bluuebunny/crossref_metadata_2025 huggingface dataset:
Quantification of Low Levels of Mercury in Gas Reservoirs Using Advanced Sampling and Analysis Techniques
Authors: Harfoushian Jack H.
Published: June 2014

In addition to health, safety, and environmental issues, the presence of mercury can potentially have a huge impact on the economics of a gas development project. A mercury removal unit (MRU) must be designed in order to reduce mercury concentrations to below detectable levels to prevent such issues as liquid metal embrittlement (LME) which could lead to catastrophic events. It is therefore imperative to accurately quantify levels of mercury in a gas reservoir to design gas processing and mercury removal equipment accordingly.

Without consistent and precise procedures, accurate quantification is challenging with current technologies used in laboratory apparatus, especially when concentrations of mercury are very low. The conventional method of mercury content quantification is by analysis of samples captured either with wireline formation testers or while drillstem testing (DST) a well. However, these measurements are rarely in line with what is observed once a field is put on production. Loss of mercury due to adsorption by a DST string or by the metal surfaces of sample chambers and sampling tools is significant, especially when the sampling point is thousands of feet away from the producing reservoir. In addition to reaction with metals, test results have also shown how mercury can go undetected if reservoir fluid samples are compromised by small amounts of drilling fluids or mud filtrate. There have been a number of catastrophic failures in gas processing plants attributed to liquid metal embrittlement, such as the explosion at the Skikda LNG plant in Algeria in 1973, or the more recent 2004 New Year's Day Moomba gas plant fire which was confirmed to be due to LME in an aluminum vessel.

Workflows detailing procedures for capturing, storing, if required, and analyzing representative gas samples for the quantification of low levels of mercury have been developed, tested, and proven. Results of recent experiments conducted simulating downhole sampling conditions reveal the reasons why there have been numerous cases in which false negative results were obtained from laboratory analyses. Advanced focused sampling methods together with accurate downhole fluid analysis with wireline formation testers have been applied in the field to provide representative reservoir fluid samples for quantification of mercury levels.
Pressure and Temperature Transient Analysis: Hydraulic Fractured Well Application
Authors: Ribeiro Priscila M. , Horne Roland N.
Published: June 2014

Recent developments in bottomhole data acquisition techniques, such as distributed temperature sensing systems (DTS), have brought attention to the potential increase of information that can be obtained from temperature data. Studies have shown the application of temperature surveys to estimate flowrate profiles, resolve the kind of damage around the well, improve the robustness of the history matching, among others. Nonetheless, Temperature Transient Analysis (TTA) is not a mature technique and its capabilities have not been explored fully yet.

In order to investigate the application of temperature analysis to the hydraulic fracturing problem, in addition to pressure analysis, a numerical model was developed to calculate pressure and temperature responses. Regarding the fracture and reservoir fluid flow, a general approach can be adopted, where the formation permeability and fracture characteristics dictate how the fluids flow during and after fracture growth. We developed a comprehensive model, which accounts for the pressure effect on the temperature response, as well as a dynamic fracture that grows and eventually is allowed to close during falloff.

In this research we analyzed the temperature and pressure responses during and immediately after hydraulic fracturing in order to improve our knowledge of this complicated physical problem. Based on this study, we can better understand not only the fracture properties, but also the reservoir itself. In addition, sensitivity analysis shows how reservoir permeability can impact final fracturing performance, as well as pressure and temperature responses. The developed model is also applied to simulate minifrac analysis, and a field example is presented that shows a good agreement with the simulated behavior during fracture closure.

This paper highlights the potential of Temperature Transient Analysis, expanding the application of temperature in addition to pressure transient analysis to improve the characterization of fractured wells:

TTA has potential to reduce uncertainty related to fracture length and reservoir permeability. TTA also adds value to DTS information, which is commonly measured but often not fully used. Temperature analysis has the potential to give reliable information about the flow dynamics of the reservoir and especially about near well zone.
Optimum Perforation and Changed Stimulation Treatment for Improving Zonal Productivity: Key Enablers for Strategic Reservoir Management of Deep HP-HT Sour Carbonates in North Kuwait
Authors: Pradhan San P. , Acharya Mihira N. , Fidan Erkan , Rao Narhari S. , Al-Awadhi Mansour , Singh J. R. , Dashti Qasem M.
Published: June 2014

Deep HP-HT sour carbonate reservoirs in Northern Kuwait have varied matrix properties and fracture intensities. The wells are drilled with barite laden OBM with 1,000-2,000 psi overbalance. The intervals suffer substantial formation damage during drilling as is evident from the fact that the wells normally do not get activated, in spite of creating an underbalance of 5,000-6,000 psi by displacing mud with a lighter fluid.

