations of high flow rates, reduced well counts, and rising costs. Sand screens, the final sand control barrier, have been a critical element to assure long term well reliability. Any screen damage along the well may allow sand ingress and adversely impact the overall production. Preventive (flux limitations) and reactive (choking) methods can reduce the risk of downhole screen damage under complex producing environments, but these methods are unable to mitigate all risk. A step change in screen design to enhance sand screen reliability is needed which can also maintain simple and economic completions.

MazeFlo™ technology, currently under development, was invented to be adaptive to downhole uncertainties and to self-mitigate screen damage. The technology utilizes a redundant sand screen and compartment maze to constrain local sand ingress caused by screen damage without interrupting well production. A prototype screen has been designed and fabricated.

A series of hydraulic and mechanical tests were conducted to validate the prototype design. Both compartment and redundant screens are qualified in flow friction, erosion resistance, and mechanical integrity. A field trial has been designed to demonstrate the screen installation, downhole self-mitigating capability, and sustained production. Operationally, the innovative and robust screen design will appear and run similar to conventional screens.

Successful prototype development will lead to a 2 3/8-in MazeFlo screen ready for use in remedial workover applications. The design philosophy and qualification process are being extended to larger screen sizes for broader applications. The adaptive approach implemented in this novel sand screen establishes a new milestone to enhance sand screen reliability. The collaboration between operator and service supplier enables effective commercialization of innovative technology for the next generation of sand control completions.
Study of Unusual Responses from Multiple Resistivity Tools in the Bossier Formation of the Haynesville Shale Play
Authors: Corley Bill , Garcia Alex , Maurer Hans-Martin , Rabinovich Michael B. , Zhou Zhiqiang , DuBois Patricia , Shaw Nolan
Published: February 2011

Over the years reports have been made of anomalous wireline induction log responses in some shale formations. Anderson (Anderson, 2000) suggested an extremely large dielectric effect as an explanation. As shale formations such as the Woodford, Bossier, and Haynesville plays have gained attention as reservoir rocks, it is important that we understand the reasons for these anomalies.

This paper examines resistivity wireline logs run in the Bossier Shale, Louisiana with several instruments based on different physical principles which indicate that a large dielectric effect cannot be the only cause of the anomalous responses.

The following logs were acquired:

Array Induction log, frequency 10 kHz to 150 kHz

Multi-Laterolog, frequency 30 Hz to 200 Hz

Dielectric log, frequency 200 MHz

Multi-Component Induction log, frequency 20 kHz to 220 kHz

Accurate tool responses in ‘typical’ shale above the Bossier formation all provide evidence that the tools are functioning properly. A pure dielectric effect would linearly increase with frequency (smallest for the low frequencies and largest for the high frequencies). The observed behavior indicates that the low- and medium-frequency tools show similar anomalous response, while the high-frequency dielectric tool is unaffected.

The multi-component induction response, however, shows a strong azimuthal effect where the horizontal ZZ component is always affected. One vertical component (XX or YY) is also affected, while the other vertical component appears normal. The affected vertical component alternates as the tool rotates.
New Inflow Control Device Provides Solid-Liner Functionality Throughout Installation and Fluid Loss Control During Completion
Authors: Infra Morry , Coronado Martin P. , Woudwijk Roy , Al-Mumen Adib A. , Al-Baggal Zaki A.
Published: February 2011

Openhole horizontal completions in consolidated formations have been commonplace for a number of years. This type of completion has been very successful due to the relative simplicity of the completion design and ability to segment the horizontal production interval by using openhole hydrostatic-set packers. Using inflow control devices (ICDs) in this completion design allows a uniform inflow across the entire horizontal wellbore, which mitigates early water or gas coning into the wellbore.

