bluuebunny/crossref_metadata_2025 huggingface dataset:
Bacterial Survival in Fractured Shale Gas Wells of the Horn River Basin
Authors: Moore S. L. , Cripps C. M.
Published: February 2011

Traditional ideology on the upper temperature limits of life, suggest that extreme temperatures like those observed in the Horn River Basin shale gas formation (i.e. up to 175°C), should alleviate microbiologically influenced corrosion and souring concerns associated with hydraulic fracturing procedures. The present case history investigates the accuracy of this theory. Horn River Basin wells currently in the flowback or production stage, and the source water used to fracture these wells were studied for the presence and identity of viable bacteria. The effectiveness of two biocides, a gluteraldehyde-based and a cocodiamine-based, in eradicating these bacteria in both the field and the laboratory, was also studied. The results show that source ponds are highly contaminated with bacteria. Furthermore, the high-temperature, high-pressure downhole conditions in this region are not sufficient for eradicating bacteria introduced during the fracturing process. These bacteria survive and establish viable, proliferating communities. Biocide, applied continuously "on-the-fly" during fracturing, was effective at mitigating the downhole bacteria concern. Laboratory study further showed that more established bacterial communities were much more resistant to biocidal treatment. Therefore, early mitigation strategies will likely be key in the prevention of microbiologically induced corrosion and souring.
Optimizing Injection Wells through Innovative Completion
Authors: Khalil Ashraf , Elasmar Magdi , Shafie Shaiful
Published: February 2011

This paper covers the first global application of Influx Control Device (ICD) in an injector well for carbonate formation. This inventive completion coupled with a wellbore simulation will optimize the injection profile into heterogeneous formation zones hence enabling reservoir management strategy to be achieved.

Carbonate formations are typically known for their heterogeneity and complex pore system which have an impact on the fluid movement pathway. Conventional injection wells face the challenge of achieving even distribution of the injected water along the wellbore. Heel to toe effect, significant permeability contrast and existence of thief fractures is among the factors that complicate the effort to achieve a good reservoir management.

Inflow control devices have a long history of application in production wells both in sand stone and carbonate formations. It has proven to be very effective in achieving a balanced inflow profile along the horizontal section, delaying water and gas production breakthrough. The Influx Control Device is equally able to function in an injection well and with the usage of wellbore simulation, is able to cater for the complexities of the carbonate formations.

The installation was carried out in a horizontal water injector well in a major oil field, offshore Abu Dhabi. This paper presents the design of the completion, its installation and the initial water injection results based on production logs.

The positive result from the installation has shown the applicability of such completion technology and offers solutions in our effort to optimize reservoir performance particularly in carbonate formations.
Method to Improve Thermal EOR Performance Using Intelligent Well Technology: Orion SAGD Field Trial
Authors: Clark H. P. , Ascanio F. A. , Van Kruijsdijk C. , Chavarria J. L. , Zatka M. J. , Williams W. , Yahyai A. , Shaw J. , Bedry M.
Published: February 2011

A method has been developed for improving both steam injection and production conformance in a thermal EOR project by utilizing intelligent well technology incorporating interval control valves (ICV), well segmentation and associated downhole instrumentation. This provides the ability to selectively open and close segmented sections of the well bore and monitor the key parameters of temperature and pressure from surface. The initial field trial is ongoing in the injector of an Orion field SAGD well pair. Development of the completion system suitable for thermal conditions, initial field trial results and plans for further development are described.

Modelling shows that, depending on the level of heterogeneity present in the reservoir, an improvement of 20 to 40% in the steam oil ratio and 5 to10 % in recovery can be achieved in a SAGD process when both improved injection conformance and producer differential steam trap control can be applied in a segmented horizontal well pair. A cost effective solution to achieve this segmentation and control has the potential to add substantial value to field developments through improved steam conformance resulting in increased energy efficiency and oil recovery. The method being developed is applicable to a wide range of EOR processes such as CSS, steam drive and variations.

The initial field deployment in the injector well was primarily to prove operability of the system in high temperature thermal applications, to demonstrate the feasibility of modifying steam distribution and to learn for future optimization and deployment of the system. A successful installation and commissioning has substantially validated the completion technology. Early injection test results and data provide a significant improvement in the understanding of the injection and production behavior in the well pair. A test program to optimize the distribution of steam injection in the well is underway and the preliminary results are discussed. Lessons learned from the trial are highlighted.

The intelligent completion technology under trial, and proposed further developments, should enable more extensive use of downhole measurement and control in thermal EOR projects to improve performance.
Case Study: Development and Optimization of Quicksilver
Authors: Rempel D. G. , Somerwil M.
Published: February 2011

Development of CBM in the Horseshoe Canyon (HSC) has exploded since its commerciality was first demonstrated in 2003. To date over 15,000 wells have been drilled and are producing from HSC coals. Quicksilver's development has been steady with approximately 1800 wells drilled and brought on-line between 2003 and 2009, and today operates 17 development pods located throughout the HSC fairway. This case study overviews Quicksilver's learnings and experiences from these activities including various aspects of geological and resource assessment, development tactics and recovery optimization, and presents practical datasets for appropriate management of the resource.

