bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of Different Stimulation Techniques, Multistage Proppant and Acid Fracturing Operations Offshore Congo
Authors: Rotondi M. , Pace G. , Malonga H. , Pounga F. , Batmaz T. , Ndoassal E. , Asibor E. , Sobernheim D. , Amare P.
Published: February 2011

This paper describes the successful combination of different stimulation techniques during the development phase of an offshore field in Congo. A total of four wells were drilled and completed during 2008-10. The target reservoir, the Sendji carbonates, has a total thickness of 150-170 vertical meters with an interlayer of ten meters. It is composed of silty-shaly dolomitic and quarzitic sandstone with interbeds of shale and sand grading to sandstone and silt with dolomitic cement characterized by very poor petrophysical properties. Laboratory testing with cuttings showed that formation is more than eighty percent soluble with fifteen percent hydrochloric acid. The typical well has an average azimuth and inclination of 60 and 350 degrees respectively, in the target reservoir. A good quality cementation job of the casing was required in order to ensure isolation from the aquifer. The well completions are both open and cased hole multistage fracturing completion systems. Selected zones of varying lengths were hydraulically fractured by using proppant / seawater-based borate crosslinker fluid or by using twenty percent delayed, viscoelastic and straight acid. Two wells were stimulated by means of proppant fracturing while the other two by acid fracturing. Due to upper / lower water zones with no bounding beds, it was important to define formation mechanical properties for fracturing designs in order to avoid fracturing into water bearing layers. A Mechanical Earth Model (MEM) was created by using sonic anisotropy measurements, modular dynamic test results, and other common electrical logging data together with drilling parameters. The detailed study of design methodology, different stimulation fluids and operation sequences are described. Particular attention will be given to the comparison of well responses to multi-stage proppant and acid fracturing techniques.
Use of Wellbore-Reservoir Coupled Dynamic Simulation to Evaluate the Cycling Capability of Liquid-Loaded Gas Wells
Authors: Hu Bin , Veeken Kees , Yusuf Rahel , Holmås Håvard
Published: February 2011

The regulated intermittent gas production by automated on/off of the wellhead choke, also called "well cycling", is often the only short-term option that the offshore operators can practice in order to prolong the well production life once they are loaded up by liquid. The field experiences show that many wells can be cycled for quite a long period, but some other wells may have no cycling capability at all. For the wells that can be cycled, the average production achieved by the cycling also depends on whether and how this process is controlled. These bring in a large uncertainty in predicting the field tail-end production.

This paper is therefore concerned with the numerical modeling and simulation of the regulated well cycling. As the process involves both wellbore and near-wellbore reservoir dynamics, an integrated modeling approach is adopted through coupling a transient well flow model to a near-wellbore reservoir model. The coupled model was successfully used to investigate the cycling potential of a 3-km deep vertical well that produces from a depleted cylindrical reservoir of 100 meters in thickness and 560 meters in radius.

The simulation results confirm that the selected well can be cycled for a long period only if the operator pro-actively starts the cycling before the well is loaded up by liquid. The simulation also shows that the average gas production for the selected well can be at least doubled compared with the meta-stable production rate resulting from leaving the choke permanently open, which confirms the advantage of well cycling.

The major observation in this paper may fundamentally change the offshore gas well operation strategy as that the operators may start well cycling once they foresee liquid loading is soon due to occur in their wells. Besides, the simulation procedure presented can provide advices on how to optimize the timing of the choke on/off operation to maximize the average production.
Breaking the Boundaries for Wireline Sand Removal
Authors: Karlsen Ole Eddie , Mathiassen Erling
Published: February 2011

A new application of wireline tractors in combination with wireline sand removal technology has been proven in the Norwegian Continental Sector. Statoil experienced problems with sand build up in one of their production wells and needed to gain knowledge weather it was sand production or mechanical issues that disturbed the well. When using traditional equipment only 2.5 dl of sand were removed, which provided no conclusions for the operator.

It was decided to use the wireline cleaner PST (Power Suction Tool) to determine what caused the decrease in production. The PST is a newly developed cleaning device that can be run on electric wireline, either with a wireline tractor or as a "stand alone" tool.

The PST removed 26 litres of sand after the second run, which corresponds to a full bailer chamber that was used on this particular job. The PST is capable of carrying up to 100 litres of sand in one run.The offshore operation was successfully completed and after three runs it was possible to conclude status on the actual well. In this case, the problem was identified and the operator received improved knowledge of the down hole conditions that made it safe to continue the production.

