bluuebunny/crossref_metadata_2025 huggingface dataset:
Removal of Manganese Tetraoxide Filter Cake Using a Combination of HCl and Organic Acid
Authors: Al Moajil Abdullah Mohammed , Nasr-El-Din Hisham A.
Published: June 2014

The removal of filter cake generated by drilling fluids weighted with manganese tetraoxide (Mn3O4) particles may require strong acids [e.g., hydrochloric acid (HCl)]. Organic acids are not efficient with high-density drilling fluids (> 100 lbm/ft3) that contain large amounts of weighting materials (e.g., Mn3O4). A single stage of HCl treatment in a high-temperature and corrosive environment cannot be used. In certain cases, a two-stage treatment is recommended first to degrade polymers, and then to dissolve the solid particles in the filter cake. The reaction of acids with solid particles in the drilling fluids was investigated as a function of time at reaction temperatures up to 250°F. The solubility of the filter cake was examined using a high-pressure/high-temperature (HP/HT) filter press. Gas chromatography was used to analyze produced gases. Atomic absorption was used to measure the ion concentrations in spent acids, and X-ray diffraction was used to analyze solids. A safe, efficient, and economic technique that involves mixing HCl and an organic acid was developed to dissolve the filter cake in a one-stage treatment. The results showed higher removal efficiency (> 85%). The solubility of Mn3O4-based filter cake using 10 wt% HCl at 250°F was 80 wt%, but the reaction released chlorine gas, which is toxic and corrosive. HCl concentrations less than 5 wt%, the release of chlorine gas was not significant, but the solubility of the filter cake was low. Lactic acid alone did not dissolve the filter cake. However, a combination of 4 wt% lactic acid and 1 wt% HCl dissolved Mn3O4 particles completely at 190°F. At a temperature of 250°F, nearly 85 wt% of the filter cake was dissolved. This technique uses lower concentrations of HCl/organic acid, which would reduce the cost of the acids required for the treatment. Using HCl alone is an inexpensive approach but HCl cannot be used at concentrations above 5 wt% with Mn3O4-based filter cake. In addition, a third method was examined to remove the filter cake using a combination of organic acid and enzyme.
Large Scale Jet Pump Performance Optimization in a Viscous Oil Field
Authors: Singh Manjit K. , Prasad Dhruva , Singh Aditya K. , Jha Mihir , Tandon Rohit
Published: June 2014

This paper discusses the performance monitoring and optimization of large scale jet pumping in Mangala field, one of the biggest onshore fields in India. Mangala field is characterized by multi-Darcy sandstones, containing waxy and viscous crude oil. Currently, the field is producing at plateau of 150,000 BOPD.

The base development plan for the field included hot water flooding; this also makes water heated up to 80 °C available at the well pads as power fluid for jet pumping. Jet pump was selected as the preferred artificial lift method in deviated wells, as it addresses all flow assurance issues arising due to high wax appearance temperature of Mangala crude.

Jet pumps provide the required drawdown for sustained liquid production both at low and high water cut. With significant number of wells operating on jet pump, it has become crucial to monitor the performance and optimize for maximum efficiency application by varying operating parameters, changing the nozzle throat combinations and making other adjustments. Currently, Cairn is monitoring the real time jet pump operating parameters on a daily basis by virtue of DOF (Digital Oil Field). DOF has not only eased the tedious task of jet pump monitoring in bulk but also has reduced the response time to any failures/damage in the pump. Liquid handling capacity of the processing plant has become crucial with increasing field water cut and more jet pump installations. Jet pump performance optimization for maximum efficiency has now started to play an important role in not only reducing the burden of the processing facility but also in improving the production profile of the wells.

This paper will discuss the use of a methodology based on an in-house developed algorithm for monitoring the efficiency of the pumps, with supporting field examples. This paper will also make an attempt to analyze the effect of different operating conditions on the pump performance curves published in the literature.
Design and Execution of a Polymer Injection Pilot in Argentina
Authors: Hryc A. , Hochenfellner F. , Paponi H. , Puliti R. , Gerlero T.
Published: June 2014

A polymer injection pilot for El Corcobo Norte field started in January 2012 in Neuquén Basin, Argentina.

The pilot aims to improve volumetric efficiency for Lower Centenario unconsolidated formation.

El Corcobo Norte field produces medium-heavy oil and has been under waterflood since the very beginning of the field's production in early 2006. A fresh water source is used to make up oil volume and maintain the injection-production balanced.

The fact that Lower Centenario formation is strongly water-wet has helped to reach a successful waterflooding process. Field development plan was carried out with an inverted 7-spot pattern configuration of approximately 60 acres. Production strategy involves strong sand production during well completion, followed by a low constant sand cut during producer's life. Sand production, among other factors, has shown to be responsible for water channeling issues and even wormhole generation, that lead to a decreased efficiency and compromise reserves. Polymer laboratory experiments were conducted to design and calibrate numerical simulation, both lab and pilot scale.