Geological investigation has been an important factor right from the outset of this play's development. Many initial concepts have been challenged and subsequent production data often shows discordant relationships with geological parameters used to calculate net pay, depth, and subsequently the OGIP. Water production trends, gas rate variability, anomalous seam contributions, nonlinear pressure gradients, and variable permeabilities are discussed within this case study and the challenges that they present.

As development unfolds, production data has increasingly become a key factor in understanding these unconventional reservoirs, and is variable between areas and even within the development pods / areas themselves. Despite the variability, trends have been identified using production indicators and forecasts. A statistical approach is used to examine these trends, and in conjunction with the geology / resource characterization is enabling improved management decisions for optimal development. In particular variable density drilling, ranging from 2 wells per section to 8 wells per section, as well as various pilot higher density projects, is examined closely and provides valuable information from a reservoir development and optimization perspective. Impacts of sands completions as an add-on to the primary CBM target are also investigated.
Statistical Approach for PCP Standardizing
Authors: Gamboa Jose
Published: February 2011

The selection of a progressing cavity pump heavily relies on the expertise and experience of field personnel. Therefore, the selection of pumps for a large number of wells becomes an energy consuming and cost-effective task where heuristic prevails over an algorithmic procedure. This paper proposes a new approach that attempt to perform such task by combining multiphase calculations with well known pump selection criteria and statistical clustering method.

The methodology requires massive information about the well completions, fluid properties and operation conditions that are utilized for predicting the pressure rising required, inlet volumetric gas fraction among other variables for every well in the field. Two approaches can be utilized to identify standardized pump models: hit frequency and K-mean algorithm. The standardized models for a particular well are considered equivalent pumps, which means that any of standardized models can be utilized in the same well with equivalent results. The process also allows identifying in how many wells a particular pump model can be utilized.

A case study applying the standardizing methodology is presented. The case is a extra-heavy oil field where standardized pump models for 592 wells are required for future purchase.

The methodology proposed is the first step to establish an analytical procedure for identifying standardized pump in a field. The elastomer selection needs to be added to the methodology for sake of completeness; however, it has been left out due to lack of predicting model for the elastomer swelling, thermal expansion and fluid-material chemical interaction.
Enhancement of PLT Tool Reach in Horizontal Wells Using Advanced Wireline Tractor
Authors: Al-Buali Muhammad H. , Dashash Alaa A. , Al-Shehri Ayedh , Torne Juan , Hussein Walid Kamal
Published: February 2011

The horizontal wells drilled during the last few years are coming to a mature state in different fields and locations. Even the existing vertical wells are being converted to horizontal for better oil sweep and productivity. This has created the requirement to evaluate the production performance of horizontal wells to determine water source for proper monitoring and/or a remedial action.

The conventional conveyance methods for the horizontal production logging tool (PLT) are either coiled tubing (CT) or E-line using a tractor. These methods satisfactorily perform in conventional horizontal wells, however, operational limitations and challenges could be encountered when the horizontal section is more complicated due to extended reach, big and inconsistent washouts and high dogleg severity. These types of challenges can prevent the passage of the logging tools to the desired depth. This has an adverse effect on both data quality and accessibility to the well’s total depth (TD). Accordingly, a lot of effort is being exerted by oil companies, service providers and vendors to improve the conveying performance of logging tools using wireline tractors.

An electro-hydraulic tractor with wheels was introduced and deployed for the first time in the world using mono-cable logging tractor technology into several horizontal open hole wells in a Saudi Arabian field. The wells were drilled in a carbonate formation with long horizontal sections and were producing at high rates. This tool was run as an integral part with the logging tool to help cover the entire horizontal section and reach TD while logging.

The logging jobs using this new technique were completed safely and successfully at flowing and shut-in conditions. At flowing condition, the logging tool was successfully conveyed to TD and measurements were made over the entire horizontal section with the help of the tractor. The well was logged at different choke settings while measurements were taken at down passes (while tractoring) and up passes. The tractor was running at a constant speed and was able to pass a long washout of around 9" in diameter. The data analysis showed very acceptable measurements.