With this new technology, it has been proven that the PST is an effective solution to elucidate down hole sand problems. This new application for sand removal in completion hardware and other well bore obstructions offers a cost-efficient alternative technology to existing methods. The success of the cleaning operation is quite an achievement and has pushed the limits for what is possible to achieve on electric wireline.

This paper will examine the challenges and solution chosen in an operation of removal of sand on electric wireline.
Well Design Specificities for Shallow Gas Production of Tunu Field
Authors: Oumer S. , Taufiqurrachman H. , Perruchot M. P. , Yunus F.
Published: February 2011

Since the beginning of Tunu field development in the late 80’s, shallow gas hazard has always been considered the major operational risk during the surface drilling operation. During the last ten years, 5 shallow gas events were reported; all have been safely controlled (no injured personnel) and the main consequences were material loss and non productive time.

With the objective to reduce shallow gas reservoir crossing, a high resolution seismic survey was performed in 2005. The survey results have been used to early identify potential shallow gas hazards at planning stage by 1) checking the field history of the selected future platform area and 2) systematically reviewing the seismic data on a well by well basis. Despite of the above described mitigation measures it appears that during 2007/2008, amongst 88 wells drilled, 43 shallow gas reservoirs (thickness above 6m) have been crossed on Tunu field. This phenomenon is directly linked to the geological fluvial deposit specificities of the Mahakam delta.

The shallow gas horizons (500-1200m TVD) became recently a source of interest for the geoscientists who mapped the gas in place yielding substantial reserves. After the potential has been confirmed, the drilling engineering studies started in order to design a well being able to produce shallow reservoirs. It is worth to remind that shallow gas drilling engineering is not a routine job…What kind of well architecture? Do we set a surface casing? Where do we set it? How will we manage the extremely low LOT at casing shoe? Which mud type has to be used? What will be the required mud density? How do we manage potential unconsolidated sand production....? So many questions looking for accurate technical answers in order to convert a hazard into a well.

In 2010, a specific development plan has been proposed and approved for constructing 17 shallow gas wells, showing highly encouraging production results to date.
Monitoring Reservoir Performance in Highly Prolific Deepwater Gulf of Mexico Gas Wells
Authors: Chu Wei-Chun , Gray W. M.
Published: February 2011

The deepwater Gulf of Mexico contains numerous gas fields with highly prolific wells that have the potential to deliver exceptional profitability to an Operator. This paper presents a case history of the utilization of real-time well surveillance data to assess well performance, reservoir drive mechanism, and original gas-in-place ("OGIP") in a small discovery. The significant implications for in-depth production data analysis, material balance applications, and dynamic reservoir modeling techniques are also emphasized.

Interpretation of discovery well flow performance established the flow potential of a prolific gas producer corresponding to its associated down-hole and surface conditions in what was originally thought to be a single well subsea tieback development. Indepth analysis of the initial pressure and production data offered an early estimate of OGIP providing indications of reservoir compartmentalization before the reservoir drive interpretation of OGIP for the field was fully understood and enabled monitoring of aquifer invasion. Accurate, continuous surface and down-hole surveillance facilitated interpretation of reservoir depletion and in conjunction with sequential, unscheduled shut-ins during the production life of this subsea tieback, the true geometry of the structure was revealed and the impact of aquifer encroachment was quantified.
A New Approach to Generating Fracture Conductivity
Authors: Gillard M. , Medvedev O. , Peña A. , Medvedev A. , Peñacorada F. , d'Huteau E.
Published: February 2011

The primary goal of a hydraulic fracturing treatment is to create a highly conductive flow path to the wellbore that economically increases well production. In moderate and high permeability wells the lack of adequate fracture conductivity is a limiting factor in the production potential of the well, whereas in tight gas reservoirs the limiting factor is often the effective fracture half-length. Even in the last case, adequate fracture conductivity is important to allow efficient recovery of the fracturing fluid.

Traditionally, efforts to enhance conductivity have been directed to improve the ability to flow through a porous proppant pack. The industry has extended significant efforts towards the goal of increasing proppant pack permeability through the development of less damaging carrier fluids, higher strength man-made proppants, more efficient fracturing fluid breakers and so on.

