bluuebunny/crossref_metadata_2025 huggingface dataset:
Critical Evaluation of High Brine Tolerant Additives Used in Shale Slick Water Fracs
Authors: Paktinat Javad , O’Neil Bill , Aften Carl , Hurd Michael
Published: September 2011

The primary purpose of stimulating shale reservoirs is to allow as much contact with the reservoir rock as possible, extend drainage radius, and maximize Stimulated Reservoir Volume. Slick water fracturing has increased significantly with the advent of horizontal shale stimulation. Technological advances, including multi-stage fracturing of horizontal wells, have brought about an increase in frac volume of up to several million gallons of slick water per well. Recent restrictions by local and state regulatory entities have put limits on fresh water usage.

Concerns over the disposal and environmental impact of flowback water have created challenges for industry. To remedy some of these concerns and reduce operational cost, some operators are adopting different methods of managing large volumes of produced water by chemical and mechanical methods, in order to remove solids and iron from flowback water so it can be reused in fracturing. However, most treatments currently used do not remove dissolved salts from treated waters, therefore recycled water not only exhibits overall high salinity, but also increased multivalent ionic content.

When these conditions exist, the current commercial additives perform under par, thus necessitating the development of high brine tolerant chemicals. Searches for and development of these types of chemicals began early in 2009, and were done in part to meet operational demands, while reducing chemical costs and environmental impact. These goals can be achieved by using less friction reducer per job. This paper describes friction reducer performance and other chemical selections that tolerate high salinity flowback waters.

This study critically examines the performance of a newly-developed slick water system in high salt concentration brines containing mono and multivalent ions. Average water analyses of different shale reservoirs were used to determine the performance characteristics of the additives used in slick water fracturing. A friction flow loop was used as the main measurement tool in evaluating the rheological properties of the polymers, as well as the effect of other additives used in slick water fracturing.

This new slick water system incorporates a high molecular weight polyacrylamide in a water internal emulsion as a friction reducer, which shows significant improvement over commercially available friction reducers of similar charge and molecular weight currently used in the industry. A ten gallon capacity friction loop was utilized to pump the fluid through one-quarter inch pipe at a Newtonian Reynolds number of 52,000. Results of this study, along with compatibility data, were used to select a polymer system that exhibits high resistance to brine. Experimental and field data illustrated in this study show significant performance improvement of slick water treatments where high brine water is used in shale fracturing.
Multi-Component Sorbed-Phase Considerations for Shale Gas-in-place Calculations
Authors: Ambrose Ray J. , Hartman Robert C. , Akkutlu I. Yucel
Published: September 2011

Recent studies have shown that shale gas industry is incorrectly determining gas-in-place volumes in reservoirs with a large sorbed-gas by not properly accounting for the volumes occupied by the sorbed and free gas phases. Scanning electron microscopy (SEM) has discovered nanopores in organic-rich shale with sizes typically in 3-100 nm range, although pores less than 3 nm cannot be captured with current SEM technology. At that scale the adsorption layer thickness is not infinitesimally small. Thus a portion of the total pore volume would be occupied by a finite-size adsorption layer and not available for the free gas molecules. In SPE 131772, we proposed a volumetric method which accounts for the volumes taken up by the free gas and by the adsorption layer. The study was based on a single-component Langmuir adsorption model, however. This paper extends the discussions on the adsorption layer effect for multi-component natural gases with a sorption model also known as extended-Langmuir.

We combine the extended-Langmuir adsorption isotherm with volumetrics and free gas composition to formulate a new gasin-place equation accounting for the pore space taken up by a multi-component sorbed phase. The method yields total gas-inplace predictions, which suggest that an adjustment is necessary in volume calculations, especially for gas shales with high C2+ composition and high in total organic content. Using typical values for the parameters, calculations show a 20% decrease in total gas storage capacity compared to that using the conventional approach. The adjustments need to be done on the free gas volume is 18% more than the value using single-component (methane) case. The role of multi-component adsorption is more important than previously thought. The new methodology is therefore recommended for shale gas-inplace calculations.
Correlating Wettability Alteration with Changes in Eelative Permeability of Gas Condensate Reservoirs
Authors: Gilani S. F. , Sharma M. M. , Torres D. , Ahmadi M. , Pope G. A. , Linnemeyer H.
Published: September 2011

In gas condensate reservoirs, considerable productivity loss occurs after the pressure near the production wells drops below the dew point of the hydrocarbon fluids. Over the years, several methods have been proposed to restore gas production rates after a decline in well productivity owing to condensate and/or water blocking. These methods such as gas recycling, hydraulic fracturing and solvent injection have shown to restore the production on a temporary basis only. Altering the wettability of reservoir rock using fluoro-chemical treatments has proved to be a viable and permanent solution to this problem. The selection of these treatments from a large pool of potentially effective chemicals requires extensive laboratory testing which requires time and money.