This paper will describe the case histories, challenges, planning, deployment and advantages/disadvantages of this type of tractor.
Heavy Oil (Bitumen) and Alkane Solvent Partitioning (HASP) Process
Authors: Frauenfeld Ted W. , Rajan Raj S.
Published: February 2011

Both gravity-based solvent and cyclic solvent processes for recovery of heavy oil or bitumen may involve relatively high solvent/oil ratios. It has been experimentally observed that at high solvent loadings, the oil/solvent mixture partitions into a solvent-rich oil phase and a heavy-ends-rich oil phase. The partitioning may have significant beneficial impact on the performance of a solvent-based process such as VAPEX, or other gravity based processes if the low-viscosity phase carries the bulk of the oil production, and the asphalt-rich phase is mostly asphaltene and essentially immobile. Data on the physical properties (viscosity and density) and the composition of both the partitioned phases are needed to design and optimize solvent-based processes. The project objective was to analyze the laboratory test data on multiple phases partitioning of a selected oil/solvent system. The experiments, conducted with propane and Athabasca UTF bitumen at different solvent loading, have shown the oil/solvent mixture partitions into a solvent-rich oil phase and a heavy-ends-rich (mostly asphaltenes) oil phase with significantly higher densities and viscosities. CMG-WinProp software was used to model the phase partitioning. It was possible to get a good match between the test data on the liquid phase separations and some properties such as densities, but not viscosities.
Non-Condensable Gas Distribution in SAGD Chamber
Authors: Yuan J-Y. , Chen J. , Pierce G. , Wiwchar B. , Golbeck H. , Wang X. , Beaulieu G. , Cameron S.
Published: February 2011

This paper summarizes a set of SAGD experiments conducted live under an X-ray scanner. These experiments were specifically designed for mapping non-condensable gas distribution and their movement in an active steam chamber during SAGD.

Many researches over the past three decades have shown that non-condensable gases may have critical impacts on SAGD performance. Some may be positive; others may be negative depending on reservoir and operating conditions. For better utilizing the positives, avoiding the negatives and for better SAGD performance predictions, it is crucial to understand how these gases behave in a steam chamber. It is arguable that non-condensable gases tend to accumulate at the steam front where steam condenses. However, this assertion has only been supported by numerical simulations. Field observation data have been too sparse. Meaningful tracking of gas production is not a normal practice in the field.

The first experiment was conducted in an aluminum vessel packed with 4Darcy sands at 1.0MPa. The second experiment was conducted in a scalable system consisting of a titanium pressure vessel and a PEEK cell, allowing the SAGD experiment ran at 2.1MPa. Both experiments used bitumen fully saturated with methane at reservoir conditions and were run live under the X-ray scanner. X-ray images were taken at given time intervals. Temperature profiles were obtained directly from thermocouples. Density profiles were computed from the X-ray images. Methane in free gas phase were calculated and mapped. After each experiment, samples from opened cell were also tested for additional observation and confirmation.

These experiments confirmed the assertion that non-condensable gas tends concentrate along the steam front. It also demonstrated that the steam temperature zone does not coincide with the oil depleted zone, indicating that in a SAGD reservoir with nontrivial presence of non-condensable gases, temperature measurements at observation wells alone would not reflect the boundary of the steam chamber. The more representative measure of a steam chamber should be the mapping of oil depleted zone. 4D seismic plus a more comprehensive monitoring of gas production would be needed for determination of the oil depleted zone in the field operation.
Troubles, Problems and Improvements of ESP
Authors: Shimokata N. , Yamada Y.
Published: February 2011

Since 1975 Abu Dhabi Oil Co., Ltd (ADOC) has been applying artificial lift with ESPs in one of its offshore fields and has aquired experience in the installation and use of more than 300 ESPs, 45 of which are currently in operation. This paper will highlight the problems that have occurred with these ESPs, together with the technical improvements and countermeasures that have been put in place in order to achieve a longer ESP run-life.

The failure of the ESP cables delivered in 2003 caused the ESPs to cease production, after a short period of time, due to cable damage in 2004. Following inspection, we concluded that the problems were related to the quality control of the cables. In order to avoid further cable problems, we reviewed the quality control system, including cable handling during transportation. Furthermore, we investigated the potential for technical improvement of the ESP cable, in order to extend the ESP run-life. As a result, the lead thickness was increased and the pothead coating material was changed. Since improving the quality control system of the cable, no further problems have been observed to date.

The build up of asphaltene and CaCO3 scale is another problem which we face with regard to ESP wells. Once scale is deposited at the down hole, it is difficult to remove and, as a result, oil production will decrease. To avoid asphaltene deposit, Xylene is injected into the annulus periodically. To avoid CaCO3 scale deposition, the brine pH is controlled during stimulation and, if necessary, a scale inhibitor is squeezed after stimulation.
Azimuthal Seismic Pilot for Fault and Fracture Detection - An Abu Dhabi, U.A.E. Case Study
Authors: Mueller Klaus W. , Nahhas Mohamad Samir , Soroka William L. , al Baloushi Mariam , Sinno Rick , Martinez Ruben D. , Hussein Waleed , LeCocq Paul
Published: February 2011

An azimuth dependant processing pilot study was carried out in a large Middle East Field to evaluate if this technology has the potential to successfully identify fracture permeability pathways. The field is heavily faulted and fractured with good well control and therefore is a good candidate to perform this study. The success criteria for the Azimuthal processing are: Improved fault imaging relative to the available conventional processed seismic volume;Obtain information about seismic anisotropy in the reservoir zones.