As an industry however, we continue to struggle with the fact that well testing frequently indicates disappointingly shorter or less conductive fractures than designed. Multiple studies indicate that proppant-pack retained permeability is often a small fraction of the maximum expected value.

This manuscript describes a novel hydraulic fracturing technique that enables a step-change approach towards increasing fracture conductivity. The technique is based on the creation of a network of open channels inside the fracture.

Modeling and experimental work indicates that the new technique can deliver conductivities in excess of ten-times those obtained from conventional fracture treatments. Extensive lab-, yard- and field- scale experiments combined with theoretical work allowed creating the framework that describes the physical processes occurring during the application of this new technique.

By providing significantly higher fracture conductivity, this new fracturing approach delivers a number of consequential benefits: better fracture cleanup; lower pressure loss within the fracture; longer effective fracture half-lengths, all of which will contribute to improved short- and long-term production.

A 15-well field study, selected from over fifty treatments performed up to date with this technique, is presented to show posttreatment results with significant gains in well production and expected ultimate recovery with respect to offset wells treated with conventional fracturing methods.
Permanent Tracers Embedded in Downhole Polymers Prove Their Monitoring Capabilities in a Hot Offshore Well
Authors: Nyhavn Fridtjof , Dyrli Anne D
Published: February 2011

Tracers are applied as embedded in polymers that are placed in the downhole completion. The Tracer Systems are designed to change behaviour as a function of the surrounding medium. Such behavior can be the release of tracer into one medium while keeping tight in another. Released tracers will migrate to surface where topside fluid samples are analyzed and the tracer concentrations in those are the basis for extracting Well Inflow Information.

The Tyrihans well, B-IAH T2, was cleaned-up in two sections and the 1100m long toe section was equipped with 3 unique oil soluble tracers that were placed along the production zone. The objective was to evaluate the quality of clean-up and (if necessary) also during a production restart 6 months later. The well had a downhole temperature of 137°C, higher than the operating temperatures for available Permanent Tracer Systems. So a new Tracer System had to be developed and qualified for the case.

RESMAN's tracer systems indicate that the toe is contributing as expected to the fluid production and that additional production occurs along the well bore. All completion fluids in the lower completion seem to be fully cleaned-up. All 3 tracers adds value to the interpretation. Extra information on the fluid dynamics of the clean-up process could be indicated.
Novel Emulsified Acid Boosts Production in a Major Carbonate Oil Field with Asphaltene Problems
Authors: Appicciutoli Danilo , Maier Robert , Strippoli Danilo Pasquale , Tiani Alessandro , Mauri Luca
Published: February 2011

When performing matrix-acid treatments, the goal is to stimulate the formation as deeply as possible, distributing the acid uniformly over the total zone of interest. Uniform distribution is even more important when intervals are long, horizontal, or several zones with natural fractures predominantly take the reactive fluid. In Italy's major oil-producing field, all of these challenges are faced.

In addition, during production, asphaltenes form and are deposited in the well, making it even more difficult to distribute the acid evenly. Because the field is located in an environmentally sensitive area, all fluids need to be mixed and pumped using a zero-operational-risk philosophy. Some of the matrix-stimulation challenges were overcome as a result of the development of a novel emulsified acid that combines the practiced asphaltene-dissolving technique with proven acid-diversion technology. The environmental challenges are overcome by creating an oil-external/acid-internal emulsion, on-the-fly, just before the fluid is pumped downhole.

This paper describes the engineered process of finding solutions to the challenges, beginning with laboratory testing to develop and optimize the solvent part of the innovative acid system. Further, an overview of how operational difficulties were resolved and how the innovative fluid system was applied is presented. The first section of the paper outlines laboratory testing, showing that an emulsified-acid system can be mixed with custom-tailored asphaltene-solving blends and provide the desired benefits for matrix acidizing, such as a slower acid reaction, higher base viscosity, and excellent emulsion stability in temperature. The second part of the paper explains the equipment setup used to create the acid system ready for field application in an environmentally sensitive area. The third part of the paper describes how the novel acidizing approach in its first field application boosted production to unexpected highs.
Using a Fully-Coupled Flow and Geomechanical Simulator To Model Injection Into Heavy-Oil Reservoirs
Authors: Huang Hao , Wattenbarger R. Chick , Gai Xiuli , Brown William P. , Hehmeyer Owen J. , Wang Jianlin , Long Ted A.
Published: February 2011

In this paper, the geomechanical factors that may affect injection processes in heavy oil recovery are investigated. To accurately capture the geomechanical effects, a new numerical formulation that allows fully coupled simulation of porous media flow and geomechanical deformation is proposed. Two salient features of this new coupling formulation are (1) all flow and geomechanical equations are solved implicitly in one single matrix equation, and (2) it allows reuse of matrices from both a traditional fully implicit multi-component reservoir simulator and a nonlinear geomechanics simulator. The former feature ensures stable coupling between the reservoir flow and geomechanics, and the latter significantly reduces the programming work. Numerical examples are given to demonstrate the accuracy and convergence performance of the new formulation.