This work will present the challenges faced for the design and implementation of a polymer pilot when dealing with medium-heavy oil, sand production and channeling in order to increase recovery factor. We will summarize as well the project's results up to date and lessons learnt in the field experience.
Spatio-Temporal Stress Path Prediction using A Fluid Flow-Geomechanical Model
Authors: Shahri Mojtaba P. , Miska Stefan Z.
Published: June 2014

In-situ reservoir stresses change during the production period due to the reduction in pore pressure. Consequently, the upper limit of the drilling mud window; i.e., formation fracture pressure, reduces corresponding to the pore pressure depletion. Since drilling operations in critical situations such as deep water and depleted reservoirs require precise prediction of the mud window, it's of vital importance to accurately assess the reservoir stress path; i.e., the change of in-situ stresses with pore pressure. Currently used models for reservoir stress path prediction can be divided into two main categories: space- and time-independent and spatio-temporal models. Space- and time-independent models have been used for several decades. According to industry demand of precise stress path prediction, spatio-temporal models have recently been developed for stress distribution determination within reservoirs. However, the developed stress path models are based on the transient flow regime and can not be utilized in depleted reservoirs wherein the pressure response usually reaches the reservoir boundary.

The aim of this study is to provide an analytical model for predicting reservoir stress changes at different times and locations within reservoirs during the pseudo-steady-state flow regime. Constitutive equations from the theory of poroelasticity are combined with a force-balance equation to find the relationship between reservoir stresses and pore pressure. The application of the proposed model for reservoir stress path prediction is illustrated using a numerical example.
The Dynamics of Fluids In Reservoirs
Authors: Mullins Oliver C. , Zuo Julian Y. , Dong Chengli , Elshahawi Hani , Seifert Douglas J. , Cribbs Myrt E.
Published: June 2014

Measurement of reservoir fluid gradients vertically and laterally in a reservoir captures a ‘snapshot’ of the evolution of fluid processes that take place over geologic time. Downhole fluid analysis (DFA) has enabled this reservoir fluid profiling to be performed in an efficient manner. Dramatically different fluid distributions are obtained in different reservoirs and can be categorized in terms of the extent of thermodynamic equilibrium attained. Factors that influence the equilibration process include the geologic timing of reservoir charging, possible secondary fluid processes, the extent of convection versus diffusion, the size of the equilibrating fluid component, and the size of the reservoir. Here, we show reservoirs that span a very large range, from very young reservoirs (Pliocene) that evidently exhibit stochastic distributions of solution methane over relatively small distances to old reservoirs (Lower Cretaceous) with equilibrated asphaltene clusters over immense distances. For each class of reservoir evolution, very different yet very important production concerns are identified. Characterization of the fluid columns in terms of (dissolved) solids, liquids and (dissolved) gases is found to be most informative for several reasons including 1) the large gradients associated with the different (dissolved) phases and 2) the important production concerns associated with the different phases. In particular, understanding the disposition of the asphaltenes in the reservoir is key for many purposes. This is accomplished using the industry's first equation for asphaltene gradients, the Flory-Huggins-Zuo Equation of State for asphaltenes, with its reliance on the Yen-Mullins model of asphaltene nanoscience. The ability to model all three crude oil phases within a proper thermodynamic framework enables the ability to track the evolution of these phases in the reservoir, bringing into view simplifying systematics that significantly improve risk management in production of these reservoirs.
How Does Innovation Happen in the Upstream Oil & Gas Industry? Insights from a Global Survey
Authors: Perrons Robert K.
Published: June 2014

Few would argue that the upstream oil & gas industry has become more technology-intensive over the years. But how does innovation happen in the industry? Specifically, what ideas and inputs flow from which parts of the sector's value network, and where do these inputs go? And how do firms and organizations from different countries contribute differently to this process? This paper puts forward the results of a survey designed to shed light on these issues. A joint research initiative between the Society of Petroleum Engineers and the Queensland University of Technology, the survey was sent to 469 executives and senior managers who played a significant role with regards to R&D and/or technology deployment in their respective business units. A total of 199 responses were received from a broad range of organizations and countries around the world. Several interesting themes and trends emerge from the results, including: (1) service companies tend to file considerably more patents per innovation than other types of organization; (2) over 63% of the deployed innovations reported in the survey originated in service companies; (3) neither universities nor government-led research organizations are considered to be valuable sources of new information and knowledge in the industry's R&D initiatives; and (4) despite the increasing degree of globalization in the marketplace, the USA still plays an extremely dominant role in the industry's overall R&D and technology deployment activities. By providing a detailed snapshot of how innovation happens in the upstream oil & gas sector, this paper provides a valuable foundation for future investigations and discussions aimed at improving how R&D and technology deployment are managed within the industry.
Application of New Fingerprinting Bacteria DNA in Crude Oil for Reservoir Charaterization-Part II
Authors: Hayatdavoudi A. , Chegenizadeh N. , Chistoserdov A. , Boukadi F. , Bajpai R.
Published: June 2014