In this paper, we present data that correlates changes in wettability with improvements in relative permeability. Imbibition, contact angle and X-ray photoelectron spectroscopy (XPS) tests along with coreflood results are used to characterize wettability changes. XPS tests, drop tests and core flood experiments were conducted and correlated with each other. It is shown that XPS analysis and imbibition tests provide a quantitative measure of chemical adsorption and surface modification, but only a qualitative measure of the possible change in relative permeability. As such these simple analytical tools may be used as a screening tool. A positive but imperfect empirical correlation was obtained with results from core flood experiments. The varying concentration of fluorine observed on the rock surface was found to be directly correlated to the wettability change in the rock, which in turn is responsible for improving the deliverability of wells in gas condensate/volatile oil reservoirs.

The method discussed in this paper can be successfully used to identify chemical treatments that can change rock wettability and, therefore, relative permeability. This provides a simple and inexpensive way to screen chemicals as wettability altering agents and relative permeability modifiers. In this way the number of HTHP core floods needed is minimized which saves time, cost and effort.
Corrosion-Inhibitor Design for Compatibility with Acid-Gelling Polymers
Authors: Cassidy Juanita , Kiser Chad , Smith Chris
Published: September 2011

Polymers used for delayed acid gelling are designed to crosslink with metal crosslinkers once the acid is spent to a certain pH so that the resultant solution-viscosity increase will cause acid diversion. However, some organic molecules have the ability to react with the functional groups of the polymers and cause crosslinking before a pH rise. Consequently, the higher viscosities resulting from early crosslinking can affect the pumpability of the acid blend and can also lessen the ability of the polymer to clean up from the formation following diversion.

Aldehydes, used as active components in many acid corrosion inhibitors, have the potential side effect of prematurely crosslinking polyacrylamide-based acid-gelling agents because of the reaction of the aldehyde with the polymer amide groups. Furthermore, other unsuspected inhibitor active ingredients might also convert to aldehydes in an acidic environment and cause crosslinking problems.

The chemistry of the reaction of different aldehydes with polyacrylamide-based gelling agents is presented through use of analytical techniques, along with viscometer studies that simulate downhole conditions. These investigations consider how the molecular structure of the aldehyde affects crosslinking with temperature and acid strength.

Based on information learned from the study of aldehyde interactions with the polymer-gelling agent, an acid corrosion inhibitor can be designed that does not cause any interference when used in conjunction with acid-gelling polymers. Development of such a corrosion inhibitor is presented.
Surface Energy of North American Shales and its Role in Interaction of Shale with Surfactants and Microemulsions
Authors: Zelenev Andrei S.
Published: September 2011

In recent years a number of laboratory studies on the use of surfactants and microemulsions in hydraulic fracturing of shale formations have been reported. These studies mainly focused on such metrics as improvement in permeability regain and enhancement of fluid recovery from packed columns upon the use of surfactant-containing chemicals. Laboratory studies have also been backed by the documented observations from the field illustrating benefits of using microemulsions for the increase in gas production from shale formations. It is a commonly accepted view that these additives benefit gas production by lowering capillary pressure and altering wetability of shale formation. Although it is recognized that the interaction of surfactants and microemulsions with shale is governed by the energetics of solid/liquid, liquid/gas and solid/gas interfaces, there are practically no studies in which surface energies have been determined for different shales. The surface energy, as well as dispersive, non-dispersive, Lifshitz-van der Waals, and Lewis Acid-Lewis Base components of surface energy of several North American shales have been determined from contact angle measurements. It has been discovered that the surface energy of all shale rocks is rather low, typically in the range of 40-50 mJ/m2 a contribution from non-dispersion ("polar") component of about 8-11 dyn/cm. Consequently, shales are capable of interacting with liquids predominantly via dispersion and Lifshitz-van der Waals molecular interactions, which should substantially influence the orientation of surfactant molecules and microemulsion moieties at the shale surface. Furthermore, there was no significant variation in surface energy of shales from different basins, which suggests that individuality of shale surface chemistry should play only a secondary role in the development of shale-specific chemical treatments, and factors other than surface chemistry should be considered first.
Optimized Stand-Alone Screen Design for the 'J' Field, Malaysia
Authors: Regulacion Rhandy , Seno Andreas , Safiin Norhisham Bn , Zarina Nik , Khansani Suryana Bt
Published: September 2011

Gravel pack and stand-alone screens (SASs) are the two most commonly used sand-control methods for openhole (OH) well completions in unconsolidated formations. When comparing the two methods, gravel pack is considered the more robust for sand control and is expected to have a longer service life than SAS in similar reservoir and operational conditions. However, gravel pack costs more per foot than SAS, which limits its use to poorer-quality sands in projects with acceptable economics. The industry has developed accepted criteria for selecting these sand-control methods, and this documentation provides guidelines as to when SAS should be sufficient and when gravel pack is more appropriate, depending on sand quality, which is based on particle-size distribution (PSD) of formation sand samples.

