bluuebunny/crossref_metadata_2025 huggingface dataset:
Casing-Running Analysis in Riserless Topholes
Authors: Samuel Robello , Gradishar John
Published: October 2011

Riserless drilling poses numerous operational challenges that adversely affect the efficiency of the drilling process. These problems include increased torque and drag, buckling, increased vibration, poor hole cleaning, tubular failures, poor cement jobs, and associated problems during tripping operations. Riserless drilling in deep and ultra-deep water, as well as drilling to deeper depths, requires improved models and comprehensive analyses, especially when larger-diameter casings are run and cemented in a deviated or directionally drilled tophole environment. Current methods that lack proper modeling will severely overestimate hookload values when casing strings are run in and underestimate in the pick-up load estimates.

A new modeling approach is proposed to calculate appropriate hookload values, as well as torque and drag. This method can model situations in which the drillstring/casing string is in open water or in openhole under various operating conditions. Both soft- and stiff-string models are used in the hookload estimates and in the wellhead side-loading calculations. Hookload calculations and buckling limitations for the scenarios in which casing and inner strings are run with drilling mud inside the inner string, seawater in the outer string, and pad mud in the hole below the mudline, are presented. The study indicates that the results are influenced by various parameters, including depth of the mud line, offset of the wellhead from the rig center, wellbore inclination, curvature, wellbore torsion, and angle of entry into the wellhead, as well as by the complexity arising from wind, wave forces, and ocean currents. This study compares simulated predictions with actual well data from wells from Angola and the North Sea and describes the accuracy and applicability of the model. It also presents several examples of surface casing-string failure.
Application of a Torsional Impact Hammer to Improve Drilling Efficiency
Authors: Deen Aron , Wedel Ryan , Nayan Abhijeet , Mathison Shaun , Hightower Greg
Published: October 2011

Several phenomena that negatively affect drilling efficiency are still commonly observed in practice. These phenomena can often be linked directly to the high torque required for a PDC bit to aggressively shear formation, and the difficulty of effectively transmitting such torque consistently to the bit. In highly transitional or conglomerate formations, the depth of cut and subsequent torque required for the bit to continuously shear formation fluctuates greatly, leading to the buildup and release of torsional energy in the drill string, commonly known as stick/slip. High speeds and vibration during the slip phase, combined with the heterogeneous and/or hard nature of the environment can cause damage to PDC cutters and other drill string components, resulting in reduced bit and tool life as well as poor rate of penetration (ROP).

A proprietary torsional impact hammer was tested in applications in Western Oklahoma and in the Southeast Arabian Peninsula where drilling efficiency was believed to be much lower than the theoretical limit. These applications were identified by high cost per foot drilling with roller cone and diamond impregnated bits, as well as known and expected high vibrations accompanying unsuccessful and inconsistent PDC testing. The case studies reveal the strengths and weaknesses of applying such a solution, and introduce a discussion on selection of applications where this solution is advisable. The balance of this paper will also describe how this solution has reduced drilling costs and changed the economics of drilling applications in Western Oklahoma and the Southeastern Arabian Peninsula over the course of the cases studied.
Characterization of Gas Dynamics in Kerogen Nanopores by NMR
Authors: Kausik Ravinath , Minh Chanh Cao , Zielinski Lukasz , Vissapragada Badarinadh , Akkurt Ridvan , Song Yiqiao , Liu Chengbing , Jones Sid , Blair Erika
Published: October 2011

The Nuclear Magnetic Resonance (NMR) response of gas in gas shale nanopores is different from that of bulk gas, where relaxation is dominated by spin rotation and diffusion is unrestricted. Gas shales are characterized by very low porosity and ultra low permeabilities. Their porosity is dominated by nanometer-scale pores in the organic kerogen that restricts diffusional motion, in addition to having very high surface-to-volume ratios that enhance surface relaxation. At high pressure, the gas exists as an adsorbed phase on the pore surface and as free gas phase in the pore interior. Thus, relaxation and diffusion properties of gas in gas shales are controlled by the combined effects of adsorption, enhanced surface relaxation, restricted diffusion and molecular exchange between the adsorbed and free phases. One of the biggest challenges is the understanding of such effects in order to determine the quantity of free and adsorbed gas from NMR data, and to devise novel techniques to log these unconventional plays. Proper estimation of fluid volumes also requires the knowledge of the hydrogen index for the gas restricted in the gas shale nanopores, which is yet another challenge.

The NMR responses of methane gas in Haynesville shale plugs cored from a well in East Texas, USA were studied in laboratory experiments using a 2 MHz NMR spectrometer at elevated pressures up to 5 kpsi. The effects of adsorption, surface relaxation and restricted diffusion have been characterized, and the hydrogen index of the gas has been measured. Mineralogy, elemental analysis and Brunauer-Emmett-Teller (BET) experiments have also been carried out on the same plugs to understand the formation characteristics. In the samples studied, faster relaxation modes (few tens of milliseconds) and slower apparent diffusion coefficients (an order of magnitude less than their bulk values) for the confined gas molecules in comparison to their bulk properties have been observed for the first time with the help of 2D-NMR experiments at high pressure.