During the early exploration phase of these reservoirs, long and/or multiple intervals were perforated and treated with conventional matrix stimulation using 28% retarded/ emulsified acid in stages with chemical diverter (gel based and visco-elastic surfactant based). Post stimulation PLT survey in these wells indicated, that only about 5-10% of the total perforated interval contributed to the production; concluding that the diverters were found to be ineffective leading to sub-optimal reservoir management due to poor zonal contribution.

As part of strategic reservoir management process selective bottom up approach in perforation with higher concentrations of HCl treatment and without diverter has been adopted in these reservoirs. To obtain a degree of diversion over the perforated interval, the acid was pumped at higher rate and with higher pressure. Adoption of this changed perforation and stimulation treatment has been proved to be the key enablers for improving zonal productivity.

Around 30 wells have been completed with this changed perforation strategy and treated with this new recipe and technique. Post stimulation test results are comparable to those wells treated with regular matrix stimulation. The PLT survey post acid wash treatment by this technique showed that zonal contribution has improved. This process in addition to being simpler is faster and cost effective. This paper presents the comparison between the two types of perforation and stimulation strategies vis-à-vis test results and also the QA/QC followed prior to pumping the acid.
Analyzing Completion Efficiency Using Modified Heterogeneity Index
Authors: Salman Ahmad , Chen Jiansheng , Rasdi Faisal
Published: June 2014

Completion techniques in the unconventional reservoirs are continuously evolving. Yet a method to evaluate completion efficiency is still lacking. This study proposes a method employing the conventional Modified Heterogeneity Index (MHI) to evaluate completion competency and reservoir quality.

Hydraulic fracturing is designed to maximize reservoir contact. The hydraulic fractures may grow beyond the target or landed geologic zones due to an improperly planned or executed stimulation. This paper first shows the vertical water saturation profile and the observed correlation between water saturation and water cut. These results help to understand reservoir communication between multiple stacked reservoirs and hence help to quantify completion effectiveness.

Modified Heterogeneity Index is traditionally used in conventional reservoirs to monitor water breakthrough and normalize producer well performance in a water-flood field. This paper proposes a method to exploit the HI analyses and understand the correlation between water production and well productivity. The analysis is also tied to completion techniques to understand completion efficiency and its relation to reservoir properties.

This paper demonstrates that (a) correlation between water saturation, water cuts and production indicates that water saturation is one of the key reservoir properties governing production, (b) modified Heterogeneity Index can be utilized to scrutinize the completion effectiveness and reservoir quality, (c) the new method can be used pro-actively to screen for re-frac candidates and to forecast or estimate the possibility of pressure communication between offset wells.
ASP Flood of a Viscous Oil in a Carbonate Rock
Authors: Panthi Krishna , Sharma Himanshu , Mohanty Kishore K.
Published: June 2014

The goal of this work is to develop an alkaline-surfactant-polymer (ASP) formulation for a viscous oil carbonate reservoir. A large number of phase behavior studies were performed to find a low interfacial tension (IFT) ASP formulation for the viscous oil. The reservoir dead oil was diluted with decalin to get a viscosity equal to that of the live oil (105 cP). The surfactant formulation was tested with an outcrop vuggy dolomite core in both tertiary and secondary modes. Waterflood recovered about 47.8% of the oil in place and reduced the oil saturation to 43.8%. The tertiary surfactant flood increased the cumulative oil recovery to 92.7% whereby the oil saturation was reduced to 7.3%. During secondary surfactant flood, the oil saturation was reduced to 3.1% and the oil recovery was 95.6%. The ASP core floods were modeled by the UTCHEM simulator. The modeling showed a reasonable match between the experimental and simulation results. Experimental data for surfactant phase behavior, polymer viscosity, and surfactant adsorption were useful in matching the experimental results. The effect of divalent ions in the connate water was negligible because the injection brines were softened and the core consisted only of dolomite which has little solubility in water at the experimental conditions.
Experimental Investigation of Water Saturation Effects on Barnett Shale's Geomechanical Behaviors
Authors: Lin S. , Lai B.
Published: June 2014

Shale gas is one of the most rapidly expanding trends in onshore domestic oil and gas exploration and production today. Improving the performance of shale gas wells typically requires the improvements of fracturing technologies. One of the most important factors that affect hydraulic fracture propagation is the geomechanical property of rocks (Young's modulus, E and Poisson's ratio, ν and so on). In reservoir conditions, most reservoir rocks contain a certain amount of connate water, which indicates geomechanical properties measured by using dry samples suffer substantial flaws.

This paper is to experimentally investigate the impact of water saturation effects on Barnett shale's geomechanical properties (Young's modulus, E and Poisson's ratio, ν and uniaxial compressive strength (UCS)). Nineteen Barnett shale cores (satisfied with ASTM standard) were first partially saturated with KCL water to various water saturation degree. A Material Testing System (MTS-810) was then employed to test the elastic properties and UCS of those partially saturated Barnett shale's samples under uniaxial conditions.