Unfortunately, many small oilfields with poor quality unconsolidated formations cannot be developed economically using gravel pack. SAS is the next best alternative, and often, the only option to bring those small oilfields online. The ‘J’ Field in Malaysia is an example of a small oilfield with marginal economics that was developed successfully using SAS completions despite the fact that the sand quality called for gravel packing. This paper discusses the methodology used in selection and sizing of the SAS design for the ‘J’ Field.

The methodology involves two major processes: 1) review of PSD information for initial screen micron rating selection, and 2), retention-plugging testing of wire-wrapped screen (WWS) and mesh screens for screen-type selection and screen micron rating optimization. Using this methodology, the operator and service company were able to design a completion strategy for eleven (11) wells that fulfilled the economic needs of the development project while resolving the sand-control needs.
Analytical Assessment of Water-free Production in Oil Wells with Downhole Water Loop for Coning Control
Authors: Jin L. , Wojtanowicz A. K.
Published: September 2011

Typically, in the presence of water coning, a water-free production is economically unattainable since critical rates are too small. Downhole water sink (DWS) technology has been proved and demonstrated as capable of significantly increasing critical rates. In actual practices, however, DWS wells have produced oil above critical rates but with lower water cut that resulted in high oil rates and the need for water separation. In fact, water handling is an inherent downside of DWS since the downhole water drainage (for coning control) involves independent lifting of oil and large amount of water to the surface. In contrast, downhole water loop (DWL) technique would combine coning control with water-free production by recycling the drained water from the water sink (drainage) and source (injection) completions and keeping the water in-situ. Experiments show that the beneficial effect of water recycling on well performance is very strong – a moderate water recycling rate would increase critical oil rate by ten times comparing to the conventional well.

Although attractive, the DWL technique is constrained by well-reservoir system properties such as oil viscosity, relative oil permeability, bottom water thickness, well penetration and reservoir anisotropy. This study offers a simple analytical model describing the effects of the above parameters on the water-free oil production rate. The model has been derived using principles of the flow potential theory and anisotropy transformation supplemented with some empirical correlations. A comparison with reservoir simulator demonstrates time savings and acceptable accuracy of the analytical approach. A sensitivity study reveals factors most critical for using DWL in specific reservoirs: critical thickness of the bottom water, limiting value of the fluids mobility ratio and strong effect of permeability anisotropy in the reservoir and water layer. Also presented is a statistical assessment of reservoir systems potentially suitable for the DWL technique.
Multifunctional Compact Well Maintenance System
Authors: Tait G. , Smith I.
Published: September 2011

Multi Functional Compact Well Maintenance System Provides the Ability to Evaluate, Maintain and Remediate Mature Wells Providing Cost Effective and Efficient Well Servicing.

In order to maximize production and to extend the economic life of their wells, Operators today face a number of challenges in organizing required services while maintaining cost efficiency. This is particularly true for wells on small or satellite platforms where available space is limited and crane capacity is often insufficient for some standard service equipment to be deployed. This can apply to many of the services required such as capillary string deployment for many forms of chemical injection, safety valve retrofit and remediation, Slickline services, surface readout or memory data acquisition and thru tubing installations such as plug setting. In many cases mobilization of a rig often supplies the only viable option, the cost of which can be prohibitive.

To address these issues a new Well Maintenance System (WMS) has been created which incorporates compact modular units each designed to weigh less than 2000lbs which are easily transportable and can be combined in various ways to provide all of the services which may be needed from a single source.

In this paper the authors will discuss the introduction of this versatile and compact multifunctional WMS which has been specifically designed to provide single source high performance, safe and efficient well service operations without the need for costly rig mobilization.
Modeling and Simulation of Nitrate Injection for Reservoir Souring Remediation
Authors: Haghshenas Mehdi , Sepehrnoori Kamy , Bryant Steven L. , Farhadinia Mohammad Ali
Published: September 2011

Reservoir souring refers to the onset of hydrogen sulfide production during waterflooding. Besides health and safety issues, H2S content reduces the value of the produced hydrocarbon. Nitrate injection is an effective method to prevent the formation of H2S. Designing this process requires the modeling of a complicated set of biogeochemical reactions involved in the production of H2S and its inhibition. This paper describes the modeling and simulation of biological reactions associated with the injection of nitrate to inhibit reservoir souring. The model is implemented in a general purpose adaptive reservoir simulator (GPAS). To the best of our knowledge, GPAS is the first field-scale reservoir simulator that models reservoir souring treatment.