A newly designed ICD has been developed and field-trialed successfully that mitigates the need for an inner string during installation, allowing circulation through the liner while running in the hole as well as hydraulic setting of the openhole packers before pulling out of the hole with the workstring. This also provides an improved well control condition. A temporary valve system has been incorporated into the ICD design that provides pressure integrity in the liner until after the upper completion has been installed. Once the upper completion is in place, the valves are triggered hydraulically with applied pressure in the production tubing and opened once the differential pressure is removed, allowing the ICD to be reconfigured into the production mode. Once the valves have been opened the ICD performs normally for the operational life of the well.

This completion technology also provides the added benefit of isolating the upper wellbore from the reservoir until after the upper completion is installed. This potentially prevents unwanted and costly fluid losses into the formation before the well is put on production.

This paper will describe the new ICD design technology developed for the application and review initial case history well installations in Saudi Arabia.
A Process to Evaluate Unconventional Resources
Authors: Chan Phillip , Etherington John R. , Aguilera Roberto
Published: February 2011

It is the intention of the SPE/WPC/AAPG/SPEE Petroleum Resources Management System (PRMS) to provide a consistent approach to estimating petroleum quantities, evaluating development projects, and presenting results within a comprehensive classification framework. The reserves and resources definitions and application guidelines are designed to be applicable to both conventional and unconventional petroleum accumulations, regardless of their in-place characteristics, the extraction method applied, or the degree of processing required to yield a marketable product.

The fact that unconventional resources are usually pervasive throughout a large area and are not significantly affected by hydrodynamic influences may require different approaches in evaluation. Assessments may include an increased sampling density to define uncertainty of in-place volumes, the variations in quality of reservoir, and hydrocarbons and their detailed spatial distribution for the design of specialized extraction methods.

This paper summarizes the special problems in the estimation and evaluation of several resource types ranging from shale gas to bitumen. The material is largely drawn from the soon to be published SPE Application Guidelines to the PRMS, supplemented with illustrations from actual field examples.

The rapidly advancing exploitation of unconventional resources has opened up many development opportunities, especially in North America. Shale gas and bitumen have already caused major impact on energy supply. We anticipate these opportunities will expand rapidly throughout the world. Achieving a better understanding of the special problems in unconventional resources evaluation will help us build on PRMS to develop a more consistent approach to classification and categorization, accounting for unique project risks and uncertainties.
Extending the Life of Mature Oil Field by Converting Gas Wells into Oil Wells
Authors: Hadiaman F. , Wismayandi H. , Setyawan H.
Published: February 2011

The Handil field is a giant mature oil field in Indonesia. It has been producing since 1975 with current recovery factor for oil is 49% and gas is 57%. Cumulatively, oil had been produced around 855 MMstb and gas around 1.68 Tcf. Now, from this field, oil is being produced at 20,000 bopd, gas at 75 mmscfd and water at 130,000 bwpd. One of the feasible and economic ways to recover the remaining oil at this late stage of field production is by doing a Light Workover technique. This technique aims to change the well status without pulling out the existing completion. This technique is considered the optimum way to maintain the field production performance up to now. One of Light Workover technique is to do re-completion by inserting smaller completion inside existing completion. An innovative spool adapter was utilized to be able to run smaller completion and sit above existing wellhead. Hence, from three (3) depleted gas wells that were converted into oil wells, all wells are still producing and economically had been paid out the intervention cost.

This technique is considered applicable for a mature oil field where some gas wells had been depleted and oil layers are exist.
Multizone Single Trip (MST): Deepwater and Downward Recompletion Case Histories
Authors: Sanford J. R. , Flanagan E. J. , Bruton J. , Woomer J. , Prince J. C. , Landry J. M. , Hansen C.
Published: February 2011

Multizone single trip (MST) systems are currently being evaluated for deep water low tertiary (LT) trends1 where multiple sand control intervals are required. However, this technology can be implemented in other applications. This paper will review the use of this system in two case histories.

The first and primary case history, Mississippi Canyon (MC) 502 Well 2, was the first implementation of a multizone system in the deepwater Gulf of Mexico (GoM). MC 502 Well 2 was part of the Longhorn development, where four (4) different completion types were implemented in the same field, similar measured depth (MD) and pressure regime. A direct comparison of the completion techniques will detail the time savings associated with the MST system.