In early 80's, while reassessing some old gravel pack sands from a well, we noticed some sludge in the samples. The sludge had plugged formation and the gravel pack pores. The permeability was so low that the owner of the oil property thought of abandoning the well and consequently stopped all workover measures. The owner stated that there was no more oil left in the reservoir. This observation and the previous ones in early 70's, in addition to the laboratory studies conducted at a later date, suggested the existence of bacteria in the oil. In the current study we implemented a novel, sensitive technique for bacterial DNA fingerprinting; that is, denaturing gradient gel electrophoresis of PCR amplified 16S rRNA genes. This approach allowed us to identify and classify bacteria found in the oil. The research enabled us to evaluate the application of our technique to evaluate the origin of oil in the reservoirs.

To prove the hypothesis that bacteria were present in oil, we requested an operating company to provide us with 6 samples taken from 2 separate wells, but drilled in the same reservoir or at least the operator believed both wells were drilled in the same reservoir. To characterize the oil and subsequently the reservoir, we implemented our procedure of fingerprinting bacteria DNA as follows: (1) DNA extraction from oil, (2) DNA concentration, (3) Making 0.7% and 1% Agarose gel, (4) Electrophoresis of total DNA isolated from oil, (5) PCR amplification of 16S rRNA gene fragment from DNA isolated from oil, (6) Running gel on the PCR product, (7) Running Denaturing Gradient Gel Electrophoresis (DGGE), and (8) Cycle Sequencing DNA.

The result from DNA concentration using our technique proved the existence of the bacteria DNA in all crude oil samples, which was not possible to find previously. Using the governmental open source data from offshore Louisiana and the results of researchers work available in the literature, we conducted a detailed geological and petroleum engineering study of the field in our study area. Furthermore, in order to find petroleum engineering applications for our discovery of DNA in crude oil we classified the bacteria and found the origin of the crude oil produced from each well in the reservoir. Based on our results, we found that Well B drained oil from a grassland, lacustrine, fresh water environment, whereas Well A drained oil from a very shallow marine environment. From the results, we concluded that, these two wells are not drilled in the same reservoir, implying that there may be enough oil left in both reservoirs to be drained by one or more wells.
Transport and Distribution of Proppant in Multistage Fractured Horizontal Wells: A CFD Simulation Approach
Authors: Bokane Atul , Jain Siddharth , Deshpande Yogesh , Crespo Freddy
Published: June 2014

Multistage hydraulic fracturing has become the key technology for completion of horizontal and vertical wells. The perf and plug method is the most commonly used staging method. In each stage, multiple perforation clusters are used, attempting to create a separate transverse fracture at each cluster. How these clusters are placed can significantly affect both short- and long-term production performance. Simultaneous creation of multiple fractures is a cost-effective and time saving method for stimulating both vertical and horizontal wells. Multistage fracturing is an effective method in terms of completion efficiency; however, achieving even proppant distribution to each cluster is an intricate task that proves to be challenging within the industry.

Numerical simulations predict uneven proppant distribution of the fluid streams entering different perforation clusters. Field data indicates, in many cases, that some of the clusters do not contribute to production. This led to hypothesizing that actual proppant and fluid distribution along the stimulated clusters can differ from the assumed uniform distribution. However, with respect to limited-entry frac design, the proppant distribution among the different perforations is assumed to be the same as the fluid distribution. Until recently, this assumption remained unchallenged.

This paper presents extensive study and investigation of proppant transport in different perforation clusters within a single stage by using computational fluid dynamics (CFD) techniques. Effects of varied fluid and proppant specific gravity, viscosities, proppant sizes, and slurry flow rates were analyzed while maintaining outside-casing parameters constant. Validation of empirical proppant transport CFD simulation results are compared to experimental test data. This is helpful to gaining a better understanding of fluid and proppant behaviors in multi cluster fracturing processes to achieve maximum efficiency.

The results of the study indicate that proppant transport can be accurately modeled when the effects of single particle settling, density driven flow, particle velocity profiles, and slurry rheology are all considered. The investigation demonstrates that CFD is an effective tool for optimizing proppant distribution among perforation clusters and enhancing production.
An Innovative Survey Method Using Rotating Sensors Significantly Improves the Continuous Azimuth and Inclination Measurement Near Vertical and Offers Improved Kickoff Capabilities
Authors: Bowler Adam , Sugiura Junichi , Lowdon Ross , Hawkins Richard , Jones Steve
Published: June 2014

When kicking off at low inclination, static measurement-while-drilling (MWD) surveys are used to confirm the kickoff direction, when free of magnetic interference from offset wells. However, as MWD continuous azimuth and inclination measurements have limited accuracy when near vertical, the directional driller does not have confidence in the kickoff direction with continuous (dynamic) survey while drilling. This requires additional static surveys to be made, taking up precious rig time.