The basic mechanism in the biologically mediated generation of H2S is the reaction between sulfate in the injection water and fatty acids in the formation water in the presence of sulfate-reducing bacteria (SRB). There are proposed mechanisms that describe the effect of nitrate injection on souring remediation. Depending on the circumstances, more than one mechanism may occur at the same time. These mechanisms include the inhibitory effect of nitrite on sulfate reduction, the competition between sulfate-reducing bacteria and nitrate-reducing bacteria (NRB), and the stimulation of nitrate-reducing sulfide-oxidizing bacteria (NR-SOB). For each mechanism, we specify the biological species and chemical components involved, and determine the role of each component in the biological reaction. For every biological reaction, a set of ordinary differential equations along with differential equations for the transport of chemical and biological species are solved.

The results of reported experiments in the literature are used to find the input parameters for field-scale simulations. This reservoir simulator can then predict the onset of reservoir souring and the effectiveness of nitrate injection and helps the design of the process. The comprehensive modeling accounts for variation in biological system characteristics and reservoir conditions that affect the production and remediation of hydrogen sulfide.
Polymer Chemistry Improves Productivity in Tight Gas Hydraulic Fracturing
Authors: Hutchins Rick , Daniel Sylvie , Wirajati Agustinus Yudho , Ladva Hemant , Williamson Don
Published: September 2011

An additive consisting of acrylic co-polymers, polyvinyl alcohols, polyvinyl acetates, polyvinyl versatates, butyl maleates, and polyvinyl pyrrolidones is considered as a fracture efficiency modifier (FEM) for inclusion in fracturing fluids for tight gas (0.001 to 0.5 mD). The chemical nature of the fracture efficiency modifier improves fluid efficiency, promotes cleanup, enhances gas production, and increases the effective fracture length. Although conventional thought suggests that fluid efficiency is not a controlling parameter in tight gas treatments, this work suggests it can be critical to enhancing well productivity. Lab studies support the field trends in regards to cleanup and fluid efficiency. A modified method for evaluating fluid loss tests provides more realistic values for wall building coefficient and spurt that can improve fracture simulator predictions and support the use of the fluid efficiency modifier.

The liquid additive is easily implemented in the field. Wells treated with the polymer chemistry have better initial and long-term production, faster cleanup to gas sales, longer effective fracture length and require less pad volume while placing the same amount of proppant. The paper also describes high differential pressure leakoff test results at 7,000 psi to emphasize potential irreversible damage due to fracturing fluid invasion into rock matrix. This condition is more prevalent as treated reservoirs become deeper, especially in active tectonic areas around the globe.

Tight gas wells with permeability from 0.01 to 0.14 mD show one year production improvements up to 41% due to the chemistry of the fracture efficiency modifier polymer included in the fluid. The wells typically were designed with reduced pad volume and production analysis suggests the wells show longer effective fracturing length, higher fluid efficiency and faster cleanup, while placing the same mass of proppant. Tighter wells with permeability of less than 0.005 mD showed higher conductivity with smaller fracture length. These wells showed cost reductions while yielding the same cumulative gas production.
Reservoir Fluid Evaluation and Flow Assurance Analysis: Offshore Field, South East Asia
Authors: Lim Lee Chin , Wa Wee Wei , Haddad Sammy , Tighe Michael
Published: September 2011

Representative fluid samples are essential to achieving high quality PVT and flow assurance lab analyses. This is especially important when downhole samples are acquired in an oil base mud (OBM) environment. These high quality samples are also needed to better understand reservoir and fluid behavior throughout the field life.

This work presents a case study of an offshore field in East Asia that required high quality reservoir oil fluid samples for detailed PVT and flow assurance analyses. An oil bearing sand was discovered during the development drilling phase of a predominantly gas bearing reservoir environment. It was required to take low contamination samples from this zone during the development drilling phase without compromising the primary well objective of completion as a gas producer. As such, samples had to be taken on wireline in an oil based mud (OBM) environment. Accordingly a carefully planned methodology and technology was planned and used to achieve the goal of obtaining reservoir fluid samples.