Experimental results show that 1) water saturation has a significant impact on Young's modulus and UCS. Young's modulus decreases 6.1‰ with an increase of a water saturation (1%) of Barnett shale core corresponding to the value of dry shale's Young's modulus. 2) Young's’ modulus and UCS decrease linearly with increasing water saturation. And 3) the relationship between water saturation and Poisson's ratio is not obvious. In another word, the water saturation does little impact on Poisson's ratio. Correlations predicting elastic properties and UCS under reservoir water saturation conditions from dry core samples are proposed based on experimental findings in this paper. The improvement of accuracy of predicting geomechanical properties of Barnett shale can better understand hydraulic fracture propagations, improve wellbore stability and optimize hydraulic fracture design in Barnett shale reservoirs.
In-situ Disintegrating Completion Tools by Means of Controlled Microgalvanic Cells
Authors: Zhang Zhihui , Xu Zhiyue , Salinas Bobby J.
Published: June 2014

The technology advancement in horizontal drilling and hydraulic fracturing makes it economically viable in exploration of unconventional oil and natural gas resources where conventional drilling is ineffective. In fact, more than 90% of the wells drilled today are hydraulically fractured. Despite the efforts, there exists demanding challenges to reducing the cost of non-productive time during well drilling and completion. Traditionally, many downhole disposable tools such as frac-balls, disks or plugs that are used for sleeve actuation and isolation of different production zones during fracturing, or control valve actuation for production, are disposed artificially through either a re-entry such as drilling out or flowing back that is limited by the available lightweight materials subject to early yielding or severe shape change.

The concept of in-situ disintegrable tools made of materials that are lightweight, high-strength and have a controllable corrosion rate simplifies operations and represents an obvious advantage. In this work, the integration of light weight and a high corrosion rate is realized in the dissimilar metal composites forming micro-galvanic cells. Simultaneously, an ultra-high strength is achieved through engineering the micro/nano-matrix and secondary nanoscale metallic and/or ceramic additions. The corrosion tests were conducted in 3% potassium chloride (KCl) at 200 °F. The results show the nano-engineered composite materials exhibit a disintegration rate that can be controlled between 10 and 400 mg/cm2/h with ultra-high strength up to 80 ksi. The interaction mechanism between the matrix and nanoscale secondary phases was studied using scanning and transmission electron microscopy. The improved mechanical properties were analyzed in the framework of micromechanical models and the perspective to further increase the material strength was discussed. Field application tests show the completion tools made with the composites reliably eliminated artificial intervention and opened a flow path within controlled time in the natural downhole fluid.
Lessons Learned from 27 Years' Experience of Stimulation Vessel Design and Operation - a Case Study
Authors: Martin A. N. , Austin S. , Glennie A. , Martinez J. , Bradford S.
Published: June 2014

The operating envelope and environmental demands for hydraulic fracturing and stimulation treatments in the North Sea are increasingly larger and more complex. As a result, a generation of vessels designed and built in the 1980s are increasingly unable to achieve operational, economic and/or environmental goals. Thus, a new generation of vessels must be designed specifically to meet these European requirements.

The design characteristics of a new vessel can be split into five categories: (i) stimulation plant (ii) marine systems (iii) environmental protection (iv) welfare of the crew and (v) regulatory compliance. All five categories are critically important to achieving the stated goals for the new generation of European vessels, and all require careful integration of current cutting-edge technology with forward-thinking design concepts that will enable technical evolution over the expected 30-year lifetime of the new vessels.

This paper will outline the most significant problems faced by the current generation of stimulation vessels, compare current technological solutions to those problems, and demonstrate that integrating those technologies in a new vessel can achieve performance and flexibility far beyond what is possible by retrofitting them on an older vessel or in a modular system on the deck of a supply boat.

Tail-end production will have an increased importance in the North Sea and in all offshore production as a large number of producing fields near the end of their life. The effective deployment of production enhancement with stimulation vessels has a major part to play in extending field life.
Evaluating the HSE Risk Costs and Reputational Implications of Major Accident Hazards in E&P Activities
Authors: Petrone A. , La Rosa L. , Sordini E. , Scataglini L. , Dresda F. , Pavli E. , De Ghetto G. , Cherubin P. , Pellino S. , Bandini R.
Published: June 2014

The Cost of producing a barrel of oil depends on a variety of factors related to the inherent costs (direct and indirect) associated with oil field exploration, development, exploitation and lifecycle extension up to oil field decommissioning. Yet there are also other variables that enter this already complex equation and contribute to determine the final oil price.

Like any other industry, in the oil and gas business, accidents, have negative impacts on operational and financial performances, since they can adversely affect the production process and require proper restoring interventions.

Whenever people are injured, assets damaged, the environment polluted and business interrupted, money is unavoidably lost and company image and reputation is compromised. It is not easy to estimate the nature and extent of such losses and translate this estimate in a defined algorithm. However, different components can be evaluated through quantitative and qualitative methodologies.

