bluuebunny/crossref_metadata_2025 huggingface dataset:
DTS Sensing: An Emerging Technology Offers Fluid Placement for Acid
Authors: Reyes Robert , Glasbergen Gerard , Yeager Valerie , Parrish Joseph
Published: October 2011

Distributed temperature sensing (DTS) is used on wells to determine the effectiveness of acid treatments. The technology uses a fiber-optic cable to read temperature in real-time, which allows for validation of fluid placement. In the case studies presented in this paper, effectiveness was determined during the pumping of the job. Using this process, the operator was able to decide if a change to the design needed to be made in real-time during pumping. The effectiveness of the acid job was dictated by how effective the fluid was placed into all zones. Concerns related to the acid treatments included where the acid was placed in the well, if the acid went where it was supposed to, and if the acid went into the first least-resistive zone and subsequent zones went untreated. If the latter took place, then investment capital for gallons of acid was not used wisely. The acid treatments included a wide variation of stimulation methods, such as stimulation of the formation using fracturing or matrix rates, varying the acid percentage, varying the type of acid, using linear, gelled, or crosslinked acid, varying the rate, and using diverters. Historically, on acid jobs, surface readings for pressure and rate were the only indicators to judge the effectiveness of the treatment. As the operator attempted the previously mentioned acid treatments and also monitored the treatment using DTS, it was observed that what is seen at the surface can be misleading. This is because surface pressure can be masked by friction and is therefore not a valid indictor for what occurred down hole, and because diversion can take place without surface indication. DTS allowed for practical adjustment to the diversion strategy for the well that was being treated. Candidate selection is highly recommended when using the DTS-number process. Placement of stimulation fluid was and is critical to well stimulation. DTS allowed real-time analysis to determine in real-time if stimulation was effective during the job.
Understanding Production from Eagle Ford-Austin Chalk System
Authors: Martin Ron , Baihly Jason , Malpani Raj , Lindsay Garrett , Atwood W. Keith
Published: October 2011

The US Energy Information Administration's forecast gas price is below USD 5/Mcf through the 2011 calendar year, prompting many historically gas-focused companies to shift their portfolio emphasis to oil. South Texas has been a hotbed for oil development for the last half a century. The last great oil boom in south Texas occurred in the Austin Chalk formation in the 1970s and early 1990s. Today, the Eagle Ford Shale has renewed oil exploration interest in South Texas.

The Eagle Ford Shale is a very prolific play that for the most part is bounded on top by the Austin Chalk formation. Many operators are wondering if the oil being produced from the Eagle Ford Shale is essentially the same oil (from both a source and geochemical standpoint) as the Austin Chalk. Owing to the tight nature of the shale, it is highly unlikely that oil is being produced solely through pore flow into hydraulic fractures. The industry has not fully grasped the storage mechanism in the Eagle Ford Shale and the factors that indicate a good producing area versus a mediocre one.

This paper studies the possibility that the Austin Chalk and Eagle Ford Shale form a single hydrocarbon system. The potential source, generation, migration, storage, and production mechanisms of both formations will be analyzed from a geologic perspective. The implications of this theory for exploiting the Eagle Ford Shale will also be discussed. From a production standpoint, this paper will compare the production trends of horizontal wells in the Eagle Ford Shale and Austin Chalk formations, analyzing each in detail to determine if there are any similarities in initial production rates and decline trends.

This paper investigates the areal extent of production from the Eagle Ford Shale and Austin Chalk formations and discusses their interdependencies. In addition, geological and petrophysical attributes are evaluated to understand this phenomenon. Lastly, this paper describes the key mechanism(s) for oil/condensate flow in these oil-producing reservoirs and how to best exploit these unconventional formations.
A Coiled Tubing Perforating Solution Incorporating a Gun Deployment System and Dynamic Underbalance Technique Improves Well Production in High Angle Deep Gas Wells in Saudi Arabia
Authors: Al Jubran Hasan , Leal Jairo , Al BuHassan Shaker , Bolarinwa Simeon , Kharrat Wassim , Pulson Dave , Barnawi Mazen
Published: October 2011

Saudi Aramco has recently initiated a change in gas well design in the Ghawar field of Saudi Arabia. The new approach is to drill deviated cased hole gas wells through the reservoir to increase the length of contact of the productive zone and thereby increase production potential. Typical gas wells were drilled as a vertical cased hole through the reservoir or open hole horizontal gas wells.

The increased well deviations, measured depths and resultant increase in reservoir sections required a new approach to the perforating solution for these wells to connect them to the gas plants. Various techniques were reviewed, considering safety, operating efficiency and well performance. The final solution was to deploy the perforating systems on electric coiled tubing (CT) and run all the guns in one run using completion insertion and retrieval under pressure (CIRP) as a deployment system, which allowed the guns to be run and pulled under live well conditions without having to kill the well.