Samples acquired from a previous well in the field using traditional openhole wireline formation testing technology and methods resulted in relatively high contamination levels. High levels of OBM filtrate contamination typically have detrimental effects on the PVT analyses quality for both gas and oil samples. Rig time, cost and sticking risk also limited the time allowed for the wireline formation tester to stay stationary at a sampling depth. As a result, a decision was made to utilize a new sampling technology, Quicksilver, that is specifically designed to obtain low level contamination samples while minimizing sampling station and hence rig time. To achieve this goal, the job was carefully designed and monitored by operating company and service company experts in real time to ensure the required results. The sampling technology, method and field and laboratory results are presented in this work.
Evaluations to Mitigate Water Coning and Sand Production by Integrating LWD Technology with Completion Designs
Authors: Sharma Aviral , Bryant David , Bieltz Tom , Obvintsev Alex , Riegler Paul , Neuschaefer Russ , Kok Jeffrey , Han Shim Yen
Published: September 2011

Horizontal and multilateral completions have become increasingly popular as operating companies strive to maximize oil production and minimize the number of wells in Gulf of Mexico (GOM) Shelf. Horizontal oil producers are challenged by gas or water coning that can shorten the well life due to variation in wellbore pressure and reservoir properties from toe to heel. Differences in permeability and/or water saturation, undulations in the wellbore and toe to heel frictional pressure drop can all contribute to early gas or water coning. GOM Shelf sands are predominantly un-consolidated and therefore require appropriate drilling BHAs with placement strategies along with suitable sand control to prevent accumulation in the wellbore and/or erosion of down hole completion components and surface facilities. GOM Shelf sands can contain abundant fines and are non-uniform. The particle size distribution often varies with depth and along the wellbore, thereby making sand control a major challenge.

This study descends on an existing GOM Shelf horizontal well that was completed with prepacked screens that sanded in and plugged the well after five years of high water production. A recent reservoir saturation logging run across the reservoir near the toe-end of the lateral granted the viability to revisit this reservoir. Consequently, a new offset horizontal was proposed next to the existing one to sweep out the remaining recoverable reserves. Studies based on existing field data and history match were used to evaluate drilling, well placement, and completion design. Simulations were performed to evaluate attic placement methodology and the inclusion of Inflow Control Devices (ICDs) into the sand control completion and to optimize the integrated design. The results illustrates that attic placement is feasible using azimuthal resistivity measurement with the integration of ICDs to not only delay water coning but also choke back any water that might eventually migrate into the wellbore. Finally, the ICD modeling demonstrates improved sweep efficiency from toe to heel. Both water/gas coning and sand production impose significant risks for lateral well placement and completion design in GOM Shelf especially in horizontal and multilaterals wells. This paper addresses these risks and proposes optimum well placement drilling strategies and completion design to mitigate them.
A Versatile Method for Evaluation of Antifoaming and Defoaming Agents in Oilfield Applications as a Tool for Green Product Development
Authors: Mahmoudkhani Amir , Wilson Bobby , Rocker Jacob
Published: September 2011

Foams are encountered in aqueous and nonaqueous systems throughout the upstream oil and gas industry from drilling and cementing to primary separation and production. Anti-foamers and defoamers are key ingredients to ensure efficient operations where uncontrolled foam causes problems. Application and performance of anti-foaming or defoaming agents are often assessed by blender tests or using sparge tubes. These tests, although simple and easily executable, are largely nonrepresentative of real-world conditions.

A versatile method, the FEAT (Foam and Air Entrainemnet Test), has been developed to better simulate the field behavior of oilfield antifoamers/defoamers in a laboratory setting. The FEAT is used to evaluate and optimize a variety of oilfield aqueous/nonaqueous systems which produce or encounter foaming conditions. Foam is generated by gas entrainment in the test media at a given temperature and pressure in the presence or absence of a foaming additive. The foamed media is then continuously recirculated while density and mass flow rates are measured and recorded to objectively quantify antifoamer/defoamer performance. The recirculating media may be altered, if desired, by successive dosage of salts, hydrocarbons or water over the time to better simulate field conditions and present a spectrum of medium behavior and additive performance. The dynamic nature of this measurement loop enables the evaluation of chemical additive systems under a variety of conditions such as brine buildup, water hardness, or hydrocarbon leaching. FEAT offers a versatile technique for developing new liquid and solid green products. Experimental results and field trials confirm the FEAT method better approximates field performance than commonly used tests. This allows for greater refinement of oilfield antifoamers and defoamers which offers both environmental and economical benefits.
Numerical Simulation of Mass-Transfer between Matrix and Fracture
Authors: Jamili A.
Published: September 2011

This paper presents a mathematical model and its numerical solution, describing mass-transfer between a gas flowing in a fracture and resident fluids in the adjacent matrix block. The model accounts for diffusion and convection mass-transfer mechanisms both for gas and liquid phases. Diffusion mass-transfer between the matrix and fracture is modeled by a mass-transfer coefficient while the convection mass-transfer is accounted for using Darcy equation and the appropriate flow potential gradients. The injected gas transported into the porous matrix causes vaporization of oil in the matrix pores, which, in turn, is transported by convection and diffusion to the gas flowing in the fracture. Compositions of equilibrium phases are computed using the Peng-Robinson equation of state.