This anisotropy will be linked in a full evaluation to fault & fracture density and orientation. The anisotropy can be measured via differences in seismic travel times or amplitudes / seismic attributes measured in the different azimuth seismic cubes. Azimuthal anisotropy from a 3D land seismic dataset acquired in the U.A.E. has been analyzed using wide azimuth processing. Two different processing methods and flows were tested to derive optimum processed volumes. In both methods raw CMP gathers, after convolution, residual statics, and inter-bed multiple elimination were used as input data for the azimuth stack processing sequence. The two methods are Azimuth SectoringCommon Cartesian Offset Bins (CCOB)

Both processing methods have their benefits, one big advantage of CCOB is that you can stack very fast different individual azimuths together and get a sharper image, which results in better interpretation.

Azimuth sectors both parallel and perpendicular to the three major fault system orientations, were imaged separately to produce the six final azimuth volumes. Comparisons between the different azimuth sectors were used to detect azimuthal differences in velocities and amplitudes that could be correlated with fault and fracture orientation and magnitude.

The interpretation and validation of the results suggest that value is maximized by integrating multiple attributes that include horizon mapping for time differences, amplitude extractions for reflectivity differences and result validations with available well calibration. The azimuth sector results have aided in the quantification of fault presence, magnitude of throw and suggests that fractured zones can be identified which may indicate higher permeability pathways within the reservoir.

Another important learning from this case study is to use an integrated approach during processing and interpretation and don’t look only at one single part, e.g. velocity cube.

Overall the results of this carbonate Azimuthal Pilot for fault and fracture characterization has produced encouraging results and valuable lessons learned to aid future studies.
Successful Formation Pressure Testing While Drilling Directionally Demanding 17 1/2-in. Hole in Deepwater Angola
Authors: O’Hara Peter , Prieto Olga , Symons Graeme
Published: February 2011

The benefits of formation pressure testing while drilling include improved formation evaluation, drilling hazard mitigation, drilling performance optimization and saving time. In deepwater wells offshore Angola, this is regularly used in 12 ¼-in. and smaller hole sections. The requirement extended to the 17 ½-in. hole sections which are typically directionally drilled with high buildup rates due to the reservoir being located at a relatively shallow depth below the seabed. The plan was to adapt the formation pressure testing equipment already used in 12 ¼-in. hole and establish a technique to use it in 17 ½-in. hole. This was complicated by the high buildup rates in the 17 ½-in. hole, as opposed to the high-angle tangents seen in the 12 ¼-in. hole sections. The unconsolidated nature of the formation further complicated the process as the low compressive strength of the rock can prove challenging for directional steering and the friability of the formation could affect both the seal of the formation pressure tester and its ability to sample pressure.

This paper will discuss development of the techniques over the initial wells, issues that were encountered and solutions developed to simultaneously deliver the formation pressures and the directional profiles using standard equipment. In addition, the paper will discuss how the techniques developed for the 17 ½-in. hole were further adapted to sample formation pressures when these had to be measured in 13 ½-in. hole below 9 ⅝-in. casing in situations where conventional formation pressure testing techniques could not deliver data. As a result, the paper describes the successful deployment of real-time formation pressure testing in large hole sizes whatever the directional challenges.
Optimization of Horizontal Wellbore and Fracture Spacing Using an Interactive Combination of Reservoir and Fracturing Simulation
Authors: Taylor R. S. , Glaser M. A. , Kim J. , Wilson B. , Nikiforuk G. , Noble V. , Rosenthal L. , Aguilera R. , Hoch O. , Storozhenko K. , Soliman M. , Riviere N. , Palidwar T. , Romanson R.
Published: February 2011

The application of horizontal wellbore drilling and multistage fracturing technology has been playing a pivotal role in unlocking shale-gas reserves globally. More recently, the same technology has been applied to both new and mature oil fields.

A key question for economic optimization of these assets is what fracture spacing to use along a horizontal wellbore. Of equal importance is what spacing to use for multilaterals and the wellbores themselves to achieve optimal drainage of the reservoir. In addition, the design of the fracturing treatments must be optimized.

To address these questions, a combination of reservoir and fracturing simulation has been applied. The required input data are provided through a combination of advanced log and core analyses, diagnostic fracture injection testing (DFIT), rate transient analysis (RTA), and characterization of fracture geometry through microseismic monitoring. Fluid rheology is characterized using pressurized rheometers and flow loops.