This paper details the learning curve and lessons learned from the implementation of this technique in five gas wells. The deployment system and pressure control equipment were optimized to satisfy Saudi Aramco's requirement for three barriers. A CT cleanout run was added before perforation to remove any debris from the wellbore causing a problem to the depth correlation tools. An existing CT tower was used to support the very long wellhead stack, but due to its height limitation a special solution was implemented to enable safe CT operations. A deployment system under live well conditions was used to minimize CT runs, operating time and cost savings. The static underbalance condition was set before running the guns, combined with the dynamic underbalance perforating technique and deep penetrating charge gun design were implemented to optimize the well performance. This technique allowed safe and efficient perforating in a single underbalance run of these five gas wells.

The paper also covers the planning of the perforating solution, health, safety and environment (HSE) considerations, equipment selection, operational procedures, job execution and results.
Threading the Needle: Optimizing Horizontal Wellbores Within Tight Vertical and Lateral Tolerances: A Case Study
Authors: Spotkaeff Matthew , Dolan James , Dupuis Christophe , Saicic Milan , Handels Martijn , Viandante Mauro , Perna Ferdinando , Stueland Eirik
Published: October 2011

The process of geosteering, using real-time logging-while-drilling data to actively steer horizontal or highly deviated wellbores, has been in use for more than 20 years. Over this period, the demand for more sophisticated measurements has developed along with the need to access increasingly difficult reservoirs as the simpler drilling scenarios are being exhausted.

Such a case is evident in the Yme Gamma development, located offshore south-western Norway, consisting of four horizontal producing wells and two vertical injectors. Abandoned by the original operator because of high water cut, to redevelop the field the current operator needed to drill subsequent wells in a narrow corridor up-dip between the existing producer wells and the bounding fault, in the thin YS 7 (4 to 8 m) inner-estuary sands or the YS 5/4 (2 to 6 m) inner/central-estuary sands.

The Yme 9/2-C-2A well was successfully drilled as a replacement for the C-2 well, which had been redrilled because of the reservoir being swept in that area. Since the neighbouring well, C-3T3, showed encouraging results in the YS 5/4 reservoir, which was not targeted in that well, a horizontal well was planned to exploit this reservoir.

There were several challenges that needed to be addressed in the geosteering of this well: the need to keep the wellbore within a narrow reservoir (between 2 and 6m in thickness); a very narrow lateral corridor between the main bounding fault and existing wells; observed sub-seismic faulting in neighbouring wells; and the possibility of a coal layer, which would necessitate a sidetrack if intersected.

As with any geosteering operation, success is often the result of a combination of inter-department team work and communication as well as the use of appropriate technology. Integrated use of a bed boundary mapping device and real-time density images allowed the 9/2-C-2A well to be geosteered within these tight tolerances, skirting the bounding fault by less than 1 m lateral displacement, and allowing for the drilling of other tight tolerance wells.
Cardinal Points to Achieve the Excellence in Horizontal Open-hole Gravel Packing Operations in Deep- and Ultra-deepwaters
Authors: Marques Luiz C. , Pedroso Carlos Alberto
Published: October 2011

In many instances Campos Basin has been a place of milestones in horizontal open hole gravel packing (HOHGP) in deep and ultra-deepwaters scenarios. However, to achieve the excellence in this field, we have continuously fine-tuned our operational practices and procedures to overcome different hurdles, such as: paucity of formation sand distribution analysis, poor understanding of the deposition profile of our turbidites and/or reservoir heterogeneities; poor understanding of gravel transport phenomena, use of newly-developed HOHGP tools (which had not been extensively field-proven yet), inadequate wellbore clean-up procedures, inadequate sand screens, excessive corrosion of screens during post-acid treatments, non-optimized well geometry, poor drilling-in practices, bad-tuned sand placement simulators (we ended-up developing our own one), unsuitable filtration practice, the need to complete - and gravel pack - long open hole wells with low fracture gradient in ultra-deepwaters scenarios and other Gordian knots.

After a somewhat-bumpy beginning, which is typical of any learning process, we have successfully managed to perform circa 350 horizontal long-interval open-hole gravel packs, and 170 frac packs (Statistics of 2011) in Campos Basin. Based on reliable and abundant data we have managed to gather from these operations, we have developed a field-proven bias in favor of gravel packs and frac packs (not a subject of this technical paper) as well. The following are the advantages associated with the application of these sand control measures: a higher-performance completion, a longer mean-time to failure, and a lower skin factor. So, when it comes to sand control, gravel pack and frac pack - wherever they can be applied to - are the first recipes we go for.