The mathematical model was used to simulate a nitrogen injection experiment (Morel (1990)). The experiment was performed in a 1-D horizontal Chalk core for 16 days. All sides of the core were sealed except one side, where the injected nitrogen gas in the fracture flowed across that face. The initial resident fluids (oil and gas) in the core were a mixture of methane and pentane.

Calculated results matched the experimental data, including recovery of each component and gas saturation profiles inside the core. The simulation revealed the presence of countercurrent flow inside the core. Diffusion was the major contributor to the mass-transfer mechanism between fracture and matrix during the early times in the experiment while convection mass-transfer was more significant after 15 days. While these results are significant to prove the viability of the numerical modeling, extension of these results to field application depend highly on reservoir pressure, composition and many other factors. Nonetheless, this paper gives credence to mathematical modeling and provides a test case for researchers using other numerical techniques.
CT-Conveyed Sand Jetting Perforation on Deep, Tight Gas Well: Treatment Fluid Selection and Application Perspective
Authors: Fryzowicz R. , Maas T.
Published: September 2011

In the tight gas formations the perforation channel can be created by means of abrasive action. If possible to implement, such a method would leave clean cut hole in the liner without sharp edges and perforation tunnel in the formation free of crushed zone. The main advantage of sand jetting perforation lays in the cleaner and larger perforation channel. Perforations created with sand jetting technique usually display reduced near wellbore friction during hydraulic fracturing operations.

The preparations for sand jetting perforation operation in deep wells require proper selection of the carrier fluid. In deep horizontal wells sand laden slurry has to travel through small diameter coiled tubing increasing the injection pressure at the pump. In order to lower pump pressure at the required treatment flow rates the sand is suspended in highly pseudoplastic fluid. The sand suspension in large suction lines and friction reduction in smaller coiled tubing (CT) are the main parameters required to complete the operation. The selection of proper carrier fluid maintaining both parameters at the bottom hole temperature is crucial to the job success.

This paper will discuss the testing of fluid systems from the perspective of the sand suspension and friction reduction capabilities along with the discussion of basic properties and parameters of the selected system. The findings from the tests will be verified by the actual sand jetting perforation operation on the offshore deep tight gas well.
Field Test Results of an Innovative New Drilling Tool using Rate of Penetration Modulation
Authors: Farley Steven Reid , Maranuk Christopher A , Jasper Clint
Published: September 2011

Mud motors, in conjunction with a bent sub, have been used for over 40 years to directionally steer wells to a target location. Mud motor technology is well understood and has seen significant improvements over the years. Rotary steerable tool technology is relatively new to the oilfield and improvements are still being made to enhance performance and reliability. The significant advantage of rotary steerable tools is that the drillstring is continuously rotated throughout the drilling operation. A new system for wellbore directional control has been developed which uses continuous drillstring rotation above a positive displacement motor and bent sub. This new system offers many advantages of a rotary steerable system but also offers the proven technology of a positive displacement mud motor.

Steering is accomplished by managing pressure fluctuations within the drill string, creating slight oscillations in the flow rate through the mud motor. These controlled undulations in flow rate allow high frequency variations in drilling parameters to steer the well in any targeted azimuth. If the objective cannot be achieved using rate of penetration modulation in rotary mode, then the motor can still be oriented using the more conventional means of stopping rotating, sliding against the borehole until the motor is in its new orientation, and returning to rotating.

This paper will discuss the advantages and disadvantages of the new system compared to both conventional mud motor and rotary steerable technology. The paper will also discuss the early field trials of the new system in various hole sizes and discuss how selected parameters affect performance.
The Shale Gas Potential of China
Authors: Wang Xiuli , Wang TianJiao
Published: September 2011

China is energy hungry and shale gas, a recent engineering feat in the United States, is likely to prove an invaluable asset for China as well. Currently about 70% of China’s total energy is still from coal and only 4% derives from natural gas. Natural gas per capita in China is about 2.2 thousand cubic feet per year while, in the United States, it is about 77.4. To reach a semblance of a developed country’s energy profile, China has to increase its natural gas usage and this is an expressed policy of the government.