It has been observed that the relaxation spectra for bound water and the gas in the small pores overlap. Additional information is required to resolve these two fluids. Subsequently, the diffusion dimension is investigated to resolve the various fluids in the nanopores. We formulate new relaxation and diffusion models for the interpretation of the dynamics of gas restricted in gas shale and propose that multi-dimensional NMR logging with pulse sequences optimized for gas shales be further tested in the field, to help quantify the total gas in place.
Materials Selection: A Systems Engineering Approach
Authors: Caldwell Eric , Annadorai Karthik , Gibson Grant , Jordan Lee
Published: October 2011

Subsea and topsides materials selection is becoming a vital part in the development and long term sustainability of deepwater oil and gas production facilities. Increasing challenges associated with capital and operating cost constraints, schedule compression, remote locations, and the need to deploy materials ever closer to their known limits makes fit for purpose materials selection a complex and difficult issue that crosses many different discipline boundaries. Materials selection is primarily governed by corrosion engineering principles and applied chemical inhibition practices, and then by project specifics. However, there are two different practices that are generally followed that dictate how materials are ultimately selected. The first is by a standard materials selection process using guidance such as that provided in NORSOK M-001, and the second is by using a more informal system with limited guidance that involves individually selecting materials for a specific project.

In actuality, the materials selection process is a combination of both. The selection process to identify which materials are considered appropriate is routine and straightforward and is dictated by various corrosion parameters and associated risks. Often this high-level assessment does not appropriately address project specifics, so causing the final material selections to be substantially different from those initially proposed.

One of the specific items that often drives this change in materials selection philosophy is the use of chemical inhibitors for corrosion inhibition and the perceived feasibility and level of risk associated with this. Use of a systems engineering approach to material selection can be used beneficially as a process that accelerates the determination and initial optimization of the materials, and the selection of chemicals and their injection locations, and associated monitoring methods and locations in a given topsides, subsea or water injection system design. This process can also be used to address management of change items more readily because alternate materials, chemicals, and injection locations are either already determined or can be rapidly identified by the selection process.

The use of a systems engineering approach to materials selection has been instrumental in reducing and/or eliminating risks to ensure maximum productivity and longevity of deepwater production and injection systems while accommodating the unique factors pertaining to each individual project.
Fracturing Fluid Comprised of Components Sourced Solely from the Food Industry Provides Superior Proppant Transport
Authors: Loveless David , Holtsclaw Jeremy , Saini Rajesh , Harris Phil , Fleming Jeff
Published: October 2011

The industry is seeing significant pressure from regulatory bodies concerning the chemicals that comprise typical fracturing fluids. It has long been the belief of the industry that to obtain the best performance of a fracturing fluid, it is necessary to use certain chemicals in fracturing-fluid formulations. However, this paper clearly illustrates that a fluid comprised solely of components sourced from the food industry can excel in maintaining proppant-transport performance.

This paper focuses on the proppant transport of a fracturing fluid that is comprised solely of components sourced from the food industry and approved for direct addition to foods as governed by the Code of Federal Regulations Title 21 (CRF 21). The proppant-transport capabilities of this fluid are compared to a borate-crosslinked galactomannan, a viscoelastic-surfactant (VES) fluid, and a linear-gelled system. The results illustrate that proppant-transport performance does not need to be sacrificed when using a fluid system comprised of components sourced from the food industry.

The ability to carry proppant into the fracture is one of the most fundamental attributes necessary for a successful fracturing fluid. This paper provides an evaluation of four types of fluids currently used as gelled fracturing fluids, employing five different methods to measure their ability to transport and support proppant. The methods used in the evaluation include traditional steady-shear viscosity, small-amplitude oscillation rheology, flow-through-a-slot model, a slurry viscometer, and static settling results.

The results show clearly that the testing methods and protocols do not necessarily agree on the best performance of a fluid system; a comprehensive examination of the limitations and benefits of each are examined. Some of the gels tested showed good proppant support under static conditions, while others showed good transport under flow conditions. The crosslinked gel that was sourced solely from the food industry showed a dramatic difference in that it was able to support proppant under static- and dynamic-shear conditions, leading to superior proppant-transport performance using the five test methods.
Applied Borehole Image Analysis in Complex Sedimentological and Structural Settings: A Single Well Case Study, California, USA
Authors: Amer Aimen , Glascock Michael , Schwalbach Jon , Khan Masood
Published: October 2011

Borehole images are typically used to obtain the structural dip of the formations penetrated by a well, identify thinly bedded reservoirs, and analyze fractures and faults (especially those of subseismic scale). In this paper borehole images are used as depositional environment interpretation tools to identify different elements of a deepwater system and to correlate features observed on borehole images to those exposed at outcrops that are analogs for these deposits. In addition, borehole images are used to verify structural interpretation near the well, which is particularly valuable in areas with poor quality seismic data.