The second case history, West Delta (WD) 89 Well A-01, is an innovative solution to a downward recompletion using a MST system to isolate the previous completions. Without the MST technology, this well probably could not have been completed.

Based on the results of these case histories, MST completion techniques should be considered for all equivalent pressure multizone completions. Additionally, a MST system is a tool than can be utilized in more applications than high cost deepwater stacked completions.

Increasing the tools available to perform completion operations is always significant. The resulting savings associated with this technology, is in the multiple million dollar range. By proving up this technology, MST sytems will allow the LT trend to be developed more economically.
Key Criteria for a Successful Microseismic Project
Authors: Maxwell S. C. , Underhill B. , Bennett L. , Woerpel C. , Martinez A.
Published: February 2011

As microseismic monitoring expands, a wide variety of monitoring configurations have evolved including vertical, horizontal and deviated observation wells as well as surface and near-surface monitoring. All monitoring configurations have a common data quality indicator: signal-to-noise ratio (SNR) such that the higher the SNR the more accurate and confident the results. The key criteria for a successful microseismic project therefore primarily involve maximizing SNR. Data acquisition can be designed to optimize SNR by using low-noise equipment designed to record appropriate data quality, deployed as close as possible to the target zone. Sample rate should be tailored to the signal bandwidth, and the equipment should also have optimal directional response although for individual microseismic events both will be controlled by the data SNR. Finally, the position of the sensor array will control the fundamental location accuracy, although this will be commonly be a trade-off with SNR depending on logistical constraints of monitoring wellbore access. Recent processing techniques based on seismic migration methods, offer automated and repeatable processing with inherent signal conditioning which provided SNR improvement. Associated with the automated processing is the ability of realtime delivery of all the microseismic events for realtime stimulation decisions. A demonstration with an automatically processed dataset, illustrated the importance of filtering the events based on SNR. Low SNR events had higher location uncertainty, such that both the volume of the microseismic cloud and its aspect ratio were made anomalously large. An accurate microseismic image was produced by filtering out the low confidence, low SNR events. Beyond the geophysical processing aspects, it is equally important that the microseismic project be designed so that engineering value can be extracted by determining valuable fracture details or answering key questions.
Using Microseismic Source Parameters to Evaluate the Influence of Faults on Fracture Treatments - A Geophysical Approach to Interpretation
Authors: Downie R. C. , Kronenberger E. , Maxwell S. C.
Published: February 2011

Microseismic monitoring during hydraulic fracturing treatments has confirmed that hydraulic fractures are much more complex than might have been assumed even a few years ago, when conventional fracture models were considered adequate. Analysis of diagnostic pump-in tests and mining tunnels has shown that fracture complexity exists in both the near-wellbore and far-field regions of the fracture. Also, microseismic monitoring and interpretation have shown that even fractures initiated in the same wellbore during successive stages can have distinctly different characteristics.

Evaluating the effectiveness of hydraulic fracture treatments using microseismic events is challenging. The most common techniques attempt to correlate production with the dimensions of the microseismic clouds and volume estimates based on the density of microseismic events.

Geophysical interpretation has shown that microseismic activity recorded during fracturing treatments can sometimes be associated with existing geological structures such as faults. It is possible to examine the frequency of the microseismic event magnitudes during a fracturing treatment and determine if microseismic events are being produced by the failure of the existing rock fabric, or activation of existing geologic structural features, which might be detrimental to well performance. The resulting frequency-magnitude distributions can then be correlated to observed fracture geometries.