Moving from these considerations, this paper presents a methodology aimed at evaluating the so called "Cost of the risk" of a Barrel of oil that takes into account the following elements:

Process Safety Risk Costs: to face the impact on people due to process Major accidents Occupational Risk Costs: to face occupational safety hazardous events Environmental Risk Costs: to address the impact on the environment due to a Blow out event or pipeline ruptures Asset Risk Costs: to manage the financial impact on the Asset due to process Major accidents Reputational risks costs: to manage potential impacts on reputation and negative perception of the public of the company
Environmental Stewardship: Global Applications of a Non-Radioactive Method to Identify Proppant Placement and Propped Fracture Height
Authors: Duenckel Robert J. , Palisch Terry T. , Han Xiaoganag , Saldungaray Pedro
Published: June 2014

Accurate assessment of intervals receiving proppant and the determination of near well bore fracture heights are valuable in assessing and optimizing stimulation strategies. Proppant placement evaluation in hydraulic fractures has traditionally involved the detection of radioactive tracers pumped down hole with the proppant. However, as environmental regulations regarding this technique have tightened, and with increased scrutiny by the public and regulatory bodies of the industry in general and hydraulic fracturing in particular, the need for an alternative to radioactive tracers has become paramount.

A new technology for assessing intervals receiving proppant and determining fracture heights utilizing a non-radioactive detectable proppant has been recently introduced. The technology has found global acceptance and has proven to be a robust and accurate method of locating proppant in the near well bore region. In addition to eliminating the safety and environmental concerns with radioactive tracers, this new method also provides a permanent indication of the proppant location near the wellbore. Unlike traditional radioactive tracers which must be logged before the radioisotopes completely decay, this new method will allow investigation of the proppant pack many years or decades in the future, which will provide critical information during remedial or redevelopment work that cannot be determined with conventional approaches.

A review of the current state of regulatory impediments to the use of radioactive tracers in key producing regions around the world is discussed highlighting the need for an alternative diagnostic technology. The technology utilized in the application of the non-radioactive detectable proppant is described and comparisons to other fracture diagnostic technologies are presented. Several case histories are shown which illustrate various applications of the technology in regions around the globe. These case histories include applications performed in Asia, Middle East, Europe and North and South America. In addition to identifying proppant location and fracture height, this technology can be used in other applications such as the evaluation of gravel pack quality. If the current trends in regulatory actions related to hydraulic fracturing continue, it is anticipated that the use of radioactive tracers will be restricted to fewer and fewer locales. At the same time the importance of reliable fracture diagnostics for optimization of hydraulic fracturing both from a well performance and cost control standpoint remains extremely important.
Polymer Flooding Pilot Learning Curve: 5+ Years Experience to Reduce Cost per Incremental Oil Barrel
Authors: Buciak J. , Sancet G. Fondevila , Del Pozo L.
Published: June 2014

This paper deals with the learning curve of a 5+ years polymer flooding pilot conducted in a mature water-flood that includes several works related to injector and producer wells, reservoir management, etc. The scope of this paper is to describe the learning curve during the last five years rather than the reservoir response of the polymer flooding technique; focus is on the aspects related to reduce cost per incremental oil barrel for a possible extension to other waterflooded areas of the field.

Diadema Oil Field is located in the San Jorge Gulf Basin in the Southern portion of Argentina. The field is operated by CAPSA, an Argentinean oil producer company; it has 480 producer and 270 injector wells. The company has been developing waterflooding during more than 18 years (today this technique represents 82% of oil production in the field) and produces about 1,600 m3/d of oil and 40,000 m3/d of gross production (96% water cut) with 38,400 m3/d of water injection.

The reservoir being polymer-flooded is characterized by high permeability (500 md average), high heterogeneity (10 to 5000 md), high porosity (30%), very stratified sand-stone layers (4 to 12 m of net thickness) with poor lateral continuity (fluvial origin) and 20 °API oil (100 cp at reservoir conditions).

Diadema's Polymer Flooding Pilot started in October 2007 on 5 water injectors (it includes 13 injectors today) with an injected rate of 1000 m3/d (today, 2000 m3/d). Polymer solution is made using produced water (15000 ppm brine) and 1500 ppm of HPAM polymer reaching 15/20 cp of fluid injection viscosity.

Oil rate production from the original "central" producers (wells that are aided with 100% of polymer injection) has increased 100% at the same time as average reduction in water cut is about 15%.

The main aspects presented in this work are: depth profile modification with cross-linked gel injected along with polymer, use of "curlers" to regulate injection in multiple wells with one injection pump without shearing the polymer and an improved technology on producer wells with PCP to decrease shutting time and number of pulling interventions.