The borehole images captured from a single well in the Ventura basin, California, contain excellent examples of sedimentary features such as groove casts, lenticular bedding, scours, graded beds, and. rip-up clasts. These features enable us to interpret depositional facies such as debris flows, channels, and amalgamated and layered turbidites to better understand the position of the well within the depositional system. We are also able to identify and verify overturned beds and repeat stratigraphic sections in the well because the image logs enable us to document the presence of reverse faults. The outcrop analogs we discuss are from the Pliocene Pico formation from the Ventura basin in California. Features observed on the outcrops are similar to features observed on borehole images and in cores, allowing us to extend our facies interpretation to larger areas of the field.

Detailed structural analysis of the image log from this well using manually-interpreted formation dips shows three large-scale thrust zones (at least 3000 ft each) associated with highly tilted and in one case overturned beds. This analysis enhanced our structural understanding of this compressional regime. This is an important tool in areas such as the Ventura basin, where seismic data is not easily acquired because of the rugged terrain and steeply dipping structural limbs. Combining the sedimentological and structural information from the borehole image interpretation provides a better understanding of the reservoir geometry and likely connectivity between reservoir units. This information is critical for choosing the next well location and planning future development strategy. This paper demonstrates the value of utilizing borehole images to understand local depositional systems and complex structures within an active field development program.
Effect of Relative Permeability Characteristics and Gas/Water Flow on Gas-Hydrate Saturation Distribution
Authors: Behseresht Javad , Bryant Steven
Published: October 2011

The descent of the base of gas hydrate stability zone (BGHSZ) through gas accumulated in a sediment is analyzed. A mechanistic model enables estimating hydrate saturation from initial distribution of gas phase saturation in sediment with known grain size distribution. The initial gas phase saturation is estimated from the profile of capillary entry-pressure with depth. The latter is estimated from grain size variations. A mechanistic model is proposed to determine the relative rates of methane and water transport into the HSZ during hydrate formation. The gas accumulation is assumed to be isolated so that methane transport occurs only within it. If water transport occurs only by co-current flow of gaseous and aqueous phases up to the hydrate stability zone (HSZ), it is not possible to create large hydrate saturations from large initial gas saturations due to limitations on water flux imposed by typical relative permeability curves. Thus the observed large hydrate saturations, such as that observed in Mt. Elbert, Alaska and Mallik, NW Territories and deep Indian Ocean, above the BGHSZ suggest another form of water flow: water moves down through accumulated hydrate from above. This requires the aqueous phase to remain connected within the hydrate-bearing sediment. The ratio of aqueous phase permeability in the hydrate-bearing sediment to the aqueous phase relative permeability at residual gas saturation determines hydrate saturation profile. The model is validated against field data from a hydrate-bearing sand unit in Mt. Elbert.
Analysis of Plunger Lift Applications in the Marcellus Shale
Authors: Kravits Matthew , Frear Ray , Bordwell Dave
Published: October 2011

Field testing was performed on plunger lift systems in horizontal Marcellus shale wells. Plunger lift software from Echometer Company, Total Well Management, or TWM was used on certain wells to monitor acoustic trace, casing pressure, and tubing pressure throughout the plunger cycle.

The plunger lift testing program addresses the challenges presented in shifting from vertical to horizontal well plunger lifting. The plunger lift testing addresses the feasibility of running plunger lift on wells with X and XN-profiles. These nipples are used to provide safe snubbing operations. The most valuable insight from the testing involves the possibility of running plunger lift to deviation angles of 70° and greater.

The results of the plunger lift testing yielded several conclusions. An important result was that all plungers successfully passed through the X-profile, contrary to industry doubt. Another conclusion was that all plungers fell down to their bottom deviation angle with the deepest falling of 70°. Testing also showed the importance of performing TWM investigations on every plunger lift well to optimize plunger cycles. The most notable result was the phenomenon that plungers fell faster below kickoff point. This phenomenon suggests the possibility of plungers travelling to 90°. The observed trends of 53 TWM traces suggest that current plungers in horizontal Marcellus shale wells can theoretically reach a final deviation angle of 74°.