In a novel continuous survey method used in a particular rotary steerable system (RSS), a six-axis survey was taken continuously, both while drilling and when static, with the surveys sensors being housed in a rotation-speed-controlled platform in the RSS. This algorithm was first verified in a software simulator, and it was subsequently implemented in hardware and tested in a hardware-in-the-loop-simulator environment. The effectiveness of the new measurement method was field tested and compared against MWD static survey points. The field test result shows that the new near-bit continuous azimuth and inclination from the RSS is considerably more accurate than that of the MWD continuous measurements at very low inclinations of between 1° and 5°.

This unique measurement method has valuable applications, such as low-angle kickoff without using multiple static surveys as the directional driller can use the continuous azimuth and/or toolface to accurately steer the well. Equally important is that if gyro surveys are required, their number will reduce as the survey measurement point is so close to the bit, reducing the amount of time of exposure to magnetic interference from an offset casing. When drilling out of the shoe, this survey method will allow an accurate kickoff approximately 50 ft earlier than would normally be expected as magnetic interference is cleared. Additionally, the use of a continuous gravity toolface is possible without the need for static surveys, allowing accurate low-side sidetracks to be performed even in areas of high magnetic interference. This surveying method reduces the rig time needed to kick off and provides a more reliable real-time measurement for the directional driller to ensure the desired well trajectory is drilled through crowded platform environments.
Performance of Multiphase Flowmeter and Continuous Water-Cut Monitoring Devices in North Slope, Alaska
Authors: Brady Jerry , Igbokwe Chidiebere , Montague Stuart , Warren Mike , Stadnicky Nick , Linder Mathew , Hall Andrew , Mehdizadeh Parviz , Roberts Bart , Lievois John , Rodriguez Daniel J.
Published: June 2014

Alaska's North Slope oil fields offer several different types of production environments that can prove challenging for effective production well testing with conventional gravity type test separators. The Prudhoe Bay field has mature production: high water cuts exceeding 90%, crudes with low 20s API gravity and gas-lifted wells with high gas volume fractions (GVF) >99.9%. The Milne Point field has viscous crude and light oil production and employs electrical submersible pumps (ESP), jet pumps and gas lift. This wide range of production methods and challenging fluid properties create challenges when analysing potential equipment and procedures to provide the critical production data needed to optimize overall production.

Over the last several years, BP Exploration (Alaska) Inc. (BPXA), installed over 24 infrared water-cut sensors. Nineteen water-cut devices have been installed in three-phase flow regimes at the wellheads. Five water-cut units have been installed on the liquid legs of two phase test separators. During this period BPXA also installed seven in-line multiphase meters—five in use at production pads for testing wells and two on individual wellheads.

This paper will discuss BPXA's experience with these metering devices over two years of operation, and present the verification process used to qualify the devices and their performance data. Additionally, successes, challenges and lessons learned are discussed.
Evaluation of Annular Pressure Losses while Casing Drilling
Authors: Dokhani Vahid , Shahri Mojtaba P. , Karimi Moji , Salehi Saeed
Published: June 2014

Casing Drilling is an innovative drilling method wherein the well is drilled and cased simultaneously. The small annulus of Casing Drilling can create a controllable dynamic ECD (Equivalent Circulating Density). Casing Drilling technology permits the same desired ECD as conventional drilling to be achieved using a lower, but optimized, flow rate, rheological properties, and mud weight. In this paper, the frictional pressure loss during Casing Drilling operation is evaluated using Computational Fluid Dynamics.

Annular pressure losses have received substantial attention in theoretical analyses, laboratory assessment and actual well measurements. Combinations of casing motion, annular eccentricities, wall roughness and fluid temperatures along the length of the annulus affect fluid flow regimes that control annular pressure losses. Current analytical solutions have limited applicability for complex conditions with pipe rotation and eccentricity.

In this study, the pressure losses during Casing Drilling operation are investigated using computational fluid dynamics. The results are compared against the available analytical solution and field data. The effect of pipe rotation and eccentricity on the frictional pressure loss is investigated as well. According to the simulation results, the pipe rotation reduces the frictional pressure loss for Yield-Power-law fluid which would be beneficiary during the casing drilling operation. It is found that the pipe eccentricity has a significant effect on the ECD calculation.

The industry is moving towards more challenging jobs in narrow pressure window scenarios such as deep-water and HPHT applications. Drilling with casing/liner is among the primary options to complete these sections due to strengthening effects associated with plastering the wellbore wall and also eliminating conventional drill pipe trip. Having accurate models for ECD including the effects of pipe rotation and eccentricity in the narrow annulus is essential to the success of these challenging jobs.
Resistivity-Based Pore-Pressure Prediction—Pitfalls and Solutions
Authors: Saleh S. , Williams K. E. , Rizvi A.
Published: June 2014

An investigation of resistivity-based pore-pressure estimation in sediments near salt bodies was conducted as part of a joint-industry project (JIP) that acquired, analyzed, and documented more than 100 wells in the Gulf of Mexico from shelf to deepwater (2005–2009). The result of this unique study culminated in the compilation of a comprehensive database that includes geophysical, petrophysical, and drilling data. This database was used to develop best practices for pore-pressure estimation below and around salt bodies.