The proposed formulation is then employed to model injection into heavy oil reservoirs. The numerical investigation revealed that geomechanical factors, such as in-situ stress anisotropy and the incompatible deformation of reservoir rock and attached impermeable rock, can result in uneven shear dilation, and hence alter the sweep of the injected fluid. Coupled geomechanics simulation also gives rather different transient pressure response from that of uncoupled simulation. In the end, an example on how to utilize the formation deformation results to evaluate casing and cap rock integrities is given.
Modeling High-Viscosity Oil/Water Flows in Horizontal and Vertical Pipes
Authors: Zhang H.-Q. , Vuong D. H. , Sarica C.
Published: February 2011

Water is produced along with heavy oil either during the primary production or enhanced oil recovery. Therefore, oil-water flow is a common occurrence in heavy oil production and transportation. Production system design is strongly dependent on the accurate predictions of the oil-water flow behavior. The predictions of previous mechanistic models for pressure gradient and water holdup are tested with the data acquired, and significant discrepancies are identified, especially for horizontal flow (Vuong 2009). The model performance is largely dependent on the predictions of phase inversion, distribution and interaction. Based on the new understandings from experimental observations, The Zhang and Sarica (2006) unified model is modified by adding a new closure relationship for water wetted wall fraction in stratified flow and a new interfacial shear model based on mixing length theory. The new model is compared with both high viscosity and low viscosity oil-water flow experimental results, and significant improvements are observed.
The Impact of Hierarchical Fracture Networks on Flow Partitioning in Carbonate Reservoirs: Examples Based on a Jurassic Carbonate Ramp Analog from the High Atlas, Morocco
Authors: Agar Susan M. , Geiger Sebastian , Matthäi Stephan , Alway Robert , Tomas Sara , Immenhauser Adrian , Shekhar Ravi , Paul Jonathan , Benson Greg , Karcz Zvi , Kabiri Lahcen
Published: February 2011

Hydrocarbon reservoirs commonly contain an array of fine-scale structures that are below the resolution of seismic images. These features may impact flow behavior and recovery, but their specific impacts may be obscured by the upscaling process for sector and field-scale reservoir simulations. It is therefore important to identify those situations in which subseismic structures can introduce significant departures from full-field flow predictions. Using exposures of Jurassic carbonate outcrops near the village of Amellago in the High Atlas Mountains of Morocco, we have developed a series of flow simulations to explore the interactions of a hierarchical fracture network with the rock matrix of carbonate ramp strata. Model geometries were constructed in CAD software using field interpretations and LiDAR1 data of an outcrop area that is 350 m long by 100 m high. The impact of water injection on oil recovery between an injector and producer pair was investigated. Simulations were performed by a single medium reservoir simulator using a single mesh to represent fracture planes as well as rock-matrix volumes. The effects of changing scenarios for rock permeability and porosity as well as facture permeability distributions were investigated. First-order results show that the best recovery was achieved by a model with a high permeability, homogeneous matrix combined with a heterogeneous fracture network. The worst recovery scenario was given by a model with low, homogeneous permeability and high fracture permeabilities. After approximately 450 days there is a divergence in recovery profiles. Three models continue to recover oil while average oil saturations for the other 4 models start to plateau. The divergence does not simply reflect homogeneous vs. heterogeneous matrix models but captures a threshold between high and medium fracture-permeability scenarios that determines whether recovery continues in late time or the well starts to water out. The results highlight the importance of the permeability contrasts between the matrix and the fractures for overall recovery and the very significant impact that fractures can have on recovery by creating shadow zones and providing critical connections between permeable layers. The presence of the hierarchical fracture network developed strong fingering even in homogeneous matrix cases and evolving velocity patterns reveal competing fluid pathways among matrix and fracture routes. Insights from these models can help to develop production strategies to improve recovery from fractured carbonate reservoirs and provide an initial platform from which to extend further evaluations of different populations of conductive and baffling structures, spatial variations in wettability and capillary pressures and well positions.
Paraffin-Plug Remediation in Deep Water Wells via Capillary Tubing: A Cost Effective Alternative
Authors: Embrey Mark , Larke James
Published: February 2011

Description: A 5/8" capillary unit was used to effectively remediate a paraffin plug from a deep water Gulf of Mexico well saving the operator the expense of a coiled tubing job.