Plunger lift systems have been used across the United States for decades to unload small amounts of liquid (water, oil, and/or condensate) as gas rates fall below the minimum critical rate to continuously unload fluids. The Marcellus shale is a vital asset to natural gas production in the United States. Development has transitioned from a vertical well science program to a proven horizontal well development program. Plunger lift has become common among some operators in the Marcellus shale for wells which have fallen below their critical gas rate. Our plunger lift program shows promise to maintain production after wells reach unstable flow up the tubing. Marcellus shale production can potentially benefit significantly if plungers eventually reach deviation angles of 90° since it will allow for production of fluid left in the horizontal lateral.
Understanding and Predicting Fayetteville Shale Gas Production Through Integrated Seismic-to-Simulation Reservoir Characterization Workflow
Authors: Ramakrishnan Hariharan , Peza Eva , Sinha Shekhar , Woods Miriam , Ikeocha Christopher , Mengel Flemming , Simon Yves , Pearce Paul , Kiester Jeff , McKetta Steven , Jeffers John
Published: October 2011

This paper describes a comprehensive workflow that incorporates geologic, seismic, and production data in an effort to understand and predict the performance of gas wells in the Fayetteville Shale play. A reservoir model was developed by integration of all available well, log, petrophysical, sonic, image, core, stimulation, production, microseismic and processed surface seismic data. This static reservoir model was used to history match the short- and long-term production performance and its variations across the exploration area. History matching production profile from multiple wells is a critical step toward understanding the key production drivers in unconventional shale gas formations. This workflow involves extensive use of surface seismic to develop a velocity model and to distribute reservoir properties. This paper highlights the multidisciplinary knowledge that was applied in the project and the lessons learned.

The reservoir characterization and dual-porosity simulation model developed was used to predict production performance of future wells in the Fayetteville Shale formation. Key production drivers—such as matrix quality, natural fractures, net gas porosity—and ways to identify and exploit these parameters during the development phase of the reservoir are discussed. The ability of the models to predict production performance is also discussed. This workflow is useful in selecting drilling locations, identifying best landing points, optimizing well spacing, and guiding completion practices.
Is There Evidence of Super Cycles in Oil Prices?
Authors: Zellou Abdel M. , Cuddington John T.
Published: October 2011

A number of authors have claimed that the strong upward movement in commodity prices since 2000 represents the early phase of a ‘super cycle’ (SC) driven by industrialization and urbanization in the BRIC countries (Brazil, Russia, India and China), especially China. Moreover, Heap (2005), Cuddington and Jerrett (2008), Jerrett and Cuddington (2008) and others have found evidence of SC (20-70 years in length from peak to peak or trough to trough) in metals prices associated with earlier industrialization episodes in Europe, the U.S., and Japan. These cycles are much longer in duration than the typical business cycle, defined as 2-8 years. The purpose of this paper is to address the question: is there evidence of super cycles in crude oil prices?

Our approach to the empirical question posed in the title applies the asymmetric Christiano-Fitzgerald band-pass filter to real crude oil prices from 1861 to 2010 in order to extract a cyclical component with a period between 20 and 70 years.

Our results suggest the existence of SC in energy commodities with a strong correlation between the SC of coal and oil prices after World War II. The SC analysis is carried out using both nominal and real prices in order to determine whether these SCs are an artifact of the price deflator used. There appear to be three obvious SCs in oil prices, the first one between 1861 and 1884, and the last two from 1966 to date. The period 1884-1966 is harder to interpret and has been aggregated into one SC. These results are consistent with the recent work performed by Dvir and Rogoff (2009) on the changes in real oil price persistence and volatility.

There has been renewed interest in commodity prices over the past decade. Evidence on the presence of SCs in energy commodities is valuable for national and state governments, financial institutions and oil and gas companies. At the government level, countries that rely on the import or export of energy commodities need to take SCs into account when formulating resource extraction as well as revenue and expenditure policies. At the firm level, the exploration-development-production-distribution-research-and-development cycle of energy projects often spans several decades, as do SCs. Hence the investment decisions made by oil and gas companies should take into account the presence of these SCs.
The Design and Execution of Frac Jobs in the Ultra Deepwater Lower Tertiary Wilcox Formation
Authors: Haddad Ziad , Smith Mike , De Moraes Flavio Dias , Moreira Oswaldo
Published: October 2011

A considerable amount of effort goes into designing one of the deepest frac jobs in the world. For the past several years, Petrobras has been working on developing the Cascade and Chinook fields which are located in the Gulf of Mexico (GOM), 250 miles south of New Orleans in ultra deepwater depths between 8200 ft and 8900 ft. The oil producing reservoir is in the Lower Tertiary Wilcox formation with a gross sand thickness of 1200 ft. The reservoir mid-point is at an average depth of 25, 600’ TVD with a bottomhole pressure of 19, 500 psi and a bottomhole temperature of 260°F. The reservoir is comprised of vertically stacked thin beds of sand and fine grained siltstone intervals with effectively no vertical permeability. Additional information on this project can be found in a paper written by Moraes el al (2010).