With growing international demand in natural gas, shale gas has become the brightest spot. It is an unconventional energy source, extracted from reservoirs with very low porosity (2% or less) and permeability (0.1 to 0.0001 md or even less). There are abundant reserves around the world, about 16,000 trillion cubic feet (Tcf). In China, shale gas resources are widely distributed in the Sichuan, Tarim, and Ordos basins and other continental sedimentary basins with shale gas formation conditions. The estimated potential shale gas resources in China amount to about 1,084 to 3,530 Tcf.

Despite this potential, China's shale gas exploration and development is still at its infancy.

This paper investigates the status of shale gas development in China and describes shale gas accumulations, their geographical distribution and the economic value of shale gas production to the country. If, emulating the United States experience, where in the course of less than ten years shale gas contribution to total gas production increased from essentially zero to 17% (estimated), Chinese shale gas could deliver 1.8 Tcf of gas (from a total projected gas consumption of 10.6 Tcf) with an annual value of preventable imports of about $18 billion by 2020.
A Practical Solution to Describe the Proved Area within a Resource Play Using Probabilistic Methods
Authors: Dobson M. L. , Lupardus P. D. , Divine T. W. , McLane M. A.
Published: September 2011

The United States Security and Exchange Commission (SEC 2008) adopted revisions to the oil and gas reporting disclosure rules on December 29, 2008 that included expanded definitions to allow entities to disclose reserves using probabilistic methods. These benchmark rule changes, titled Modernization of Oil and Gas Reporting; Final Rule are coincidently timed with the rapid discovery and development of world class resource play reservoirs. These resource plays are favorable subjects for probabilistic evaluation due to their shear size, well count, projected future activity and significant current and future reserve impact.

The modernized rules create new opportunities in reserve disclosure as well as new potential pitfalls. Probabilistic methods are not required to be implemented for reporting; however, if used they need to adhere to sound statistical principles to serve the purpose of the new rules and yield robust results. This paper presents a new approach that incorporates probabilistic principles into a practical method for the first step in reporting undeveloped reserves in a resource play; empirically describing the proved area.

The practical method presented here does not use a probabilistic approach previously shown by others (Patricelli, 1995), (Mata, 1997), (Moore 1999), (Acuna, 2000), (PRMS, 2009). Additionally it does not rely on Monte Carlo simulations for input values based on geologic variables expressed as Probability Distribution Functions (PDF). Instead, the method employs production statistics of the existing Proven Developed Producing (PDP) well set within the play.

The analog to future wells involves the existing PDP wells in the same geologic and geographic portion of the play being evaluated. Empirically the step that describes the proved area is controlled by statistical rules for sample size and the principle of aggregation. This approach is likely only applicable to resource plays. Other factors such as gas-in-place and reasonable recovery factors must also be considered to insure the results are reasonable.

The probabilistic reserve evaluation method requires a comprehensive level of support documentation. The objective of this paper is to present the principles and methods that create a robust, reliable, yet simplistic way to evaluate the proved area component of reserves evaluation using probabilistic methods for resource plays. Proved, probable, and possible reserves are allowed to be disclosed under the new SEC rules. However this paper is limited in scope to proved reserves. Explanations are provided to show how SEC definitions and probabilistic concepts are integrated into the proposed method. The Fayetteville Shale is used throughout the paper to demonstrate the application.
Stage Isolation Failure of Non-packer Reasons in Openhole Horizontal Completion
Authors: Zhou Desheng , Yuan Hong
Published: September 2011

Multistage fracturing in openhole horizontal completion is an economic technology in the production of low permeability reservoirs. Openhole horizontal completion requires sealing the surface of horizontal wellbore rock directly to create stages for fracturing. Packers are usually used to create the sealing stages. However, stage isolation failure is not uncommon during openhole fracturing. Packer is commonly blamed for the failure in the industry. The paper studies the other (non-packer) reasons of the isolation failure based on rock mechanics, fracturing theory, and finite element analysis.

The paper presents that stage isolation may be failure even for perfect packers. Four sources may yield the multistage isolation failures in addition to packer itself. They are wellbore wavy, wellbore diameter change, wellbore deformation to oval shape, and axial fracture and fracture initializing location.

To avoid the non-packer isolation failure, horizontal wellbore survey, stress and deformation around a openhole horizontal wellbore should be analyzed. Engineers may use the paper to improve multistage fracturing in openhole horizontal completion. It is also useful in packer selecting, setting, and designing for an openhole horizontal completion.
An Integrated Performance Model for Multilateral Wells Equipped with Inflow Control Valves
Authors: Zarea Marwan , Zhu Ding
Published: September 2011

Intelligent well technology is a relatively new technology that has been adopted by many operators in recent years to improve oil and gas production, and recovery. The technology uses downhole monitoring and control to regulate flow condition and provides solutions to production problems. It is one of the most effective means for optimization of commingled multilateral wells in heterogeneous reservoirs. Due to the high cost and complexity in intelligent multilateral well constructions, accurate modeling of the reservoir, completion and wellbore performance is essential to design an economically beneficial well, and the critical component, inflow control valves (ICV), should be integrated into the performance modeling process.