Application: The formation of organic deposition in oil wells is inevitable. This hindrance is an even larger problem in deep water wells where the produced fluid experiences temperatures near freezing at the mud line. Paraffin inhibition methods such as down hole injection of chemicals and insulated risers can be effective as long as the well is flowing. If the well is shut in for a long period of time, these inhibition methods are not effective and a paraffin plug is likely.

Results, Observations, Conclusion: A capillary tubing unit was used to deploy 5/8" capillary tubing to the paraffin plug. A paraffin solvent was then pumped down the capillary tubing to remove the plug. After adequate soak time the blockage was cleared, and the operator gained communication with the well.

Pumping solvents from surface or down hole through the chemical injection mandrels was proven ineffective due to the solvent not being able to contact the plug. Washing or milling the plug with a coiled tubing unit or workover rig was not desired due to the cost and exposure. Other advantages of utilizing the capillary unit were: small footprint, less personnel required, reduced safety risk, less rig up and rig down time, and the crane was freed up by not having to support the injector head.

Significance of Subject Matter: Operators now have a cost effective alternative for removing small amounts of deposition in a well. The light weight, small footprint capillary units can access platforms with de-rated cranes and limited work decks giving operators other options for intervention work.
Horizontal Drilling and Well Completion Optimization in a North Dakota Bakken Oilfield
Authors: Zander Dennis , Czehura Michael , Snyder Daniel J , Seale Rocky
Published: February 2011

First discovered in 1951, development of the Bakken formation in the Williston Basin has been problematic and inconsistent. However, technological advancements in horizontal drilling and completions in the past decade have steadily improved production results and consistency on a well by well basis. So much so, that the United States Geologic Survey (USGS) reported in 2008 that the undiscovered, technically recoverable oil in the Bakken was between 3 to 4.3 billion barrels.

How many fracture stages to run and how far apart to space stages in horizontal wells are prevalent questions asked by the oil and gas industry. This study provides insight into the advantages of various stage numbers and optimum stage spacing by analyzing up to 15 months of production results from horizontal wells targeting the Bakken in the Stanley Field, North Dakota. These wells were completed with open hole, multi-stage fracturing systems (OHMS) and production is compared to offset wells and field averages.

Advancements in OHMS completion and fracturing technology have enabled maximized production from this asset. The lessons learned and methodology can be utilized for other unconventional oil and gas plays around the world.
Meeting the Challenges in the Downhole Scale Control for High-Water-Production Horizontal Wells in Environmentally Sensitive Part of the Norwegian North Sea
Authors: Chen P. , Montgomerie H. , Hagen T. , Vikane O. , Juliussen B. , Haaland T. , Nguyen K. , Chen T.
Published: February 2011

Due to the seawater injections in one of in Norwegian Sea oil fields, sulfate scale depositions have been identified in the near well bore region and inside the production well. The scale inhibitor squeeze treatments are regularly carried out. Most of the production wells are horizontal producing with a fairly high water cut and increasing the squeeze treatment life is one of the major issues for the selection of scale inhibitors and placement technologies. In addition, the inhibitor selected has to be environmentally acceptable and meet the regulations from the environmental authorities. Both challenges from the high water production wells and environmental requirements limited the choice of the inhibitor candidate selections.