Multiple limitations were considered during the initial design phase of the frac pack program. The fracs were designed taking into account the use of a Single-Trip Multi-Zone sand control system. Although this system was not crucial in the overall implementation of the frac program, it added additional complexity from an operation stand point due to a continuous, multi-stage frac operation. Some of the operation limitations included service tool erosion limitations due to maximum pump rates and proppant volumes, overall frac vessel capacity, boat-to-boat fluid transfers and crew fatigue. The geological complexities of the reservoir were another major challenge in completing this very thick interval. Perforation intervals had to be placed to avoid a fault (and thus a potential early screenout), avoid a water contact, comply with tool spacing limitations and still maximize contact with net pay.

This paper addresses the approach taken to develop a fracture stimulation program for the Lower Tertiary formation in the Cascade and Chinook fields. Some of the major questions addressed during this process include the following: how many fracture treatments are needed, what is the optimum fracture geometry, what is the desired conductivity, how to effectively position the perforation intervals, what is the desired pump rate and is a high-density fluid needed to fracture this deep, high-pressure formation? The approach, the answers and the treatment are discussed along with responses to additional questions that arose during the actual fracturing operations.

Along with the Lower Tertiary in the GOM, the industry faces similar challenges around the world. These include reservoirs with potentially large reserves but much lower permeability (due to depth and in-situ stresses) where fracturing is required for both stimulation and potential formation collapse sand control. Careful planning is necessary to avoid costly learning curves in these environments.
A Practical Method to Calculate Polymer Viscosity Accurately in Numerical Reservoir Simulators
Authors: Sharma Abhinav , Delshad Mojdeh , Huh Chun , Pope Gary A.
Published: October 2011

Polymers play a key role in several EOR processes such as polymer flooding, surfactant-polymer flooding and alkaline-surfactant-polymer flooding due to the importance of mobility control in achieving high oil recovery. Numerical simulations are used to predict the performance of these processes and in particular the injection rate of the polymer solutions since the economics are sensitive to the injection rates. It is important to model the polymer viscosity accurately so that accurate predictions of injection rate can be made. Because the viscosity of the non-Newtonian polymer solution is a strong function of shear rate, the calculation of shear rate must be accurate. The shear rate depends on the local velocity in the reservoir. As the gridblock size increases, the calculation of this velocity is less accurate, especially close to the wells. We present a method to calculate the effective shear rate for the gridblock sizes that are practical for large field simulations. We also present improvements in the polymer viscosity model. At high temperature, the rate of hydrolysis of polyacrylamide polymers is significant over reservoir time scales. A simple scheme was developed to account for the hydrolysis and the corresponding change in viscosity as the polymer flows through the reservoir. This study demonstrates that accurately computing polymer viscosity is important for the proper representation of not only the well pressure, but also for the pressure distribution substantially away from the wellbore, thereby significantly influencing the performance of chemical EOR processes that use polymer.
Design of Simultaneous Enhanced Oil Recovery and Carbon Dioxide Storage Applied to a Heavy Oil Field Offshore Trinidad
Authors: Sobers Lorraine E. , Blunt Martin J. , LaForce Tara C.
Published: October 2011

We have developed an injection strategy to recover moderately heavy oil and store carbon dioxide (CO2) simultaneously. Our compositional simulations are based on PVT-matched properties of oil found in an unconsolidated deltaic, sandstone deposit in the Gulf of Paria, offshore Trinidad. In this region oil density ranges between 940 and 1 010 kg/m3 (9-18 degrees API). We use counter-current injection of gas and water to improve reservoir sweep and trap CO2 simultaneously; water is injected in the upper portion of the reservoir and gas is injected in the lower portion. The two water injection rates investigated, 100 and 200m3/d, correspond to water gravity numbers 6.3 to 3.1 for our reservoir properties. We have applied this injection strategy using vertical producers with two injection configurations: single vertical injector and a pair of horizontal parallel laterals. Eight simulation runs were conducted varying injection gas composition for miscible and immiscible gas drives, water injection rate and injection well orientation. Our results show that water over gas injection can realize oil recoveries ranging from 17 to 30%. In each instance more than 50% of injected CO2 remained in the reservoir with less than 15% of that retained CO2 in the mobile phase.
Simple Engineering Applications Recycled as Effective Training Aids
Authors: Sawaryn S. J.
Published: October 2011

Technical advances have led to both the expansion and increased specialisation in the engineering skills employed in our industry. In many cases these specialisations involve the use of complex engineering calculations involving a bewildering number of inputs and outputs to match real-world situations. A further problem with high-end applications is that they are costly and their logic is often presented as a "black box" and disclosure may be hampered by intellectual property concerns. Whilst such high fidelity applications may be essential for operations, simpler models with few inputs are better for scoping exercises or training.