In summary, this paper describes the cardinal points to deal with in order to achieve the excellence in HOHGP operations. Case histories and lessons we have learned in this "no two wells are alike" scenarios are discussed as well. Statistics on our well-completion efficiency are also presented. A list of the cardinal points to achieve the excellence in HOHGP is presented below.
The Upstream Professional Development Center (UPDC): The Continuing Evolution of Upstream Professional Development
Authors: Aggour Tamir , Salamy Salam , G. Kersey David , Ghanim Abdullatif
Published: October 2011

This paper presents details of the development and implementation of a new upstream professional development initiative in Saudi Aramco. In response to quickly changing business and demographic environments, the approach to technical training has evolved to ensure a competent workforce that can effectively manage the technical challenges faced in exploration and production operations. The paper presents the business drivers leading to the establishment of a new state-of-the-art training facility and a new upstream training organization, along with details of the implementation of this new initiative. The result is a dynamic training organization that is responsive to evolving business needs, and accelerates the development of young professionals. In addition, experienced engineers and geoscientists benefit from receiving a structured professional development roadmap that spans their entire careers. By incorporating instructional design concepts, advanced training technologies and formal competency assurance, the Upstream Professional Development Center provides engaging, effective and efficient training that accelerates the achievement of competency and improves job performance.
Real Time Sand Production Management Using Non-intrusive Surface Ultrasonic Sand Monitors in TNK-BP Brown Fields in Western Siberia
Authors: Muslimov E. Y. , Medvedev P. V. , Shevchenko S. D. , Mironov D. V. , Afanasiev A. V.
Published: October 2011

The article discusses the conducted pilots in TNK-BP brown fields (Vaniegan, Samotlor) with non-intrusive surface ultrasonic sand monitors to optimize ESP lifted oil well regimes in real time. Existing produced solids monitoring practices in TNK-BP consist of regular sampling and require further filtration lab analysis. This process delays immediate corrective action implementation and provides only sporadic values of sand production. Excessive and abrasive sand production has a strong negative impact on runlife of artificial lift equipment and production systems. Today, ESP MTBF for high sand producers is 46 times less compared to analogue data field averages, which results in increased OPEX. The ultrasonic sand monitoring technology was applied to wells with frequent sand related ESP's failures to mitigate performance. Considered fields have up to 5% of such wells in the total amount. The first stage of the technology testing was a learning curve in installation, interpretation and matching outputs with the lab tests. Second stage included various tests in regulating the wells to achieve optimum balance between fluid and sand production using the surface choke and ESP VSD. Optimization of flow rates to control sand production was verified and backed up by sampling and lab analysis with over 103 tests performed within the pilot activity. Observations showed a significant reduction in sand production was achieved in various cases with minimal impact on fluids production with a trend of irregular sand production patterns observed in most of the cases. Because of the large number of wells in the fields, the new and preferred method of installiation is in the automatic group metering unit was proposed and successfully trialed. Detectors accuracy decreases with velocity below 1 m/s. Not all wells had a response to regulation. The areas for further technology development are related to specifics of on-land operations in Siberia. This includes power supply option improvement, absence of wireless data transfer or memory on the sensor for data storage. The method of real time solids monitoring was trialed for the first time in our company. This allowed discovering new opportunities to optimize performance of high sand producers and to scale up the technology to the other TNK-BP fields in the future.
Drilling and Under-Reaming in the GOM Deepwater Ultradeep Lower Tertiary: History of a Record Run in the World's Deepest Oil or Gas Well
Authors: Ubaru Charles , Thomson Ian , Radford Steven
Published: October 2011

Operators have been drilling deepwater prospects in the Gulf of Mexico (GOM) since the late 1980s. However, technology has evolved tremendously enabling deepwater operators to explore deeper frontiers. Many of the recent promising GOM deepwater prospects are targeting the lower tertiary sedimentary dispersal system that is regionally continuous from the coastal zone to the deepwater basin. Many of these wells seek ultradeep targets with total vertical depth (TVD) ranging from 28,000 - 35,000 ft (8534-10668 m).

To reach these deep lower tertiary reservoirs in the middle Paleocene to early Eocene age (Wilcox Group), operators must overcome many drilling challenges, including wellbore integrity, borehole stability, pressure management, destructive vibrations and suboptimum drill bit and under-reamer performance when drilling at these greater depths.

Due to the nature of the well construction and completion programs of these deepwater ultra-deep wells, which very often require over six casing strings, concentric expandable under-reamers are regularly used to maximize the wellbore final section size.