The plan for the next years is to extend this project to other areas by using the acquired knowledge and to improve different aspects, such as water quality and optimization of polymer plant operation, among them. These improvements will allow the company to reduce operative cost per incremental oil barrel.
Distributed-Flux Burners Improve Life of Firetubes and Process Throughput in Heater Treaters
Authors: Bartz David , Silberstein Michael , Gotterba James
Published: June 2014

Polymer agents are being used to increase the yield of oil-sand reservoirs. While these polymers are effective in increasing yield, they present problems in heater treaters used for oil/water separation. In particular, the heavy oil and polymer emulsion can coat the outer surface of heater treater firetubes, creating an insulating layer that causes high wall temperatures of the firetube. This can lead to early failure of the firetube, causing costly shutdowns and repair.

The unique design of the distributed-flux burner solves this problem by providing uniform heat distribution over a greater area of the firetube compared to conventional burner technology. The burner utilizes premixed surface-stabilized combustion on a porous ceramic cylindrical surface. Heat release of the burner is kept constant along the entire burner surface. The burner is located in the center of the firetube along the tube axis, providing uniform heat distribution to the wall. This design significantly reduces the peak heat flux and film temperatures around the firetube found with conventional burners, which in turn reduces harmful thermal degradation of the firetube and coking of the oil mixture. Thermal analysis shows that for the same total energy input, the distributed-flux burner provides a 33% reduction in peak heat flux to the firetube wall compared to a conventional burner.

The distributed-flux burner technology has been successfully used in heater treaters in California and in asphalt heating tanks in Canada. This paper will present design data from a recent installation of the distributed-flux burner in a heater treater for a Canadian oilfield using polymer injection that had previously suffered frequent firetube failures.
A New Surveillance Method for Delineation of Depletion Using Microseismic and Its Application to Development of Unconventional Reservoirs
Authors: Dohmen T. , Zhang J. , Li C. , Blangy J. P. , Simon K. M. , Valleau D. N. , Ewles J. D. , Morton S. , Checkles S.
Published: June 2014

Hess Corporation performed microseismic monitoring of hydraulic fracturing in two infill horizontal wells in the Middle Bakken Play of North Dakota during 2011. Six vertical observation wells were drilled to monitor microseismic events. Each observation well was fitted with a pressure gauge in the Middle Bakken interval, capped by a bridge plug, and instrumented with 40 geophones. The experiment was specifically designed to observe the interaction of the fracs with a pre-existing Middle Bakken horizontal well, which had been on production for about two and a half years. The producing well was shut in for the duration of the experiment and instrumented with a downhole pressure gauge.

Experimental results show the hydraulic fracturing did not propagate as anticipated. Instead, the microseismic observations provided a very interesting result early during the stimulation of the first infill well. While fracturing the fourth stage of the first infill well, microseismic events appeared along the length of the nearby production well at distances up to 9,000 ft away from the open frac port. During this stage, and just prior to the appearance of the distant events, a pressure connection was established to the original well as recorded by the pressure gauge in that well. Our interpretation is that these microseismic events were distributed throughout the depleted zone surrounding the original production well. We provide evidence for the development of a cloud of depletion points through the use of pressure measurements, microseismic event speed plots, and Mohr's circle analysis.

This experiment provided a unique opportunity to "see" the shape of the depleted zone and to understand its influence in developing Bakken resources. By analyzing the outline of the depleted zone outline, we can now propose a series of reasonable infill well locations at a minimum distance from the original producer. We are leveraging microseismic as a tool to optimize the spacing of development wells. Our objective is to infill drill at the minimum distance required to maximize fracture contact in-zone near the infill wells and yet avoid significant overlap into previously depleted zones. Thus, a new application for microseismic monitoring is envisioned, in which one would pressure-up a producing well in order to measure its actual area of depletion prior to planning subsequent development wells and executing field-wide strategies for hydraulic fracturing.
sCore: A Mineralogy Based Classification Scheme for Organic Mudstones
Authors: Gamero-Diaz Helena , Miller Camron , Lewis Richard
Published: June 2014

In recent years, operators have produced large quantities of hydrocarbon from organic shale reservoirs. Horizontal drilling and multi-stage stimulations, targeting sections with superior reservoir quality (RQ) and completion quality (CQ), have been proven as key to their development. Organic mudstones, often referred to as shales, are fine-grained sedimentary rocks with total organic carbon (TOC) above 2% and typically complex mineralogy, consisting of a mixture of biogenic and terrigenous sources of siliciclastic and/or carbonate debris, affected by diagenetic processes. These rocks are highly heterogeneous especially perpendicular to bedding. Although numerous cores and outcrops have been studied and described, there is no published mineralogy-based classification scheme for organic mudstones. This paper defines a methodology for creating a detailed mineralogy-based description for organic mudstones using inorganic mineralogy, primarily X-ray diffraction (XRD) and geochemical log data.