The rapid and effective transfer of knowledge and experience to new hires with diverse backgrounds remains a key challenge. Though information technology and richer media have helped standardise delivery methods, accessing appropriate engineering applications for training purposes remains a challenge.

The important requirements are to communicate the fundamentals and build on knowledge gained at University. At the same time, the teaching methods and modules should instill curiosity and encourage critical assessment of the models and methods used. The models should not therefore be too far from reality.

Technical progress and refinement of a broad range of topics is inherent in the content and structure of the SPE paper library. The application to training is illustrated using examples including the simple 2D-BHA algorithm presented by Walker (1973). This paper shows how key refinements have been included using simple geometrical constructs and how the model has been effectively used in spreadsheet form to develop an understanding of BHA behaviour, directional survey sag correction and to identify and correct programmatic errors.

It is suggested that greater use can be made of the SPE library as a ready source of cost effective training material and that the descriptions of the simpler engineering applications it contains can be recycled as valuable training aids.
A Flow Assurance Study on Elemental Sulfur Deposition in Sour Gas Wells
Authors: Tang Yula , Voelker Joe , Keskin Cengizhan , Xu Zhenggang , Hu Bin , Jia Changqing
Published: October 2011

This paper summarizes a flow assurance study for elemental sulfur deposition in the tubing for the Chuandongbei Gas Project (CDB), a greenfield sour dry gas development project in Sichuan, China. The project is a co-venture of Chevron and China National Petroleum Company (CNPC). The development contains several fields, all containing dry gas with 8-17% H2S, and 8-10% CO2

Elemental Sulfur (S8) dissolved in the gas may precipitate in both the near-well reservoir region, and tubing, within the pressure and temperature range predicted for gas well flow in the fields. The precipitate may form gas flow restrictions. An offset operator producing gas from the same reservoir interval and having similar composition has reported flow problems attributed to S8. This study focused on the prediction of S8 deposition in the tubing, during both production and shut-in periods.

Numerical transient well pressure and temperature modeling with the OLGA wax deposition module was used to predict precipitation and deposition of S8 in the tubing. Presently, no other S8 deposition model is available. The model estimates the pressure and temperature gradient between the bulk fluid and tubing wall, and molecular diffusion rates through the laminar sub-layer of the fluid velocity profile. An S8 phase equilibruium model calibrated by measured phase behavior from a laboratory synthetic gas having the composition of CDB field measured surface gases was used to generate the S8 phase diagram.

The study indicates that shut-in periods present the greatest S8 deposition risk: suspended sulfur precipitate accumulates at bottomhole during shut-in periods, possibly forming a flow restriction. Mitigation through solvent treatment applied after shut-in periods is therefore planned. S8 deposition on tubing walls during flow periods was found to present relatively low flow assurance risk.

This study also provides operational design recommendations for well start up, sustained flow, and shut-in periods, as well as flow assurance mitigation design.
A Novel Approach Based on Dielectric Dispersion Measurements to Evaluate the Quality of Complex Shaly-sand Reservoirs
Authors: Pirrone Marco , Han Mei , Bona Nicola , Borghi Massimiliano , Galli Maria Teresa , Pampuri Ferdinanda , Faivre Ollivier , Hizem Mehdi , Kherroubi Josselin , Mossé Laurent
Published: October 2011

This paper presents a novel approach for the formation evaluation of shaly-sand thin layered reservoirs using dielectric dispersion wireline logging provided by a new generation tool. The study is focused on gas fields in the Mediterranean basin characterized by the presence of very thin inter-laminations (centimeter-scale or even less). In these complex reservoirs, the conventional petrophysical analysis is very challenging due to standard logging tools’ vertical resolution limits which prevent the quantitative estimation of the clay content, of a detailed water saturation profile and of the reservoir quality.

The new-generation, cm-scale vertical resolution tool overcomes these limitations thanks to the continuous measurement of dielectric dispersion from the MHz to the GHz frequency range and to a fit-for-purpose inversion based interpretation model. The outcome is a high resolution estimate of the main petrophysical parameters including water volume fraction for determining hydrocarbon saturation, formation water salinity and an additional textural parameter of the rock matrix that is correlated to clay volume.

The model has been developed and calibrated using a statistically representative database of core measurements (including porosity, mineralogy, granulometry, Cation Exchange Capacity as well as dielectric spectra measurements) from several wells drilled in shaly-sand reservoirs representing different geological environments. In all the analyzed wells a full wireline log data set was also available.