Resistivity-based pore-pressure prediction is dependent on many variables including: porosity, salinity, temperature, fluid type, saturation, shale content, type of clay, and texture. Resistivity changes resulting from changes of pore water salinity near salt masses may give a false indication of pore-pressure changes. Approximately 50% of the subsalt wells show some signs of salinity variations near the salt (within ∼1,000 to 1,500 ft) that impact pore-pressure estimates for sediments adjacent to salt. Resistivity commonly responds to changes in pore water chemistry near salt; thus, there is a compelling need to recognize the salinity variation near salt bodies and find ways to account for these variations in resistivity-based pore-pressure analysis. This report presents exploratory efforts into possible approaches to achieve this goal.

Resistivity variations owing to salinity and temperature have been addressed using a dual water-modeling procedure, as published by Revil et al. (1998). This was used to generate a normalized resistivity. Normalized resistivity is then used as a primary input to conventional (Eaton 1975) pore-pressure analysis. The analysis of pore pressure from normalized resistivity remains an academic interest and has yet to be proven practical.

This paper shows good evidence for a potential improvement to be gained from normalized resistivity analysis. It is hoped that accumulated experience from applying this approach (resistivity normalization) will pave the way to an improved resistivity-based pore-pressure prediction analysis in sediments affected by salinity variations.
Static and Dynamic CFD Modeling of Viscoelastic Polymer: Trapped Oil Displacement and Deformation at the Pore-Level
Authors: Afsharpoor Ali , Balhoff Matthew T.
Published: June 2014

Understanding the flow behavior of viscoelastic fluids in porous media is critical for optimizing enhanced oil recovery (EOR). Polymers such as hydroxypolyacrylamide (HPAM) are used to improve sweep efficiency in reservoirs and these polymers often exhibit elasticity. Surprisingly, recent experimental and field observations indicate that these viscoelastic polymers improve oil recovery up to an additional 20%, contrary to the conventional wisdom that polymers should have no impact on residual oil saturation. Here, we attaempt to understand effects of viscoelasticity on residual saturation in water-wet and mixed-wet porous media. Static and dynamic computational fluid dynamics (CFD) simulations of oil droplets in the presence of viscoelastic polymer are conducted in geometries representative of pore throats. Results show that additional forces on the oil droplet are present for fluids that exhibit elasticity over those that do not (e.g. water) and those forces become larger as the oil droplet approaches a constriction. It is also shown using dynamic simulations that the amount of deformation of the oil droplet is greatly affected by the elasticity of the displacing fluid. These results are promising and provide a theoretical foundation for the laboratory and field observations of reduced residual oil.
Workflow to Image Unconformities with Deep Electromagnetic LWD Measurements Enables Well Placement in Complex Scenarios
Authors: Dupuis C. , Omeragic D. , Chen Y-H. , Habashy T.
Published: June 2014

The advent of deep-reading directional electromagnetic logging-while-drilling measurements brings opportunities in imaging complex formations around the wellbore. In this context, basing the inversions on an assumption of a layered medium is not always sufficient to decouple geometrical effects in complex formation scenarios.

Rather than attempting to invert all variables of a generic 2D formation model simultaneously, we describe in this paper how the use of 2D inversions can be enabled through a robust workflow specifically designed for a class of formation models, in this case the angular unconformity. We demonstrate how the successive application of 1D inversion to subsets of tool data gradually builds a formation model for use as input to a 2D inversion, which accounts for complex couplings present in the data in such environments.

The validity and the performance of the method are established through synthetic and field datasets.
Fluorous-Based Drilling Fluid for Ultra-High-Temperature Wells
Authors: Galindo Kay A. , Deville Jay P. , Espagne Bernard Jean-Luc , Pasquier David , Hénaut Isabelle , Rovinetti Sara
Published: June 2014

The growing industry demand to operate in high-pressure/high-temperature (HP/HT) environments (>10,000 psi and >350°F) requires robust drilling fluid performance to facilitate drilling under such harsh conditions. Several water-based and synthetic-based drilling fluids have met these high temperature operational challenges. However, despite the thermal stability of these fluid systems, deeper exploration has prompted the need for new technologies to drill in ultra-high-temperature reservoirs (>450°F). A fluorous-based drilling fluid can help meet these demands because fluorous materials are well-known to function in harsh chemical and thermal environments. Fluorous materials are composed of a carbon framework that is highly saturated with fluorine atoms. The increased electronegativity of fluorine relative to hydrogen provides fluorinated materials unique properties compared to their hydrocarbon counterparts.