The proposed classification scheme is based on a ternary diagram created specifically for organic mudstones by using a combination of core- and log-based mineralogical relationships. The primary classes are siliceous mudstone, carbonate-rich mudstone and argillaceous mudstone. Sub-classes are based on relative amounts of these three mineral groups. A mineralogy-based classification may help provide a better understanding of depositional conditions and identify target zones for completion. A common metric for the description of organic mudstones will also facilitate comparison of such reservoirs from different areas, formations, basins, and continents. A secondary objective is to provide a log display that flags other descriptive parameters that impact RQ, CQ and/or operational efficiency. A strong correlation exists between mineralogy and CQ in most U.S. shale plays. The correlation between mineralogy and RQ is not as strong. RQ appears to be driven by both compositional and textural components of organic mudstones. The log displays presented here provide a consistent description of the organic mudstone section and the input necessary for proper decision making when planning a drilling development project.
Correlation of Permeability for the Travis Peak Formation
Authors: Nzerem Vitalis , Civan Faruk
Published: June 2014

Civan's power-law equation of permeability derived based on a bundle of leaky tubes model of tortuous flow paths in porous media is proven to describe a large amount of permeability and porosity data of the Travis Peak Formation in Northern Gulf Coast Basin of the U.S.A. Its parameters are shown to correlate consistently well with the cementation factor. It is demonstrated that these correlations can be used for prediction of permeability in the field.
Improved Prediction of Multi-Component Hydrocarbon Fluid Properties in Organic Rich Shale Reservoirs
Authors: Zhang Yijia , Civan Faruk , Devegowda Deepak , Sigal Richard F.
Published: June 2014

The fluid properties modifications in nanoporous systems produced by the effect of pore wall potentials and the limited number of molecules in nanopores are investigated for liquid-rich shales. These properties include phase behavior, interfacial properties, gas and liquid transport, storage, and composition. The existing theoretical equations are modified to predict the vapor-liquid equilibrium for shale and the unique behavior of fluids in kerogen and inorganic pores. The pore geometry, molecule size, interaction between the sorbed molecules and the nanoporous framework are included to enable accurate prediction of fluid phase behavior, critical properties, and composition. The predictions of the proposed approaches are compared to results obtained using bulk fluid properties. The implications of ignoring the role of pore proximity on fluid properties can potentially be severe and can potentially compromise estimates of drainage areas, well spacing, recovery factors and reserves.
Smart Gas Lift Valves Enhance Operational Efficiency of Offshore Wells
Authors: Xu Zhiyue , Richard Bennett M. , Kritzler James H.
Published: June 2014

In a conventional gas lift system, dummy valves are loaded in side pocket mandrels to isolate the annulus from the tubing where pressurization is required to test the tubing, test the annulus, set a hydraulic packer or activate an isolation device. Then for gas lift, wireline intervention would be required to remove the dummy valves and install the live gas lift string. This can be a long, cumbersome process that can damage existing infrastructure and delay production while new live valves are installed. This paper presents a smart gas lift valve with disintegrable nanostructured composite material technology. The valve is installed in the well to function as a dummy valve during completion operations and then convert from a dummy valve to a live valve through in-situ disintegration of a nanostructured composite plug in brine during cleanup process. This eliminates multiple slickline trips or well intervention costs to replace dummy valves with live valves and significantly increases completion operation efficiency of offshore wells. The nanostructured composite plug is high strength, is chemically resistant to drilling mud, is slightly reactive with fresh water and disintegrates within 12 to 50 hours in salt water. The smart gas lift valves were successfully installed in 42 new wells that were artificially producing with gas lift offshore Southeast Asia. The nanostructured material, the valve design, the lab test data and results from successful field tests will be presented.
A Case History of Comprehensive Hydraulic Fracturing Monitoring in the Cana Woodford
Authors: Lowe T. , Potts M. , Wood D.
Published: June 2014

In the Cana Field in Western Oklahoma, horizontal wells are completed with multiple hydraulic fractures to economically produce from the Woodford Shale. This field development program is relatively young, and previous fracturing optimization had been achieved by trial and error testing. Cana wells usually are drilled with a 5,000-ft lateral, which is hydraulically fractured in 10-20 stages utilizing the plug-and-perf method with multiple clusters per stage. Throughout the early field development, there has been significant uncertainty regarding various subsurface parameters including: fracture propagation geometry, cluster contribution, and interference remediation. This paper describes a comprehensive fracture monitoring project, which will be used to further the understanding of the hydraulic fracture geometry, interference, deliverability, and production.

In late 2012, the project well was drilled as part of the infill development program. In January 2013, the well was completed with a 12 stage slickwater frac. Several established and cutting edge technologies were used to assist with monitoring the hydraulic fracturing operation of the subject and offset wells. These technologies included: Distributed Temperature Sensing (DTS), Distributed Acoustic Sensing (DAS), prototype cemented frac valves, permanent bottom hole pressure gauge, surface micro seismic, down hole micro seismic, offset bottom hole pressure monitoring, logging-while-drilling, advanced open hole logging, radioactive tracers, and chemical tracers. These technologies were used successfully to monitor cementing operations, offset fracturing, monitor well fracturing, coiled tubing drill-out, flowback, and initial production. This project has assisted in the understanding of subsurface events and is expected to provide continued insight into long term production. Similar projects are being considered for the future, and this technology may ultimately become part of the standard completion.