The application of the new approach to the examined case histories provided satisfactory, high resolution results in terms of:

lithological description of the formation with the added value of a quantitative estimation of the clay content; reservoir quality evaluation; gas saturation indicator thus reducing the uncertainty in the petrophysical characterization of complex shaly-sand reservoirs.
Successful Discovery of Light Oil from an Unsuccessful Paleozoic Well through Re-entry - A Case Study of HPHT Well
Authors: Al-Bader Haifa , Al-Salali Yousef Zaid , Duggirala Vidya Sagar , Manimaran A. , Packirisamy S.
Published: October 2011

This paper describes the challenges addressed during testing, completion and subsequent re-entry for Jurassic prospects in an ultra-deep HPHT exploratory well in highly sour environments. The approach and methodology adopted to address the problems related to perforation, Coiled Tubing, stimulation and well testing operations are also discussed in this paper.

The exploration activities for gas in North Kuwait are in progress at high pace. An exploratory well, second deepest in the State of Kuwait, drilled in Mutriba field to a depth of 22, 094 feet to cover Triassic and Paleozoic sections. All these deeper formations have very low porosity and permeability. Two formations, Kra-Almaru and Khuff were perforated and tested, which showed the presence of feeble gas. Based on the study, later it was decided to test and complete this well in Jurassic formation through re-entry.

The re-entry in this ultra-deep well was full of challenges due to HPHT conditions, high surface pressure and well killing issues. The re-entry was planned under the supervision of highly skilled task team. A snubbing unit was utilized to isolate the open perforations of the Triassic zone with cement. Subsequently a workover rig was deployed to test the prospect of Jurassic reservoir. Several severe mechanical problems like fishing, isolation and retrieving the tubing were encountered prior to well testing, which were efficiently addressed. Testing the Jurassic reservoir behind two heavy walled casings(7" 46.4 ppf and 8-5/8" 40 ppf), combined with extreme sour and HPHT environment warranted high HSE and technical precautions. Special software was run to simulate the depth of penetration in two walled casings. The targeted Jurassic interval was perforated with suitable TCP guns at a depth of around 16, 260 feet.

During testing, the formation fluid showed presence of unexpectedly high concentration of 20% H2S and 2% CO2.In this extreme sour environment, Coiled tubing operations, stimulation, flowing the well, and fluid disposal were of utmost challenge. By overcoming all the challenges, this well was successfully perforated, stimulated and tested, which led to the first commercial discovery of Oil & Gas within the Jurassic Reservoir in Mutriba field.
Revisiting Microfrac In-situ Stress Measurement via Flow Back - A New Protocol
Authors: Savitski Alexei A. , Dudley John W.
Published: October 2011

The minimum in-situ stress is an important parameter for many applications including cap rock integrity, hydraulic fracturing design and well bore stability. Microfrac testing is the most reliable and direct technique for measuring it and involves creating a hydraulic fracture. The pressure at which the created fracture closes is commonly associated with the minimum in-situ stress. The pump-in/flow back test is one of several procedures that can be done during microfrac testing, and it produces a very characteristic pressure signature at closure.

In this paper we demonstrate the pitfalls of the traditional interpretation of the flow back data based on data acquired during shallow microfrac tests in a shale formation. The importance of identifying the transient flow regime and the significance of the pressure rebound are discussed. To circumvent the drawbacks of the conventional flow back test a new protocol using an incremental flow back/shut-in procedure is proposed. The excellent results demonstrate the merits of the new procedure.
Shale Gas Water Treatment Value Chain - A Review of Technologies, including Case Studies
Authors: Horner Patrick , Halldorson Brent , Slutz James
Published: October 2011

North American shale gas plays discovered over the past ten years contain an abundant tcf of natural gas, providing a long term, low carbon domestic energy source. Drilling and completing techniques developed in the Texas Barnett Shale over the past ten years have unleashed an unprecedented new shale gas industry across North America. The most effective completion technique is known as hydraulic fracturing (or "fraccing"), a process that involves injecting a large volume (60, 000 to 140, 000+ bbls) of fresh water underground to fracture the formation, increasing permeability and thus gas flow. After a frac is completed, a large portion of the frac fluid returns to the surface as "flowback" water which contains high concentrations of dissolved salts, frac chemicals, and formation minerals.

The costs and logistics of managing both fresh and flowback water in shale gas plays are problematic. Development of North America's shale gas resources will require well developed water management strategies that include the effective implementation of water recycling technologies. Treating flowback for re-use as frac fluid reduces the impact of key issues associated with shale gas water management including cost, truck traffic, water availability, and disposal availability.

Factors including salinity, residual frac chemicals (polymers), H2S, NORM, carbonate scales, iron scales, and sulphate scales make the treatment and handling of flowback complex. The overall water management strategy is a function of water sourcing and disposal cost and availability, formation geology and how that impacts both flowback water chemistry and frac fluid compatibility, the regulatory environment, and the availability of commercialized and cost-effective technology.