Fluorous fluids and additives exhibit thermal stabilities upward of 600°F. The properties of fluorinated materials could assist drilling operations by increasing thermal stability, improving lubricity, minimizing corrosion, stabilizing shale, and increasing contamination resistance. However, because of the water- and oil-repellant nature of fluorous materials, conventional drilling fluid additives do not perform. The high inherent density of fluorous liquids allows fluorous drilling fluid to be formulated at high densities (16.0 to 20.0 lb/gal). Only 7% by volume barite loading was necessary to achieve 16.0-lb/gal density with the fluorous fluid, compared to 27% by volume barite loading required to prepare a 16.0-lb/gal water-based mud. A fluorous surfactant provided emulsion stability, and the required concentration was optimized for the fluorous-based fluid.

This paper presents the detailed laboratory study of a new fluorous-based drilling fluid that was formulated with 16.0-20.0 lb/gal densities, adequate suspension, and reasonable rheology with some degree of filtration control. Emulsion stability, rheological properties, suspension, and filtration control provided by the new drilling fluid system are also discussed. The fluorous-based drilling fluid potentially provides an ultra-high-temperature stable drilling fluid solution that can readily function in ultra-high-temperature wells.
Ream-On-Demand System Eliminates Dedicated Trip to Enlarge Rathole in Deepwater Gulf of Mexico Operation
Authors: Lirette Nicholas , Aubin Mike , Davis Jefferson , Duvvuru Hari , Nagaraj Mahavir
Published: June 2014

Hole enlargement while drilling (HEWD) is a frequent and well established practice in deepwater Gulf of Mexico operations. The most common BHA design positions a concentric underreamer above the complex MWD/LWD string to enable activation, increase stability and to ensure the enlarged borehole does not degrade LWD image quality. However, this conventional BHA configuration for HEWD results in a rathole of approximately 160 ft at TD. To open the rathole to an adequate size to accommodate the subsequent liner string, the operator is forced to trip the drilling BHA back to surface and perform a dedicated hole-opening run. This procedure is costly and can add a day or more to the well construction timeline. In a recent offshore well, the operator wanted to eliminate the trip to enlarge the rathole and land the liner shoe closer to the section TD.

To accomplish the objective, a dual reaming BHA system was developed with a conventional 12¼-in x 14½-in expandable underreamer deployed above the MWD/LWD and a new ream-on-demand (RoD) system positioned between the RSS and MWD. The RoD tool is equipped with an innovative hydraulic system that can perform multiple activations/deactivations of the cutting blocks. Because the RoD system does not require a ball drop to engage, BHA design flexibility is greatly enhanced.

Optimal tool configuration was determined by modeling the BHA with an FEA-based engineering system. The directional response of the RSS was also modeled to ensure the placement of the RoD system did not interfere with RSS directional capabilities. The RoD cutter blocks were configured to be passive when retracted to enable the underreamer to act as a control stabilizer providing a pivot-point for the push-the-bit RSS. At section TD, the plan was to pull the RoD tool above the rathole, activate the RoD cutter blocks and enlarge the 12¼-in hole to 14½-in as required.

The new tandem underreamer BHA was deployed on the deepwater project and drilled 1221 ft of section in 14.45 hrs at an average ROP of 110 feet per hour, while opening the 12¼-in pilot hole to 14½-in with the conventional underreamer. After reaching TD, the RoD system enlarged the 153 ft rathole from 12¼-in to 14½-in in only 3.5 hrs. The utilization of the dual hole opening system, in conjunction with an MWD/RSS eliminated the need to perform a dedicated rathole run to achieve the desired liner shoe depth. This paper covers the application the RoD system, tool design and pre-job risk assessment which saved the operator 16 hrs of rig time and reduced project costs by approximately $625,000 USD.
Shale Play Development Program Using Risk-Reward Mapping from Geospatial Analyses
Authors: Chorn Larry , Yarus Jeffrey , Rosario-Davis Suzanne del
Published: June 2014

Finding the best drilling locations in an extensive shale play holding is key to achieving production profile expectations and good economic metrics. Shale plays have been described as statistical plays. However, it becomes increasingly unacceptable to drill disappointing, underperforming wells as the operator and partners move from the exploration lifecycle stage into the appraisal and field development stages.

The physical and chemical properties of shales dictate the economic success of development drilling programs. It is recognized that at least seven parameters must fall within empirically-determined ranges for a play to have economic production rates and estimated ultimate recovery (EUR) exceeding threshold internal rate of return (IRR) requirements.

A geostatistical shale property workflow that high-grades 160-acre sections in a regional shale play, using a limited number of wellbores with standard logging suites is demonstrated. This paper extends the workflow from high-grading drilling targets to quantitative risk assessment. An application of the workflow to a multi-square mile U.S. shale play illustrates the analysis and its interpretation. The example shows that down-spacing well density in high-graded sections (high potential reward) is a quantitatively lower risk investment program than would normally be expected. Typically high reward opportunities, in the investment world, are expected to represent higher risk as well. Geostatistical analysis in the example play shows just the opposite behavior because the statistical nature of the local shale quality can be mapped and profitably drilled.