As these lower tertiary sandstones can be highly abrasive and hard, especially under extremely high confining pressures, bit and under-reamer durability has become a huge challenge. This paper will focus on the deepest successful 12 ¼ -in underreamer run in the world (31,400 ft or 9571 m TVD), achieved when drilling the deepest oil or gas well ever drilled., with emphasis on the selected under-reamer characteristics, bit selection and best drilling practices used.
Remote Operations - A Remote Possibility, or The Way We Do Things ‘Round Here?
Authors: Cramer Ron , Hofsteenge Hetty , Moroney Tom , Gobel Derek , Akpoghiran Fidelis , Murthy Ajith
Published: October 2011

Shell aspires to maximize unattended operations for all upstream E&P "green" and "brown" field assets using the appropriate level of automation. The benefits associated with down manned operations include the following:

Reducing staff exposure to travel hazards e.g., driving, sailing and flying Reduce staff exposure to process hazards at the well site and drill floor Increased production due to continuous monitoring and optimization by expert staff CAPEX saving due to elimination of unnecessary facilities such as process simplifications and reduced number of offshore beds OPEX savings due reduced travel and reduced logistics Increased staff productivity due to less time spent travelling Reduced GHG emissions as a consequence of reduced travel and improved process efficiency

The underlying premise is that the E&P process should as much as possible be monitored and controlled from a remote monitoring/control room staffed by the most experienced and capable people.

For "green field" facilities the basic design concept that we aspire to is unattended as the norm and attended as an exception that has to be clearly justified.

For "brown fields" we aspire towards as much as possible reducing attendance, again by monitoring and controlling from remote control centers.

This paper will describe the following:

Shell's overall remote operations strategy Technologies associated with remote operations, inclusive of production deferment reducing techniques such as data analytics and well/reservoir surveillance Shell guidelines associated with remote operations EP remote operations experiences in a number of different assets in Europe, USA and Africa

This paper demonstrates that, for Shell, remote operations is not a remote possibility, but is in the process of becoming a reality across our global upstream operations.
Acid-Fracture Conductivity Correlations for a Specific Limestone Based on Surface Characterization
Authors: Rodrigues Valdo F. , Campos Wellington , Medeiros Ana C. , Victor Rodolfo A.
Published: October 2011

Acid-fracture conductivity prediction is a key aspect in acid fracturing design and consequently in the oil and gas production forecast and economic evaluation. Acid-fracture conductivity correlations have been developed for some groups of calcareous rocks with a wide range of properties distribution. The experimental part of these studies has been based on samples from quarries and outcrops. This paper presents the development of conductivity correlations, which differs from previous studies by focusing on a specific oil producer limestone (Quissamã-ESP), by use of samples from well whole cores, and by performing comprehensive 3D surface characterization of the acid-etched fractures. Fractures were acid-etched in the lab with four types of acid systems at proper similarity conditions. The experimental study included core samples preparation, surface scanning with a laser profilometer, and rock strength and conductivity measurements. The 3D surface characterization not only supported the development of a conductivity correlation based on usual parameters, fracture width and rock embedment strength, but also enabled the development of correlations based on surface characterization parameters. It was also useful to manage experimental artifacts, to define the etching pattern, and to obtain more accurate fracture width calculation. The results showed that acid-etched fracture surfaces are rougher than usual engineering surfaces and present negative skewness, high kurtosis, and an intermediate isotropy - mostly random but with some spatial orientation. Four types of exponential acid-fracture conductivity correlations were developed for the Quissamã-ESP limestone, all them more accurate than the Nierode and Kruk correlation, adopted as a reference. The initial conductivity in the most accurate correlation is a function of a surface characterization parameter, while the rate of conductivity change with closure stress is a function of the rock embedment strength. The use of surface characterization parameters can improve the prediction of the initial conductivity, but not the rate of conductivity change with closure stress. Further studies will be necessary to improve the rate of conductivity change with closure stress prediction and to evaluate the possibility of structure creation, such as channels, in the acid-fractured surfaces.
Channel Fracturing in Horizontal Wellbores: the New Edge of Stimulation Techniques in the Eagle Ford Formation
Authors: Rhein T. , Loayza M. , Kirkham B. , Oussoltsev D. , Altman R. , Viswanathan A. , Peña A. , Indriati S. , Grant D. , Hanzik C. , Pittenger J. , Tabor L. , Makarychev-Mikhailov S. , Mikhaylov A.
Published: October 2011

The hydraulic channel fracturing technique relies on the engineered creation of a network of open channels within the proppant pack, which provides for highly conductive paths for the flow of fluids from the reservoir to the wellbore. These channels are created through a process that combines fit-for-purpose geo-mechanical modeling, surface equipment controls and fluid and fiber technologies. This paper reports the first implementation of the channel fracturing technique in horizontal wellbores.

A section of the Eagle Ford formation (TVD 10,900 - 11,500 ft) in the Hawkville field near Cotulla, Texas was selected for this study. This section comprises mainly limestone with 100 to 600 nD permeability and 7 to 10 % total porosity. The formation requires horizontal laterals with multi-stage hydraulic fracturing for economic production.

The channel fracturing technique was evaluated in twelve horizontal wells. Results from thirty eight offset wells treated with conventional techniques (slickwater or hybrid-type treatments) are also reported to compare performance. Non-normalized data from this sample of fifty wells showed hydrocarbon production increases ranging between 32% and 68% in favor of the channel fracturing technique.