This paper explores the challenges associated with treating shale gas flowback for re-use and evaluates the role and cost of available commercial technology. Cases studies of technology applications that have been used during the past seven years in major shale basins will be included.
An Examination of Clay Stabilization and Flow Stability in Various North American Gas Shales
Authors: Conway Michael , Venditto James , Reilly Phil , Smith Kevin
Published: October 2011

There is a general uncertainty regarding the issues affecting shale stability in gas shale reservoirs. True swellable smectite is not present in most of the reservoirs currently being exploited. Illite and illite/smectite are the principal clay components, and they do have a distinct fixed water of hydration which is salinity and cation dependent. Historically, two factors had a major impact on the choices made for clay stability in clay rich reservoirs. Today, many hydraulic fracturing treatments are conducted with virtually fresh water, so this comprehensive study was undertaken to identify the role of salinity on the stability of various gas productive shales. Evaluated were various inorganic salts, temporary clay stabilizers and permanent clay/shale stabilizers, and the results of the comparisons will be presented.

The petrophysical properties of the samples studied have been extensively characterized and the swelling and erosional characteristics have been examined with capillary suction time (CST), roller oven (RO) and unpropped fracture flow capacity tests. Some shale samples are inherently unstable, regardless of the fluid used in the measurement, while the majority responds positively to more compatible fluids. A few samples are extremely stable in all fluids. The native state of the clay in the shales has been characterized by a variety of tests, including specialized cation exchange and wettability studies, to help understand the fluid/rock interactions.

The results of this study have identified the relationship between clay stabilizer type and concentration on the stability of the shale and the impact on flow capacity in the "stimulated reservoir volume". This is a compelling story of rock/fluid interaction studies on actual cores, fit for purpose product development, and supporting field production results.
Field Demonstration of a New Method for Making Drillpipe Connections During Managed Pressure Drilling Operations
Authors: Johnson Rachel , Montilva Julio , Sati Mohamed , Grable Jeff , Saeed Saad , Billa Richard , Derise William
Published: October 2011

The use of managed pressure drilling (MPD) during drilling operations has proven to be an effective solution for controlling equivalent circulation density (ECD); however, making a drillpipe connection with MPD is more challenging than with conventional drilling. The current methods for making a connection during MPD rely on large, high-maintenance equipment to provide a sufficient fluid supply to maintain the MPD equipment within an operable range. This equipment is both expensive and difficult to use to control ECD efficiently.

A new method of smoothly diverting rig pump flow during connections from the stand pipe to the MPD pressure control equipment at the annulus uses a valve manifold with an on-board choke. In addition to eliminating more expensive solutions, this method will improve pressure control and increase the operating range of MPD to provide higher pressures during connections and greater drilling flow rates. Reliability is increased by a reduction in complexity when using this method, because most rigs have multiple pumps available for redundancy.

Field trials using a fully automated MPD solution were performed by a major operator in South Texas between late 2010 and early 2011. This paper uses real data based on flow testing and actual field experience to demonstrate that implementing the rig pump diverter method with standard MPD operations effectively controlled the desired annulus pressure during connections. By replacing current methods of making a drillpipe connection, this solution will reduce the overall cost of MPD, making the total MPD solution more feasible for small wells.
GFREE Research Program
Authors: Aguilera Roberto , Harding Thomas G.
Published: October 2011

GFREE stands for a multi-disciplinary target-oriented research program into unconventional gas technology that includes geoscience (G), formation evaluation (F), reservoir drilling, completion and stimulation (R), reservoir engineering (RE), and economics and externalities (EE). The program has concentrated on unconventional gas formations in Canada but the results are widely applicable to worldwide resources. The principles developed can be beneficially applied to other research programs related to the oil and gas industry. The multidisciplinary approach has meant that graduate students are not supervised, in general, by only one professor. Rather, the students have been mostly co-supervised by 2 professors with different backgrounds and/or by professionals working in industry. The program has been supported by industry, government and the university and cooperation amongst GFREE and these organizations has proven to be of utmost importance.

A decision made at the beginning, which has proved valuable for this program, was that the team would concentrate on issues with potential to generate positive cash flows. GFREE students generally share in the same study areas promoting discussion and collaboration. Bi-weekly meetings of the team members allow for exchange of ideas and dry runs that help students prepare for their thesis defenses and/or presentation of papers in local and international conferences. Undergraduate and graduate courses that concentrate on unconventional gas exploitation and naturally fractured reservoirs have proven valuable to train students that join this program and to disseminate results of the research.

Flexibility has proven also to be of importance. As GFREE was developed as a 5-year program it was impossible to anticipate all the hurdles and bridges that would have to be crossed. For example, the anticipation of core availability for the study areas did not always materialize. Consequently it was necessary to switch to the study of drill cuttings for qualitative and quantitative evaluation with limited support of core data.

The multi-disciplinary nature of the GFREE program has led to valuable insights. It is concluded that the integration of many disciplines and the involvement of government, industry and academia has provided significant positive results that could be extended to other disciplines.