This paper presents results of this work using examples of current Canadian oil and shale-gas reservoirs and a methodology to improve the economic return of different completion and production scenarios.
Hot Solvent Injection for Heavy Oil/Bitumen Recovery: An Experimental Investigation
Authors: Pathak V. , Babadagli T. , Edmunds N. R
Published: February 2011

Thermal and miscible methods are commonly used for in-situ recovery of heavy oil and bitumen. Both techniques have their own limitations and associated shortcomings, often times yielding an inefficient process. The most common thermal method is steam injection, which is highly energy intensive. Steam generation costs and water production affect the economics of the thermal technique adversely. On the other hand, miscible methods are energy effective but their economics depends on the solvent retrieval. Various combinations of these two techniques such as co-or alternate injection of steam and solvent have been proposed as a solution, but no optimum method has yet been developed.

Thermal and miscible methods can be combined by co-injecting solvent with steam or injecting solvent into a pre-heated reservoir. Current work was undertaken to study the performance of solvents at higher temperatures for heavy oil/bitumen recovery. Glass bead packs and Berea sandstone cores were used in the experiments to represent different types of pore structures, porosity and permeability. After saturating with heavy oil, the samples were exposed to the vapor of paraffinic solvents (propane and butane) at a temperature above the boiling point of the solvent, and a constant pressure of 1500 kPa. A mechanical convection oven was used to maintain constant temperature across the setup. The setup was designed in such a way that a reasonably long sample (up to 30 cm) can be tested to analyze the gravity effect. The oil recovered from each of these experiments was collected using a specifically designed collection system and analyzed for composition, viscosity and asphaltene content.

The amount of oil recovered in each case was also analyzed and the quantity and nature of asphaltene precipitated with each of the tested solvents under the prevailing temperature and pressure of the experiment was reported. Optimal conditions for each solvent type were identified for the highest ultimate recovery. It was observed that recovery decreased with increasing temperature and pressure of the system. It was also noticed that butane diluted the oil more than propane which resulted in lower asphaltene content and viscosity of oil produced with butane as a solvent.
Cement Technology Improves Fracture Initiation and Leads to Successful Treatments in the Eagle Ford Shale
Authors: Stegent N. A. , Leotaud L. M. , Prospere W. , Veillette C. P.
Published: February 2011

Stimulation-design considerations usually include things like formation-fracture gradient, reservoir pressure, stress, casing size, perforation schemes, etc. The type of cement that fills the annular space between the openhole lateral and the casing is not typically considered with regards to its impact on the execution of the frac treatment.

Early horizontal-well completions observed much higher injection pressures than those observed in vertical wellbores in the same formation. Research identified the effects caused by transverse, oblique, or longitudinal fractures from horizontal wellbores, which were usually nonissues in vertical completions. Near-wellbore (NWB) friction (tortuosity) is a component that is common to both vertical and horizontal wellbores but seems to be ignored in horizontal completions. When proppant cannot be placed during a horizontal frac, it is usually blamed on formation-fracture width (or lack of it) and proppant size (mesh size is too large). These are the typical reasons used to explain early screenouts and have become commonplace in the industry. The authors of this paper believe NWB tortuosity issues have a much larger impact than most think and will show how a properly engineered production casing cement, in conjunction with the stimulation design, allows the placement of large-mesh proppant at high concentrations in the Eagle Ford shale. High conductivity is essential for maintaining liquid-rich production.

Fracture initiation in a horizontal well, especially at the toe, can sometimes be very difficult. To minimize injection issues, acid-soluble cement (ASC) was placed in the lateral of several Eagle Ford-shale wells in Karnes County, Texas. Hybrid stimulation treatments were used to place 20/40-mesh proppant at concentrations up to 4 lbm/gal, most without issue. Proper engineering was used to successfully fracture stimulate all the intended intervals (including the first stage at the toe).

Utilization of ASC for horizontal completions can help improve stimulation efficiency and allow alternate onsite frac options that can turn an otherwise-abandoned completion interval into a successfully stimulated section of the reservoir.
Study of Alkaline/Polymer Flooding for Heavy Oil Recovery Using Channeled Sandpacks
Authors: Wu Yongge , Dong Mingzhe , Shirif Ezeddin
Published: February 2011

For heavy oils with viscosities ranging from 1,000 to 10,000 mPa·s (cP) in Western Canada, primary production and waterflood together can only recover 8 – 15 % original oil-in-place (OOIP) at their economic limit due to the adverse mobility ratio, severe water channeling and low reservoir pressure and formation voidage. These heavy oils usually have a relatively high content of acids which can react with alkalis to form in-situ surfactants. The loosely consolidated sandstone formations where these oils are deposited are characterized by high porosity, permeability and low reservoir temperature. These reservoir conditions are favorable for polymer application. Therefore, there is a potential to improve waterflood in these reservoirs by applying alkaline/polymer (A/P) flooding.