We show that it is possible to use microseismic magnitude to identify whether faults are influencing the observed dimensions of the microseismic event cloud. We also show that it is possible to use microseismic magnitude values to evaluate fracture behavior in real-time applications, allowing stimulation engineers to modify individual stage treatment designs as the specific situation dictates. The potential benefits to both stimulation cost and production results will also be discussed.
Stochastic Analysis of Resource Plays: Maximizing Portfolio Value and Mitigating Risks
Authors: Allan Paul D.
Published: February 2011

This paper outlines a method for applying stochastic representations of key macro-economic parameters and risks in evaluating the portfolio value of resource plays. Stochastic pricing, costs forecasts, and regulatory uncertainties are often neglected or improperly applied when evaluating what are typically considered to be ‘low risk’ resource opportunities. Portfolio allocation and project development timing may be critically dependent upon these macro-economic variables, particularly given the long production life and operationally intensive nature of many resource opportunities. The techniques described in this paper will allow corporate planners and E&P executives to better leverage their opportunity inventory and ensure resource play development plans are in alignment with stochastic pricing or other macro-economic forecasts. A model of a typical E&P portfolio with numerous resource plays will be used to demonstrate the basic methodologies and the insights made possible through application of these techniques. This will include analysis of leasing options, pilot project evaluation, development timing and pacing options, and portfolio balance under various macro-economic conditions. The characteristics of project level analysis will be contrasted to the decisions and insights made possible via a holistic portfolio based approach.
Enhancing Gas Production in Coal Bed Methane Formations With Zeta Potential Altering System
Authors: Kakadjian Sarkis , Garza Jose , Zamora Frank
Published: February 2011

This paper describes lab studies and field results on how a new Zeta Potential Altering System (ZPAS), utilized in fracturing treating fluids, improves gas rate production. Lab and field results show ZPAS minimizes proppant flow back and coal fines migration, enhances fluid load recovery, and inhibits calcium carbonate scale formation. The mechanism of this system based on an inner salt that modifies the Zeta Potential on particles such as frac sand and formation substrate, changing the charge towards neutral values and therefore enhancing particles agglomeration.

This paper also shows how the Zeta Potential Altering System has been applied in numerous coalbed methane wells which were treated by refracturing. The ZPAS has been run in borate cross-linked fluids and linear gel systems. Field results have been positive on wells treated, with less time to clean out frac sand, less flow back sand and coal fines, higher conductivity after load fluid recovery, and higher gas productivity after load fluid recovery and de-watering of CBM Zones. Production has increased up to 15 fold on individual wells with 3 to 20 months production history.
Modeling of Fluid Transfer from Shale Matrix to Fracture Network
Authors: Ozkan E. , Raghavan R. , Apaydin O. G.
Published: February 2011

The objective of this paper is to incorporate a more detailed description of flow in shale matrix to improve modeling of production from fractured shale-gas reservoirs. Currently, most modeling approaches for shale-gas and -oil production are based on the dominance of Darcy flow in both natural fractures and matrix. We improve the description of matrix flow by considering diffusive (Knudsen) flow in nanopores. In our dual-mechanism approach, when Darcy flow becomes insignificant due to nanodarcy matrix permeability, Knudsen flow takes over and contributes, substantially, to the transfer of fluids from matrix to fracture network. Furthermore, we consider stress-dependent permeability in the fracture network. Therefore, incorporating Darcy and diffusive flows in the matrix and stress-dependent permeability in the fractures, we develop a dual-mechanism dual-porosity naturally fractured reservoir formulation and derive a new transfer function for fractured shale-gas reservoirs. The dual-mechanism dualporosity formulation presented in this paper can be used for numerical or analytical modeling purposes. We use the new formulation of matrix to fracture fluid transfer with an analytical model and demonstrate the differences from the conventional formulation.
Knowledge Transfer via Education and Training Partnerships Among Global Universities, IOCs, and NOCs
Authors: Baughman Gary L. , Van Kirk Craig W.
Published: February 2011

The following paper summarizes the authors’ perspectives on establishing and maintaining a dynamic off-campus outreach program at a traditional university with geo-petro disciplines. Cited are the challenges to be faced as well as suggestions and recommendations for achieving success. Emphasis is placed on the importance of establishing partnerships among other universities, international oil companies, national oil companies, and when appropriate, governmental agencies.