Exploiting this geostatistical, high-grading workflow can accelerate an operator's development program with higher rewards, lower risk, and better rates of return than pursuing a uniform development program over a large regional play.
Make Decision on the Fly: A New Method to Interpret Pressure-Time Data during Fracturing – Application to Frac Pack
Authors: Pirayesh Elias , Soliman Mohamed Y. , Rafiee Mehdi
Published: June 2014

Real time analysis of fracturing data is an invaluable tool for determining whether a fracturing job is progressing as planned. Therefore since the early days, understanding of fracturing pressure as a readily available diagnostic tool has been emphasized and practiced by the industry. Theories and techniques were developed for the interpretation of such data e.g. Nolte-Smith (1981).

The well-known Nolte-Smith method (1981) analyzes the pressure response of a formation during pumping, in order to predict the fracture geometry being created. Although this technique provides a highly reliable tool in terms of interpreting fracturing events, but in real time practices, it can take this technique quite a long time to detect a change in fracture behavior. This is partly due to the data compression associated with the Nolte-Smith log-log plot. Also Nolte-Smith technique necessitates prior knowledge of closure pressure of the formation which is not always known.

In this paper, we present a new method to analyze and interpret pressure-time data during fracturing. This method, which is based on a modification of Nolte-Smith technique, has proven effective in precisely interpreting fracturing behavior while the job is being carried out. Additionally it eliminates the short-comings of the original technique, as discussed above; meaning that the proposed method permits quick and accurate interpretation of fracturing data plus it needs no prior knowledge of formation in-situ stresses. This has been reached by a new innovative moving-reference-point concept assembled with a mathematical manipulation of the power-law fracture propagation theory.

Application of the new technique in the analysis of a variety of field cases including several frac packs and regular fracturing treatments has proven quite successful. First accurate pressure-time matches were obtained and then using these matches, the Nolte-Smith parameters were determined which in part allowed detection of fracture behavior changes (e.g. propagation to width-gain) usually in less than a minute and sometimes even in a few seconds of the start of the event.
Ten Years' Experience with Flare Gas Recovery Systems in Abu Dhabi
Authors: Saadawi Hisham
Published: June 2014

Abu Dhabi Company for Onshore Oil operations (ADCO) is one of the major oil producing companies in the Arabian Gulf. The Company produces oil from a large number of reservoirs in various fields which are different in size and are under different stages of depletion.

In order to achieve near zero flaring and reduce emission, the Company began implementing several projects for flare gas recovery in its oil fields more than ten years ago.

Various compressor technologies were selected to suit the specific field applications. These included: liquid ring, sliding vane compressor, both dry screw and oil-wet screw compressors as well as ejectors.

Methods adopted to ensure positive pressure on the flare recovery system while preserving a path to the flare for emergency relief included: a water seal drum, a SIL rated quick opening valve, and a pilot-operated relief valve.

The paper presents comparison between the designs of the various systems; compressor technologies and pressure relive methods used in flare gas recovery systems. Applicable codes and standards are discussed. The paper also addresses some of the lessons learnt and the guidelines on best practice for selecting and designing vapor recovery systems.
Case Study - ECD Management Strategy Solves Lost Circulation Issues On Complex Salt Diapirs/Paleocene Reservoir
Authors: Murray David , Sanders Mark W. , Houston Kirsty , Hogg Hamish , Wylie Graeme
Published: June 2014

Drilling horizontal infill wells in the Pierce field in the UK Central North Sea is challenging due to the narrow drilling window caused by depletion in a highly fractured reservoir, which is further complicated by water injection and the proximity of other production wells. Wellbore strengthening was attempted in the reservoir section of Pierce B5, although, when a pre-existing fracture further weakened by depletion was encountered, losses occurred. During the next ten days over 5,000 barrels of non-aqueous fluid (NAF) were lost downhole. During the recovery from the losses event, 15 individual treatments with loss circulation materials (LCM) were made. More than 50MT of LCM was used without success, however, the well was stabilised enough to secure the drilled footage and complete the well.

Two additional horizontal wells in the same field were successfully drilled using a low-equivalent circulating density (ECD)-management strategy combined with the development of a low-ECD drilling fluid system and the use of a high-fluid-loss, high-strength (HFHS) pill. The dual problems of barite sag and poor hole cleaning, that can be problematic when reducing ECD, were successfully managed. This low-ECD technique can be applied in other subsea depleted wells where narrow drilling windows exist.