This paper presents the results of a laboratory study of A/P flooding for heavy oil recovery, including viscosity measurements, flood tests conducted in channeled sandpacks, residual resistance factor (Frr) determination, and residual oil distribution tests. A heavy oil with a viscosity of 1,202 cP and an acid number of 1.07 (mg KOH/g-oil) and produced brine collected from a heavy oil reservoir in Alberta are used in this study. The experimental results show that addition of polymer to alkaline solution reinforces stability and strength of in-situ formed emulsions. It is found that the distribution of the injected chemical solution into the high permeable cannels leads to the diversion of the subsequently injected chemical solution to low permeable zones with higher oil saturation due to the formation of blockage in the channel zones. Consequently, pressure build-up during chemical slug injection is the key to the improvement of displacement efficiency. Flood tests also show that alkaline-polymer flooding is more efficient than either alkaline flooding or polymer flooding. The optimal formulation for the heavy oil used in this study is 0.4% NaOH + 0.2% Na2CO3 + 1,000 mg/l polymer, with a tertiary oil recovery of 25 – 30 % OOIP over waterflood. Analysis of the results of the residual oil distributions in the channeled sandpacks at the end of A/P flooding shows that A/P flooding can effectively improve the sweep efficiency of waterflood for the heavy oil.
Application of the Ensemble Kalman Filter for Characterization and History Matching of Unconventional Oil Reservoirs
Authors: Chitralekha S. B. , Trivedi J. J. , Shah S. L.
Published: February 2011

Recently, the Ensemble Kalman Filter (EnKF) has emerged as an effective tool for performing continuous updating of petroleum reservoir simulation models. The method is firmly grounded on the theory of Kalman filters and sequential Monte Carlo techniques. The ability of the method to sequentially update the spatial properties in petroleum reservoir models, such as permeability and porosity, by integrating the dynamic production data makes it a very attractive approach. Moreover, the method takes into account the production uncertainty in the reservoir models by using error covariance matrices for the measurement vector (Production and injection rates, Gas-Oil ratio, Steam-Oil ratio, etc.) and the state vector (pressure, saturation, permeability, porosity). Similar to the traditional Kalman filter, the covariance matrices have to be tuned to reflect the uncertainty in the model and the measurements. We consider two unconventional oil reservoir models: 1) highly heterogeneous black-oil reservoir model, and 2) heterogeneous SAGD reservoir model. The results will demonstrate the advantage of using the localized EnKF for effective history matching using ensemble sizes relatively lower than what otherwise would be required with the ordinary EnKF. The results will also show the advantages of using prior knowledge available from the wells (permeability and porosity measurements) to generate initial realizations. One of the main practical advantages of history matching using the EnKF over traditional optimization based approaches is its low computational effort. The computational cost is dominated by Monte Carlo simulation of the ensemble of models only. Thus, significant computational time saving is possible by running each of the ensemble simulations on independent processors in a parallel mode. Moreover, the method can be easily integrated with any commercial reservoir simulation software.
Flow Regime Analysis of Multi-Stage Hydraulically-Fractured Horizontal Wells with Reciprocal Rate Derivative Function: Bakken Case Study
Authors: Luo Shanqiang , Neal Lane , Arulampalam Pathman , Jessica McDonough Ciosek
Published: February 2011

Activities in developing tight oil and gas reservoirs, such as the Barnett shale and the Bakken formation, have grown tremendously in recent years. Economic production of these unconventional resources relies heavily on advanced completion technology such as horizontal wells with multi-stage hydraulic fracture stimulations.

Unlike single-stage fractured vertical wells, multi-stage fractured horizontal wells (MFHW) exhibit a unique flow regime, compound formation linear (CFL) flow, which consists of linear flow in the formation toward the collective hydraulic fractures after interference has occurred between neighboring fractures. This flow regime can easily be mistaken for a reservoir-boundary (or compartmentalization) effect in production analysis. Such a misinterpretation will result in incorrect reservoir property estimates and long-term production forecasts.

This paper applies log-log reciprocal rate derivative plots to identify and analyze flow regimes of MFHW wells producing under constant bottomhole pressure. It is observed that the CFL straight line slope in the reciprocal rate derivative plot depends on the ratio of fracture length over fracture spacing but is not sensitive to reservoir permeability. As a result, the CFL slope can be used to diagnose fracture stimulation effectiveness.
Experimental Investigations of Hydraulic Fracture Growth Complexity in Slickwater Fracturing Treatments
Authors: Wang Y. , Miskimins J. L.
Published: February 2011

Friction-reduced water, i.e. “slickwater”, fracturing was first introduced in the late 1950's. It fell out of favor with the advent of gelled fluids systems; however, slickwater fracturing has seen a large resurgence with the increasing development of unconventional reservoirs. Slickwater fracturing has once again become popular for stimulating these tight gas sand and shale gas systems.

The main advantages of slickwater fracturing treatments are the economics and the adequate conductivity they can place in low permeability reservoirs. Additionally, it is possible for slickwater treatments to create long, complex fractures which enhance the well's “stimulated reservoir volume” (Mayerhofer et al. 2008). Most treatments use large quantities of water pumped at very high rates. However, the relationship between complexity and rate is not well understood.