The Hawkville field comprises a gas-rich section and a condensate-rich section. Reservoir simulations were performed on a sample of four wells located in the gas-rich section and two wells located in the condensate-rich section of the field to generate sets of normalized production data. These simulations accounted for variations in completion strategy, bottom hole flowing pressures and reservoir quality. Normalized production data for the sample of wells located in the gas-rich section of the field showed that the channel fracturing technique increased gas production by 51%. Normalized production data for the sample of wells located in the condensate-rich section of the field indicates increase in condensate production by 46%. Results from these history matches are consistent with the hypothesis that the channel fracturing technique enabled higher production by two concomitant mechanisms: increased area of contact with the reservoir and enhanced connectivity between the reservoir and the wellbore through highly conductive channels.

Positive features that were also observed during this campaign such as the elimination of near-wellbore screen-outs and significant reductions in proppant and water consumption are also summarized and discussed.
New Ways in Research and Education: The Effect of Real Field Data on Multi-Disciplinary Student Projects in Petroleum Engineering
Authors: Reinicke Kurt M. , Ganzer Leonhard , Teodoriu Catalin
Published: October 2011

When abandoning its "diploma curriculum" and implementing its bachelor/master program Petroleum Engineering in 2004, the Institute of Petroleum Engineering (ITE) of Clausthal University of Technology in Germany included a mandatory group project in the new curriculum. Group projects are interdisciplinary full time team efforts by approx. 6-8 students over approx. 8 weeks. Since 2008 all projects are carried out on real data from real fields. The recent group projects are defined around the data for five oil fields abandoned in the 1990ies at 15 USD/bbl scenarios. The data include seismic, logs, core and fluid data, production and injection data, abandonment information, well and field files. The data together with financial assistance were provided by a major oil company in Germany to allow students to work with the data and come up with plans for the redevelopment of the fields. University staff is coaching the groups with further support coming from industry experts. Results achieved by the students are presented at the end of the group projects in front of a panel formed by faculty and industry experts. In the process, the data providing Oil Company will receive a "peer reviewed" concept that may be further adapted to the company utilization.

Many SPE papers presented over the years the achievements of various universities through the aid of real field data and the student work. Yet we want to present a "real field data" project that has been successfully implemented at Institute of Petroleum Engineering (ITE), TU Clausthal, Germany. This paper summarizes the experience gained during more than 2 years of integrated group projects with real data and strong industry involvement.
Well Site Risk Screening: The Critical Few
Authors: Powell Bill D. , Van Scyoc Karl C.
Published: October 2011

Assessment of well risk potential is an important factor for well integrity management, yet there are few alternatives for rapidly screening production well site risk. Often, a small proportion of the total well inventory has the greatest risk; these wells warrant the most detailed analysis and allocation of resources to assure that well integrity is maintained. Wells with less operational risk may have proportionally fewer risk controls. Thus, for safety, environmental, economic and business reasons, on-shore oil and gas operators benefit by efficiently identifying the critical wells among the thousands being operated so that limited resources can be applied to gain the most benefit.

This paper reviews the development process for one such well site risk screening approach that combines safety and environmental risk criteria while assuring ease of use and application of sound risk principles. The paper outlines the development process along with the rationale for selection of primary screening criteria, key assumptions, approximations, and input data. Furthermore, the authors reflect on the key learnings following application of the screening method for over 10,000 operating wells in North America.

Keywords: Well Integrity, Risk Assessment, Consequence Modeling, Dispersion
Failure to Produce: An Investigation of Deficiencies in Production Attainment
Authors: Nandurdikar N. , Wallace L.
Published: October 2011

The economic importance of delivering on planned production volumes is undeniable. Over the last 15 years, however, the oil and gas industry's production attainment performance has degraded. Today, the average oil and gas project delivers only 75 barrels for every 100 barrels promised at sanction. This paper reports on a root-cause analysis conducted on over 145 oil and gas projects for which the authors have access to planned production volumes (at sanction), and 12 months to 60 months of actual production data. The authors use a detailed global database of oil and gas projects to conduct a rigorous statistical analysis of production attainment. The analytical strategy is to statistically connect "inputs" (i.e., information and practices used prior to sanction) to "outputs." The results show that poor production attainment is due to unreliable forecasts based on optimistic subsurface assumptions, failure of assurance processes, and lack of accountability for production volumes. Our analysis shows that project teams are overly optimistic about basic subsurface characteristics, especially in the absence of actual data. Assurance and decision analysis processes, such as peer reviews and risks modeling, are not successful in identifying optimistic forecasts. Every project with a significant production shortfall used these tools, yet these tools failed to flag the risks. Most companies lack a single point of accountability for delivering production. In most cases, no one is accountable if the production falls short of promise. These problems persist because companies do a poor job of conducting root-cause analysis to understand production shortfalls; only 30 percent of projects in this database conducted such an analysis. The analysis provides strong evidence that the industry has a problem in predicting production volumes. But the authors go beyond this observation and provide the reader with valuable take-aways, including specific causes of the problem and recommendations to eliminate, or reduce, this problem.
DFA Asphaltene Gradients for Assessing Connectivity in Reservoirs under Active Gas Charging
Authors: Zuo Julian Y. , Elshahawi Hani , Dong Chengli , Latifzai Ahmad S. , Zhang Dan , Mullins Oliver C.
Published: October 2011