This paper describes how a detailed analysis of the losses event on Pierce B5 provided an improved understanding of the loss mechanism resulting in a revised ECD management strategy. An engineered low-ECD NAF with a HFHS pill combined with learnings on ECD awareness in the planning and execution phases mitigated the drilling risks on subsequent wells. This has implications when encountering very large fractures that are difficult to overcome, not only on future Central North Sea wells, but also has wider global significance for wells drilled in similar geological settings.
Three-Phase Relative Permeability Modeling in the Simulation of WAG Injection
Authors: Zuo Lin , Chen Yuguang , Zhou Dengen , Kamath Jairam
Published: June 2014

We propose a new workflow to evaluate the impact of three-phase relative permeability models on the simulation of Water-Alternating-Gas (WAG) injection – define a root-mean-square error to quantify differences between the models; introduce a high-uncertainty region on a ternary saturation diagram; and map simulation saturation-time paths in this ternary diagram. The display of the saturation paths, along with the high-uncertainty region, allows us to systematically analyze and understand the impact of three-phase models on recovery predictions. We apply the workflow to immiscible and miscible WAG injection, simulated using black-oil and compositional models. Both 2D homogeneous cases (with various reservoir conditions and injection scheduling), and realistic 3D field sector models are considered. We show that the three-phase relative permeability models can have a strong impact on recovery predictions for immiscible WAG injection, and the impact depends on initial conditions and displacement history. For compositional simulation of multi-contact miscible WAG injection, the impact of three-phase models depends on the size of the three-phase flow region before the miscibility fully develops. Simulation of CO2 flooding on a 3D field sector model reveals that the uncertainty in recovery predictions due to the various three-phase models is secondary compared with other sources of uncertainty (e.g., the input two-phase relative permeability data), and this may be the case in other field studies.
Three-Phase Relative Permeability Modeling in the Simulation of WAG Injection
Authors: Zuo Lin , Chen Yuguang , Zhou Dengen , Kamath Jairam
Published: June 2014

We propose a new workflow to evaluate the effect of three-phase relative permeability models on the simulation of water-alternating-gas (WAG) injection: define a root-mean-square error to quantify differences between the models; introduce a high-uncertainty region on a ternary saturation diagram; and map simulation saturation/time paths in this ternary diagram. The display of the saturation paths, along with the high-uncertainty region, allows us to systematically analyze and understand the effect of three-phase models on recovery predictions. We apply the workflow to immiscible and miscible WAG injection, simulated by use of black-oil and compositional models. Both 2D homogeneous cases (with various reservoir conditions and injection scheduling) and realistic 3D field sector models are considered. We show that the three-phase relative permeability models can have a strong effect on recovery predictions for immiscible WAG injection, and the effect depends on initial conditions and displacement history. For compositional simulation of multicontact miscible WAG injection, the effect of three-phase models depends on the size of the three-phase-flow region before the miscibility fully develops. Simulation of carbon dioxide (CO2) flooding on a 3D field sector model reveals that the uncertainty in recovery predictions because of the various three-phase models is secondary compared with other sources of uncertainty (such as the input two-phase relative permeability data), and this may be the case in other field studies.
Comparative Study for the Interpretation of Mineral Concentrations, Total Porosity, and TOC in Hydrocarbon-Bearing Shale from Conventional Well Logs
Authors: Adiguna Haryanto , Torres-Verdín Carlos
Published: June 2014

The estimation of porosity, water saturation, kerogen concentration, and mineral composition is an integral part of unconventional shale reservoir formation evaluation. Porosity, water saturation, and kerogen content determine the amount of hydrocarbon-in-place while mineral composition affects hydro-fracture generation and propagation. Effective hydraulic fracturing is a basic requirement for economically viable flow of gas in very-low permeability shales. Brittle shales are favorable for initiation and propagation of hydraulic fracture because they require marginal or no plastic deformation. By contrast, ductile shales tend to oppose fracture propagation and can heal hydraulic fractures. Silica and carbonate-rich shales often exhibit brittle behavior while clay-rich shales tend to be ductile. Most petrophysical interpretation techniques commonly used to quantify mineral composition from conventional well logs are based on the assumption that lithology is dominated by one or two minerals. In organic shale formations, these techniques are ineffective because all well logs are affected by large variations of mineralogy and pore structure. Even though it is difficult to separate the contribution from each mineral and fluid component on well logs using conventional interpretation methods, well logs still bear essential petrophysical properties that can be estimated using an inversion method.

This paper introduces an inversion-based workflow to estimate mineral and fluid concentrations of shale gas formations using conventional well logs. The workflow starts with the construction and calibration of a mineral model based on core analysis of crushed samples and X-Ray Diffraction (XRD). We implement a mineral grouping approach that reduces the number of unknowns to be estimated by the inversion without loss of accuracy in the representation of the main minerals. After the mineral model is constructed and a set of initial values are established, nonlinear joint inversion estimates mineral and fluid concentrations from conventional well logs. An iterative refinement of the mineral model can be necessary depending on formation complexity and data quality. The final step of the workflow is to perform rock classification to identify favorable production zones. These zones are selected based on their hydrocarbon potential inferred from inverted petrophysical properties.

This paper documents several case studies from Haynesville and Barnett shales where the proposed workflow was successfully implemented and is in good agreement with core measurements and neutron-capture spectroscopy (NCS) logs. The field examples confirm the accuracy and reliability of nonlinear inversion to estimate porosity, water saturation, kerogen concentration, and mineral composition.