This paper presents an experimental study on slickwater fracturing performed by using a unique testing system, which was developed to study slickwater fracturing treatments at a laboratory scale. The intent was to study the effects of rate on the complexity of growth in the reservoir. Laboratory results were scaled to field conditions by applying scaling law analysis. The scaled results suggest that for field water fracturing treatment design in shale reservoirs, large injection volumes result in large SRA (“stimulated reservoir area”, a comparison term to “stimulated reservoir volume”) which should result in increased production. The optimal injection rate can vary for different reservoir conditions. At low injection rates, reservoir complexity does not seem to affect fracture network growth. At the same time, different rock types will also affect the fracture network growth in water fracturing processes. Quantitatively, the laboratory results agree well with the conclusions drawn from actual field applications.
Lessons Learned and Experiences Gained in Developing Waterflooding Concept of Granite Basement Fractured Reservoir: 20 Historical Years Case Study
Authors: Dang Cuong T. , Nguyen Ngoc T. , Bae Wisup , Chen Zhangxing , Phung Thuoc H.
Published: February 2011

NFR represent over 20% of the world's oil and gas reserves. However, characterization of fractured reservoirs is complex and presents unique challenges in comparison with conventional reservoirs. It is immensely difficult to achieve the best results in secondary recovery process.

This paper presented the successful developments of waterflooding to overcome the complex geological characterizations of White Tiger field - the biggest fractured basement reservoir up to now on the continental shelf of Viet Nam. This reservoir has a complicated geological structure, very high heterogeneity, high temperature and closure stress. The total OIIP of this field reached nearly 4 billion barrels with 2000 meters of the oil bearing thickness and has been produced by more than 100 wells, tens of which flow at the rate of approximately one thousand barrels per day.

The geological study and fractured model were carefully investigated in both micro and macro scales to improve waterflooding performance. The authors analyzed the advantages and disadvantages of injection systems in basement reservoir during 20 historical years. And then, the artificial water buffer solution was proposed to develop waterflooding process. The authors described the establishment and the association of local artificial water buffer in basement reservoir. An effective method to adjust the injected water mass was also discussed. The excellent results in White Tiger field proved that average reservoir pressure and total oil recovery were significantly increased in comparison with previous injected schemes.

This paper is the precious guideline to solve some typical problems of waterflooding in fractured basement reservoir such as:

What could be applied waterflooding in basement fractured reservoir? What is the optimum injected rate and injected mass for basement fractured reservoir? How to evaluate the probability of high water cut in production wells during waterflooding process? How to predict the rising of artificial water-oil contact?
Facilities Modernization Project A&B
Authors: Al-Qahtanil Mohammed Mubarak
Published: February 2011

The Facilities Modernization Projects (A & B) are part of Kuwait Oil Company’s strategic development plan to meet and achieve its production objectives and targets by adding and upgrading surface production facilities along with relocation of underground piping and upgraded control systems for nineteen production facilities.
Shale Gas Reservoir Characterization Using LWD in Real Time
Authors: Han S. Y. , Kok J. C. , Tollefsen E. M. , Baihly J. D. , Malpani R. , Alford J.
Published: February 2011

A common practice in shale plays is to evaluate vertical boreholes with an extensive wireline logging program. Largely driven by cost, time and difficulty associated with acquiring wireline measurements in horizontal intervals, only data logged from the vertical hole is interpreted and used to define the reservoir profile for the horizontal target window. The horizontal wells are then steered based on simple gamma ray measurements by means of correlation against the vertical pilot wells. Detailed studies from a range of shale plays have revealed that the geosteering results for these wells using only gamma ray, are often questionable as it can provide non-unique structural modeling solutions.

Integrating Logging While Drilling (LWD) tools into the Bottom Hole Assembly (BHA) enables formation evaluation measurements to facilitate accurate well placement and perform detailed reservoir characterization across the target structure. Additionally, LWD measurements have been successfully used to avoid drilling hazards, enhance rate of penetration to reduce drilling time, and optimize completion designs. Using limited data for horizontal well correlations often result in inaccurate structural interpretations. This inaccuracy complicates the understanding of production variations between wells. By employing LWD, the uncertainties can be narrowed to enhance trajectory placement and provide a better understanding of the reservoir-production relationship. This relationship allows target refinement within the productive reservoir interval followed by an optimized completion for an overall increase in reserve recovery. This paper details the use of LWD measurements for accurate well placement, formation evaluation, and completion optimization within a shale gas play using an integrated shale gas solution.
Numerical Simulation on CO2 Sequestration in Saline Formations With Natural or Hydraulic Fractures Using a Discrete Modeling Approach
Authors: Liu X. , Gong B. , Huo D.
Published: February 2011

To find suitable locations to permanently sequester CO2 is crucially important for carbon storage. Deep saline formations are thought to be good candidates for CO2 sequestration due to their large capacity potential. On the other hand, cases have shown that saline formations can be naturally fractured to some extent, from small individual fractures to large-scale fracture clusters. Based on research from various scientific studies, pilot CCS programs and commercial CCS projects, formations and/or cap rocks with fractures may have significant leakage problems.