Identification of reservoir compartmentalization, quantification of flow connectivity, and assessment of compositional gradients are critical for optimal reservoir characterization, production, and management, especially in deepwater developments. Downhole fluid analysis (DFA) provides a useful tool to measure composition, gas/oil ratio (GOR), density, and color (linearly associated with asphaltene content). In particular, DFA is the method of choice to measure gradients of reservoir fluids vertically and laterally. Based on DFA measurements and advanced asphaltene science, a new modified Flory-Huggins regular solution model that has been referred to as the Flory-Huggins-Zuo EOS has successfully been developed and used to delineate reservoir connectivity recently. It provides the industry's first predictive asphaltene grading equation of state (EOS) and has proven reliable to predict connectivity in equilibrated oil columns. The theory shows that asphaltene gradients can be large owing to both the gravity term and GOR gradients.

In this case study, we demonstrate that the methodology for equilibrated reservoirs can be extended to nonequilibrium oil columns. We employ the new asphaltene Flory-Huggins-Zuo (FHZ) EOS for a reservoir currently undergoing active charging of biogenic gas. Isotope analysis shows that the biogenic methane is not equilibrated in this column. Nevertheless, the local asphaltene concentration within the column is shown to be equilibrated with the local GOR value and gradient. Based on the properties computed by the Peng-Robinson EOS with methane influx, the FHZ EOS for asphaltenes - originally formulated for equilibrium columns - may also be used to model the asphaltene (color) gradient in this nonequilibrium oil column. The obtained 2-nm asphaltene diameter is also consistent with field and laboratory data and is part of the Yen-Mullins model of asphaltene science (size of asphaltene nanoaggregates). This methodology establishes a powerful new approach for conducting DFA color grading analysis by coupling the Yen-Mullins model, and the FHZ EOS with DFA to address reservoir connectivity in reservoirs under active gas charging.
Monitoring on CO2 EOR and Storage in a CCS Demonstration Project of Jilin Oilfield China
Authors: Ren Shaoran , Niu Baolun , Ren Bo , Li Yongzhao , Kang Wanli , Chen Guoli , Zhang Hui , Zhang Hua
Published: October 2011

Jilin oilfield, located in Jilin Province of Northeast China, is conducting the first large scale demonstration project on CO2 EOR and storage. During the first stage, CO2 separated from a nearby natural gas reservoir (20–97% CO2 content) is injected into the northern part of Hei-59 oil block. Currently, the targeted oil reservoir, with an area of 1.7 km2 and oil reserve of 0.78×106 tons, has six CO2 injectors and twenty-five production wells with an inverted seven-spot injector-producer pattern. Up to now, nearly 150,000 tons of CO2 has been injected for a miscible flooding, and an expected incremental oil recovery of 10% would be achieved. In order to better evaluate the reservoir performance and ensure a safe injection and long-term storage of CO2, a monitoring program has been designed and deployed to monitor the EOR performance and the state of CO2 in the reservoir.

The monitoring techniques used include CO2 tracers to monitor gas breakthrough in production wells and flow of CO2 across the reservoir, and bottom-hole pressure survey of producers to evaluate the miscibility effect on EOR combined with production data analysis. Geophysical techniques are also employed to detect possible fractures and their orientation and dimensions, which include electric spontaneous potential measurement and micro-seismic detections. Cross-well seismic is intended to monitor the flow and track the front of CO2 between wells. Data of geochemical monitoring from produced water can be used to estimate the amount of CO2 dissolved in reservoir fluids. CO2 dissolution in formation water and residual oil is one of the main storage mechanisms, which can greatly enhance the safety and effectiveness of subsurface storage. In this paper, the results of reservoir monitoring applied in the oilfield are present and analyzed, and forward work will be focused on optimizing EOR performance and verification of the geo-capacity storage in the targeted reservoir.
Game Changing Technology for Treating and Recycling Frac Water
Authors: Ely John W. , Horn Aaron , Cathey Robbie , Fraim Michael , Jakhete Sanjeev
Published: October 2011