This paper will focus on the planning, logistics, installation, and operation of this one of a kind monitoring project in the Cana Field.
Pressure Transient Tests and Flow Regimes in Fractured Reservoirs
Authors: Kuchuk Fikri , Biryukov Denis
Published: June 2014

Fractures are common features in many well-known reservoirs. Naturally fractured reservoirs consist of fractures in igneous, metamorphic, and sedimentary rocks (matrix). Faults in many naturally fractured carbonate reservoirs often have high-permeability zones and are connected to numerous fractures that have varying conductivities. Furthermore, in many naturally fractured reservoirs, faults and fractures can be discrete (rather than connected network dual-porosity systems).

In this paper we investigate the pressure transient behavior of continuously and discretely naturally fractured reservoirs using semi-analytical solutions. These fractured reservoirs can contain periodically or arbitrarily distributed finite- and/or infinite-conductivity fractures with different lengths and orientations. In some of our earlier papers, we showed that in terms of pressure transient, neither continuously nor discretely fractured reservoirs behave like the Warren and Root (1963) dual-porosity model. Unlike the single-derivative shape of the Warren and Root model, derivatives of pressure transient tests in fractured reservoirs exhibit more than 10 flow regimes. There are seven important factors that dominate the pressure transient test-flow regime behavior of fractured and faulted reservoirs; i.e., fractures and/or faults that: 1) intersect the wellbore parallel to its axis, with a dipping angle of 90° (vertical fractures), including hydraulic fractures; 2) intersect the wellbore with dipping angles from 0° to less than 90°; 3) are in the vicinity of the wellbore; 4) have extremely high- or low-fracture and fault conductivities; 5) have various sizes and distributions; 6) have high- and low-matrix block permeabilities; and 7) have damaged fractures (skin zone) due to drilling and completion operations and fluids. All flow regimes associated with these factors are shown for a number of continuously and discretely fractured reservoirs with different well and fracture configurations. For a few cases, these flow regimes are compared with those from the field data. History matchings of the pressure transient data generated by using our discretely and continuously fractured reservoir model with the Warren and Root (1963) type dual-porosity models are also presented.
Influence of Hydraulic Fractures on Wellbore/Sandface Temperatures During Production
Authors: App J. F.
Published: June 2014

The influence of hydraulic fractures during production is to alter the wellbore/sandface temperature changes by reducing the magnitude of the Joule-Thomson expansion effect. Compared to an unfraced completion in which the flow path of the reservoir fluids is purely radial, the presence of hydraulic fractures lengthens the flow path the reservoir fluids must take by creating a linear flow geometry. For a given drawdown, therefore, the local pressure gradients are lower in a hydraulically fractured completion compared to a non-hydraulically fractured completion. Through dimensionless analysis it will be shown that the Joule-Thomson effect is proportional to the local pressure gradient squared which implies a reduction in the Joule-Thomson effect for a hydraulically fractured completion compared to a non-hydraulically fractured completion. Simulations from a thermal reservoir/wellbore model will be presented comparing the thermal responses between hydraulically fractured and non-hydraulically fractured completions. It will be shown that the presence of hydraulic fractures can reduce the wellbore/sandface temperature changes by much as 85% compared to a non-hydraulically fractured completion. Additionally it will be shown that measurement of sandface and wellbore temperatures during production can provide information to determine which intervals have been successfully hydraulically fractured, and to a lesser extent a qualitative assessment of hydraulic fracture efficiency.
Unlimited Multistage Frac Completion System: A Revolutionary Ball-Activated System with Single Size Balls
Authors: Yuan Feng , Blanton Eric , Convey Brent , Palmer Chris
Published: June 2014

In recent years, there has been tremendous growth in multistage fracturing for unconventional plays employing multistage fracturing completion systems with openhole (OH) packers or cementing to isolate multiple stages and ball-activated frac sleeves with graduated seats (traditional graduated-seat frac sleeves) to divert the fracturing treatments. This phenomenon has developed primarily because these systems not only maximize production, but also save significant completion time and money with the ability to perform multiple stimulations in a single trip, with minimal or no thru-tubing intervention.