Modeling of CO2 flow in fractured systems remains a challenge. In this work, Discrete Fracture Modeling (DFM) that represents fractures individually and explicitly is applied to simulate CO2 transport in a saline aquifer. This requires unstructured gridding of the saline formation using Delaunay triangulation and transmissibility evaluation between each pair of adjacent cells. Simulations have been done using a connection list based simulator. Several examples, including injection to a formation with or without fractures and with different hydraulic fracture length, have been simulated based on data from an actual CCS project.

Results have shown that the existence of mudstone layers could prevent injected CO2 from leaking outside the reservoir when no fractures are present. While vertical fractures intersecting with mudstone layers will cause significant leakage increase as the fractures forms extremely preferential pathways for CO2 transport. On the other hand, if fractures are far enough away from the CO2 plume, it could alleviate dramatic pressure buildup caused by CO2 injection in the formation and thus help expedite CO2 propagation.

This work presents a systematic way of modeling CO2 sequestration in saline formations with natural or hydraulic fractures. The main application is to help improve evaluation and planning of possible CO2 storage location selection to identify and quantify possible leakage risks through existing or induced fractures in the injection process.
Thermal Properties of Formations From Core Analysis: Evolution in Measurement Methods, Equipment, and Experimental Data in Relation to Thermal EOR
Authors: Popov Y. A. , Spasennykh M. Y. , Miklashevskiy D. E. , Parshin A. V. , Stenin V. P. , Chertenkov M. V. , Novikov S. V. , Tarelko N. F.
Published: February 2011

New methods and instruments developed for measurement of rock thermal properties (thermal conductivity, thermal diffusivity, volumetric heat capacity, and coefficient of linear thermal expansion) have provided a sharp increase in the quality of experimental data for reservoirs and surrounding formations. Optical scanning technology primarily provides numerous high-precision, nondestructive, noncontact measurements of thermal conductivity and diffusivity directly on full cores, core plugs, and nonconsolidated rock samples and enables determination of thermal property tensor components and the recording of thermal property variations along cores. The instrument for simultaneous determination of thermal conductivity, diffusivity at formation temperature (up to 250 degC), and three-component pressure (pore, confining axial, and lateral) enables measurements at formation conditions to study thermal property variations during the heating of reservoirs and oil production in thermal enhanced oil recovery (EOR). The instrument for measurements of the coefficient of linear thermal expansion at temperatures up to 250 degC within every temperature interval of 20 degC provides measurements on core plugs that account for rock anisotropy. Application of the new techniques to study more than 8,000 cores from 17 Russian oil-gas and heavy oil fields provided a representative thermal property database for sedimentary rocks saturated by brine, oil, and gas, accounting for rock anisotropy and inhomogeneity as well as formation pressure and temperature. New correlations between thermal and other physical properties were established. The new experimental data demonstrated that previous information on thermal reservoir properties often needs to be significantly corrected. The new instruments provided detailed information on the spatial and temporal variations in the thermal reservoir properties during thermal EOR. Authors used this to construct detailed 4D reservoir models for estimation of reservoir thermal regime, thermal losses, and heat and mass transfer within reservoirs, enabling better design and optimization of thermal methods of EOR.
Application of CT-Conveyed Perforating with the Sand Jetting Technology on North Sea Deep Horizontal Tight Gas Producer
Authors: Fryzowicz R.. , Naughton-Rumbo R.. , Schrama E..
Published: February 2011

Tight gas developments in the high cost environment of the North Sea are becoming economical and operators are focusing on the technology required to realise these plays and extend field and facility life. Operating companies are targeting tight gas reservoirs with low to very low permeability with long deviated and horizontal wellbore sections. Close attention to the perforating method is required in order to optimise hydraulic fracturing operations whilst minimising rig time.

Sand jetting technology has been in use by various industries for many years. Although theoretical papers for oilfield applications were published as early as the 1960s (Brown et al, 1960), it was only after advances in steel metallurgy in the last decade that tools could be made robust enough for real-world oilfield use. In addition, simulation software has improved greatly in recent years, yielding better predictability for this type of operation.

This paper will describe coiled tubing-conveyed sand jetting perforating operations for a five stage multi-frac horizontal gas well in the Southern North Sea. The goal of the operation was to create perforations with minimal entrance friction, reduced tortuosity during treatment, and minimise the chance of multiple fractures. Such a treatment would reduce the chances of premature screen-out and the associated costly rig time as well as allow for optimised placement of the proppant following a tip screen out (TSO) design. The challenges associated with performing the operation on a small, unmanned satellite platform will be described, along with pre-job planning and operational steps taken to ensure the sand jet tool could reach the target depths in the deviated well.