This paper addresses an advanced oxidation and precipitation water treatment process employed as an on-the-fly fluid pretreatment during hydraulic fracturing operations. The water treatment technology will allow for substantial reuse of flowback and produced fluid while at the same time completely replacing liquid biocide and scale inhibitor fluid treatment during fracs. Additionally, the treatment process generates zero waste. To date, the technology has been used on hundreds of wells successfully treating over 17 million barrels. The paper will report on more than 2 years of field operations on hundreds of frac stimulations as well as numerous pilot operations in multiple shale plays. Dynamic tube-blocking tests show that the treated fluid will not deposit scale even after days of storage in an open frac tank. Field sample testing shows the injected brine has 3 to 6 log-cycle kill of sulfate-reducing and acid-producing bacteria populations. With the move toward environmentally safe chemicals, an economical process eliminating chemicals is a step forward for our industry. The equipment is purposely designed to segue directly into the fracturing process without interfering with service company pumping operations or having any compatibility problems with any service company products. Our paper will show definitive results from field operations of an economic water treatment system that will allow for a reduction in liquid chemical usage and closed-loop management of wastewater. The newest design would treat 80 barrels per minute, occupying a footprint roughly the size of a frac tank. The units can be deployed in tandem for higher flow rate requirements.
Integrating Fracture Diagnostics and Engineering Data in the Marcellus Shale
Authors: Mayerhofer Michael J. , Stegent Neil A. , Barth James O. , Ryan Kevin M.
Published: October 2011

This paper presents results from a group of Marcellus shale horizontal wells. The wells were completed in sequential order with preplanned fracture and reservoir diagnostics to better understand completion and stimulation efficiency and drainage patterns given a certain well spacing in the Marcellus Shale. Insights were gained by integrating microseismic fracture mapping, diagnostic fracture injection tests (DFITs), downhole pressure gauges, post-frac pressure transient analysis, nontoxic chemical tracer and production data.

Microseismic fracture mapping was performed during the completion of two offset horizontal wells. Since the two wells were completed sequentially, it was possible to deploy downhole pressure gauges in one well while the offset well was being completed. This procedure allowed for the unique opportunity to monitor potential communication between the two wells and correlate this with the overlap of microseismic activity. The gauge was also used to monitor the initial post-frac buildup in that well. A second buildup test was conducted after approximately 5 months of production.

The integration of various engineering data leads to interesting conclusions with respect to effective fracture length, correlation of microseismic events with actual hydraulic fracture communication, and production interference. These insights provide important information for optimizing infill drilling, well placement, and fracture completion strategies in the Marcellus shale.
A Variable Rate Solution to the Nonlinear Diffusivity Gas Equation
Authors: Barreto Abelardo B. , Peres Alvaro M. , Pires Adolfo P.
Published: October 2011

The hydraulic diffusivity equation that governs the flow of compressible fluids in porous media is nonlinear. Although gas well test analysis by means of the pseudo pressure function has become a standard field practice, the effect of viscosity and gas compressibility variation with pressure is often neglected. Moreover, in field operation, the gas well is submitted to a variable rate production in order to determine well/reservoir properties and an estimation of the absolute open flow (AOF). For slightly compressible fluids, variable rate can be properly handled by superposition in time. Unfortunately superposition cannot be offhand justified to gas reservoir due to its non-linear behavior. In this work a general solution which properly accounts for both fluid property behavior and variable rate is presented. The proposed solution, which is based on Green's Functions method by considering the viscosity-compressibility product change as a non-linear source term, can handle variable gas rate for several well and reservoir geometries of practical interest. From the general solution, an analytical expression for variable rate tests of a fully penetrating vertical well in an infinite gas reservoir is derived. This expression is applied to a synthetic data set to calculate the pressure response for a buildup test in an infinite homogeneous reservoir. The results compared to a finite difference numerical simulator shows close agreement. It is also shown that the dimensionless pseudo pressure converges to the slightly compressible fluid solution for long shut-in times. Thus, at such long times, Horner analysis and log-log derivative plot can be applied to obtain good estimative of reservoir parameters as already discussed previously in literature.
Surfactant Formulation Study for Bakken Shale Imbibition
Authors: Wang Dongmei , Butler Raymond , Liu Hong , Ahmed Salowah
Published: October 2011

This paper investigates an idea for chemical imbibition using surfactant formulations to stimulate oil recovery from oil shale. One goal of this research is to identify a formulation that promotes imbibition while minimizing clay swelling and formation damage. Experiments directed toward this goal involved balancing the temperature, pH, salinity, and divalent cation content of aqueous fluids to enhance oil recovery from the shale with ultra-low porosity and permeability in the middle member of the Bakken formation in the Williston Basin of North Dakota. The ultimate objective of this research is to determine the potential of surfactant formulations to imbibe into and displace oil from shale, and examine the viability of a field application.