However, traditional ball-activated frac sleeves have graduated ball seat sizes for each additional zone, and therefore, each ball seat creates its own backpressure within the system. With the number of frac stages increasing, the ball seat sizes become smaller, leading to an increase in the surface pressure and hydraulic horsepower (HHP) required to generate a given net downhole pressure or flow rate. In order to solve these limitations, a revolutionary ball-activated fracturing system has been developed, which can be installed with an unlimited number of zones using a single size ball and ball seat for each zone. This new technology can greatly reduce frictional forces and enables a more efficient fracturing of each zone within the wellbore. Most importantly, this new frac sleeve is sized to achieve an inside diameter (ID) as close as possible to the host tubular string, thus requiring a much lower fracturing pressure on the surface compared with traditional graduated-seat frac sleeve.

This paper will present the operational mechanisms of this new frac sleeve, simulation of frac efficiency and financial analysis with quantitative comparisons between it and traditional graduated-seat frac sleeve. The analysis will indicate that this new frac sleeve technology can be used to optimize hydraulic fracturing operations in both HHP requirements and stimulated reservoir volume (SRV) while dramatically reducing operational time and overall completion costs.
Optimum Decision-Making in Reservoir Managment Using Reduced-Order Models
Authors: Alghareeb Zeid M. , Williams John R.
Published: June 2014

Reduced-order models (ROM) are considered powerful techniques to address computational challenges associated with reser-voir management decision-making. In this sense, they represent perfect alternatives that trade off accuracy for speed in a controllable manner. In this paper, we describe a model-order reduction technique that entails the use of proper orthogonal decomposition (POD), truncated balanced realization (TBR) and discrete empirical interpolation (DEIM) to accurately re-produce the full-order model (FOM) input/output behavior. POD allows for a concise representation of the FOM in terms of relatively small variables while TBR improves the overall stability and accuracy. DEIM improves the shortcomings of POD and TBR in the case of nonlinear PDEs, i.e.; saturation equation, by retaining nonlinearities at lower dimensional space. In this work, the use of ROM reduced the computational time by O(100) while providing good overall agreement with FOM. The use of large reservoir simulation models is expected to add additional speedup factors.

ROMs are potentially perfect alternatives to FOMs in reservoir management intensive studies such as production optimization. However, ROMs presented in this paper and the overall physics-based ROMs have the tendency to perform well within a restricted zone. This zone is generally dictated by the training simulations used to build the ROM. Therefore, special care is considered when implementing these training runs. To mitigate the heuristic process of implementing the training runs, we apply a ROM based trust-region method that provides an adaptive framework to systemically retrain ROM during the optimization run.

The ROM approach with trust-region methodology is applied to a heterogeneous model containing 13,200 grid blocks and five wells. The accuracy of the ROM is first demonstrated for several testing simulations in which the injection and production rates for each well differ from those used to build the ROM. A waterflood optimization case is then considered to determine the optimum injection and production rates for four producers and one injector at five different times (total of 25 control variables). Results for optimized net present value using ROM based trust-region is shown to be very close to those achieved using the full order model with a difference of only 0.2%. The runtime speedup factor for this case was about 31. The ROM approach thus appears to be well suited for use in applications in which many simulations must be performed such as production optimization and uncertainty assessment.
Fracture Characterization in Unconventional Reservoirs using Active and Passive Seismic Data with Uncertainty Analysis through Geostatistical Simulation
Authors: Maity D. , Aminzadeh F.
Published: June 2014

This study discusses a new workflow for fracture characterization and modeling using geophysical (microseismic and 3D surface seismic) data along with independent reservoir information (such as well logs). The framework is ideally suited for unconventional environments such as shale and tight reservoirs where modern technologies such as the use of hydraulic fracturing and passive seismic monitoring allow application of the proposed workflow.

The workflow involves generating geomechanical property estimates (including stress and weakness estimates) as derived from passive seismic data analysis and relevant seismic attributes derived from 3D seismic data combined using ANN based reservoir property modeling framework. The training information for the networks is generated based on a-priori information through image logs. Resolution of passive seismic derived velocity models is improved by using sequential Gaussian co-simulation by combining low resolution velocity maps high resolution seismic impedance data for phase velocity estimation. Uncertainty estimates are quantified by adequate number of realizations and associated probability density functions for fracture properties within study volume.

In this paper, different properties estimated through ANN modeling have been shared. New fracture identifier (FZI) properties have been defined and the models have been used to characterize fracture zones and major discontinuities for a representative unconventional reservoir (geothermal setting) used in our study. We also share uncertainty estimates for the identified fracture zones for improved characterization. Finally fracture property estimates for the study area (derived using FZI and other properties) have been generated for future reservoir simulation studies.

The proposed method allows for improved understanding of shale and other unconventional reservoirs through fracture mapping and provides a workflow for improved volumetrics of the reservoir by making use of identified properties for fracture modeling. This work validates the potential for using relatively low resolution passive seismic data for improved reservoir characterization using Geostatistical tools. It also provides a valuable framework for pseudo 4D characterization where a single 3D seismic survey can be used as the basis to characterize the reservoir in a time lapse fashion using new information collected in time through passive seismic arrays as well as new well logs being obtained within the area of interest.