This paper presents an integrated analytical model that is built on existing models for predicting reservoir and wellbore flow behavior. Also, equations that can predict the flow performance through restrictions such as ICVs, in a multilateral well system are incorporated into the analytical model. The integrated model estimates the reservoir inflow and flowing wellbore pressure at each lateral of a multilateral well, then predicts the anticipated pressure drop across each ICV for any given flow rate. By knowing pressure and flow distribution in a well system, the flow rate distribution can be balanced by operating ICVs to achieve better flow conditions. This analytical model provides the engineers with a hands-on tool to select proper ICV positions for each lateral or segment and helps optimize the well production. Examples at field conditions are used in the paper to illustrate how the model can be used to improve well performance. Applications such as preventing crossflow in commingled multilateral wells are also presented in the paper.
A Practical, Application-Based Guide to Borehole Enlargement Tool Selection
Authors: McCarthy J.. , Rebellon J.. , Barton S.. , Rambhai R..
Published: September 2011

With almost 45% of wells drilled globally employing some form of hole opening technology, borehole enlargement has become commonplace. However, for many reasons it can still be very demanding, from both planning and execution points of view, particularly in the deep water basins being exploited today.

To address the needs of these challenging applications, a variety of tools have been developed by many service companies. There are two primary borehole enlargement methods involving eccentric and concentric tools. Contained within these two general categories are many options: fixed cutter, roller cone, mechanical, hydraulic, hydro-mechanical, bi-center and so on. Factor in the different drive types available (rotary, positive displacement motor steerable, rotary steerable, coiled tubing) and the potential borehole enlargement options can quickly lead to a confusing, even circular, decision making process.

With so many options, an important question must be answered by the drilling engineer: How does one select the appropriate borehole enlargement option for a specific application? With continually increasing costs and more difficult wells being drilled around the world, there is little room for error. Several factors must be weighed and evaluated before making the correct decision. Depending on the type of well being drilled and the formation characteristics, one must choose the optimal BHA and drilling parameters to obtain a successful borehole enlargement result.

This paper reviews the decision making process that can lead to the best chance of success in many borehole enlargement applications. Understanding the application is critical in delivering a successful borehole enlargement operation. Based on results obtained over many years of industry experience with applications involving all types of borehole enlargement technologies available, a practical guide to hole opening solutions has been derived. It takes into account critical factors, including economics, borehole quality, equipment availability (including rig capacity), drive type, drilling parameters, the type of well being drilled, and formation characteristics.

After a brief introduction and a description of currently available technologies, this paper will review the decisions that are made in determining which borehole enlargement tool to use and how to apply these in practice. This allows the drilling engineer to have a practical view of the available options and their versatility for proper tool selection.
Comprehensive Energy Price Model Including Deepwater Drilling Risk
Authors: Belhaj Hadi , Lay Terry , Lau Richard , Lau Laura , Rahuma Khulud
Published: September 2011

Relying solely on traditional drilling technology to estimate the world’s proven Oil Reserves denies the likelihood that billions of barrels of unfound oil lay just outside the industry’s technological reach. With substantial financial and legal assistance and government support to develop newer technologies like Deep-Water Drilling (DWD), the major oil companies and the US White House are confident that new fields can be brought into production that should increase supplies and stabilize or lower energy prices. Each new find, they estimate, will help increase the world’s proven oil reserves allowing investors and consumers to feel more optimistic about providing for their future energy needs. It is also hoped that this new technology will lead to safer, more economic and environmentally appealing exploration and production methods (Belhaj, et al)1.

Pertinent questions arise as to what impact BP’s tragic oil spill may have on the future of Deep-Water Drilling and on the future of energy prices? Does industry have the technology to successfully and economically exploit fields using DWD? What role should governments play in regulating dangerous, environmentally unsound drilling practices? Should regulations be allowed to impede progress?

Identifying DWD as having a major influence on cost and being a critical parameter in any energy equation, the authors answer these questions and present two models that pessimistically and realistically describe the future role of DWD in places like China, India and Brazil over the next 50 years – places with growing populations and economies, but little government oversight.

Conclusions are reached with a discussion about the need for DWD in the current economic slowdown in advanced economies that have witnessed decreased oil demand and why traditional models affecting energy prices have been unsuccessful in predicting the current high energy prices.