Using spontaneous imbibtion, brines and surfactant solutions with different water compositions were examined. With oil from the Bakken formation, significant differences in recoveries were observed, depending on compositions and conditions. Cases were observed where brine and surfactant (0.05–0.2 wt % concentration) imbibition yielded recovery values of 1.55 to 76% OOIP at high salinity (150–300 g/L: 15–30 wt %) and temperatures ranging from 23°C–120°C. Six key observations were noted: (1) an ethoxylate nononic surfactant, an internal olefin sulfonate anonic surfactant, and an amine oxide cationic surfactant were more stable than the other surfactants for temperatures from 105–120°C. They were effective in imbibing and displacing oil at high temperature. (2) Adding alkali to surfactant formulations increased oil recovery from Bakken shale. However, sodium carbonate reacted with divalent cations and precipitated when added to our highly saline brines. To counter this effect, sodium metaborate was added to surfactant solutions to reduce or prevent precipitation. (3) An ethoxylate nononic surfactant and an internal olefin sulfonate anionic surfactant were more tolerant of high salinity than other surfactants and display higher oil recoveries at high temperature. For Bakken cores, surfactants did not imbibe effectively using distilled or low salinity water. (4) Varying the hardness of the surfactant formulation had a major effect on imbibition and oil displacement. (5) In some cases, clay flaking from the shale was observed when contacting brine (without surfactant) or contacting amine oxide cationic surfactant with higher alkane numbers in brine. However, for the later situation, it could be improved by changing pH of surfactant solution. (6) For a given surfactant, oil recovery can be maximized by identifying the optimal surfactant concentration, brine salinity, sodium metaborate concentration, and divalent cation content.
Theory of Unipole Acoustic Logging Tools and their Relevance to Dipole and Quadrupole Tools for Slow Formations
Authors: Wang Tsili , Dawber Mike , Boonen Paul
Published: October 2011

A simplistic mathematical model has been developed to study a unipole acoustic logging tool. The model allows us to quantitatively relate a unipole tool response to monopole, dipole, and quadrupole tool responses, and vice versa. The interconnections between the different forms of excitation and reception provide some useful insights into the acoustic tool physics. The model is confirmed by numerical simulations.

The unipole flexural wave sensitivity to shear slowness has been carefully studied. Numerical modeling and slowness-time-coherence analysis show that unipole, dipole, and quadrupole appear to have similar sensitivity to the shear slowness of a slow formation. The dispersion results suggest that a unipole flexural wave cannot be dispersion corrected based on any standard wave mode such as a dipole mode. Instead, the dispersion effect needs to be corrected by considering the mode-mixing nature. The look-up table approach used for this study represents the first step in the development.

The unipole sensitivity to azimuthal shear anisotropy is studied. Substantial sensitivity is observed from the modeled responses in an azimuthally anisotropic medium. The same is true for a simplistic dipole tool. A conceptual quadrupole tool in the same formation shows reduced variation in waveforms with the rotation angle. Dispersion correction of the unipole flexural waves from the anisotropic formations is attempted by treating the formation as being isotropic. Corrections of the slow shear waves are less satisfactory.

Interesting relations among unipole, dipole, and quadrupole also are revealed from a large-borehole scenario. The models confirm that in a large borehole with excessive tool eccentricity, both dipole and quadrupole responses may approach that of a unipole tool as some of the dipole and quadrupole excitation and reception sectors lose their proximity to the borehole wall. The modeling also shows that the dispersion effect in a unipole wave will be dependent on tool standoff, implying the necessity of standoff measurement for accurate dispersion corrections.
Reservoir Surveillance - Fluid Contact Monitoring in Fractured Carbonate TA-GOGD Project
Authors: Edwards John , Brown George , Vincent Mark , Keshishian Avo , Putra Pristiwanto , Bettembourg Solenn
Published: October 2011

TA-GOGD is suited for heavy oil in fractured formations. Steam is injected into the fractures serving two purposes; applying a gas gradient across the carbonate blocks so that the oil in the carbonate drops down by gravity, and heating the carbonate blocks so that the reduced viscosity oil drips out faster. The reservoir has two fluid systems; gas/oil/water levels in the fractures, and gas/oil/water contacts in the carbonate. Oil extracted from the carbonate accumulates in the fractured oil rim, where it is produced by wells intersecting the fractures. It is essential to manage the oil rim position and thickness. Wireline interventions with gradio manometer are not safe where steam is injected at 55 bars and 271°C. This temperature is too hot for permanent electronic gauges, but is within the operating range of optic fiber used to measure distributed temperature.

A new measurement to determine the fluid levels was developed using differential thermal relaxation. Cold water was pumped around a U tube containing an optic fiber and clamped outside the perforated tubing across the open hole until the temperature at the reservoir depth inside this U tube was considerably less than the hot surrounding gas, oil and water. With the pump stopped, the rate at which the cooler water inside this U tube reached thermal equilibrium with the warmer well bore fluids was measured with rapidly repeated distributed temperature surveys. Gas, oil and water have different specific heat capacities and thermal conductivities, so each surrounding fluid took a different length of time to heat the cooler water inside the U tube. The differences caused sharp discontinuities on the initial temperature logs of the warming water inside the U tube at the depths of the fluid contacts. The fluid levels measured with this method are sufficiently accurate to manage the oil rim.