Through extensive laboratory qualification testing, a newly developed polymer inhibitor was qualified for the field and satisfactory results were achieved from several field trials. This paper presents the inhibitor chemistry as well as the laboratory tests such as inhibitor efficiency, compatibility and inhibitor core flood. The environmental properties of the chemistry will be outlined. A comparison was made between the field treatments using this polymer inhibitor and widely applied polymer chemistries. The treatment optimization using a software package will also be highlighted. The field has utilized the gelled scale inhibitor package and the technology improved the inhibitor placement in the horizontal well. The updated treatment data will be reviewed in this paper.
A two-stage well placement optimization method based on adjoint gradient
Authors: Forouzanfar Fahim , Li Gaoming , Reynolds A. C.
Published: February 2011

As well locations are represented as integer well gridblock indices in reservoir simulators, determining optimal well locations is most naturally treated as a discrete optimization problem. A few recent papers in the literature have attempted to convert this discrete optimization problem into a continuous optimization problem, but most of these papers require that one specify a priori both the number of wells to be drilled and the operating rates (or bottomhole pressures) for the specified operational life of the reservoir. Therefore, the final optimal well locations may not be optimal when different well rates (or bottomhole pressure) and/or reservoir production life are specified. The methodology in this paper attempts to mitigate the effects of an ad hoc specification of both operating well rates (or pressures) and operational reservoir life by using an initialization step to determine an appropriate total reservoir water injection rate and/or total reservoir production rate for the specified operational life. After the initialization stage a second stage is performed in which we estimate (i) the optimal number of water injection wells and/or producing wells; (ii) the optimal location of these wells and (iii) the optimal rates at these wells. Both stages use a gradient based optimization algorithm with the relevant gradient computed by a combination of the adjoint method and analytical methods for linear constraints which are imposed using a gradient projection method. A practical method is proposed for imposing nonlinear bound constraints on the bottomhole pressure of each well.
Does the Presence of Natural Fractures Have an Impact on Production? A Case Study From the Middle Bakken Dolomite, North Dakota
Authors: Mullen M. , Pitcher J. , Hinz D. , Everts M. , Dunbar D. , Carlstrom G. , Brenize G.
Published: February 2011

During the last 10 years, more than 2,000 horizontal wells have been drilled and completed in the Middle Bakken formation, which is sandwiched between the two Bakken organic-rich shales. Although most of the debate about this reservoir has centered on the lateral length, stimulation treatment, and the number of treatments, little work has been performed to explore the variations of rock properties and the effect of natural fractures along the 6,000 to 10,000 ft lateral lengths.

Maintaining the horizontal well between the two Bakken shales is easily accomplished with only a gamma ray tool. There are, however, two important questions to be addressed. First, is this an optimal practice for well placement? Second, is there a "sweet spot" layer in which the horizontal well should be placed to increase production?

In a recent well, an azimuthally-focused resistivity (AFR) tool and an azimuthal deep-reading resistivity (ADR) tool were run as a final wiper trip to investigate the location of natural fracture swarms and the variations of rock properties along the 10,000-ft lateral. The goal of this exercise was to test the concept of improving production by using a "smart" horizontal completion technique, spacing the swellable packers, and locating fracture stages based on horizontal reservoir data. The AFR image log identified more than 839 individual fractures in four fracture swarms. The ADR mapping showed approximately 40% of the lateral in the sweet spot layer. The evaluation of a post-stimulation oil tracer indicates that these sweet spot layers provide 70% of the production after stimulation. If the well had been geosteered to remain within the sweet spot using a smart completion technology, the production modeling suggests that production could have been increased by 20%.
Enhanced Production Profiling of Gas Wells Using a New Method to Model the Geothermal Temperature Gradient
Authors: Johnson M. D. , Briceño M. G. , Hutchings A. C. , George D. R.
Published: February 2011

Quantitative gas and water production profiling is very useful in completion and production performance evaluation. Production profile analysis that incorporates mass rate modeling of the flowing temperature has dramatically increased confidence in profiling results. Accurate mass rate modeling requires an accurate estimate of the geothermal temperature gradient. The conventional technique of estimating a linear geothermal gradient is not reasonable in producing regions with long completion intervals and complex lithologies. This paper will detail a new method of simulating the geothermal temperature gradient and advances in quantitative production profiling.

A multi-well study was conducted in the Piceance Basin in Northwestern Colorado because of the unique effect of lithology on the geothermal gradient. Coal, sand and shale sequences which impact the geothermal gradient must be taken into consideration. The study includes open and cased hole log data to define lithology and shut-in temperature data to characterize the geothermal gradient. An analytical simulator was developed to model the geothermal gradient. Research in rock, mineral and fluid thermal conductivities is utilized to qualify the field data and analytical model.

Results demonstrate that higher shale volume and coal beds increase the geothermal gradient above clean sand layer gradients. Measured geothermal gradients across coal bearing intervals are an order of magnitude higher than clean sand intervals. Geothermal gradients from the simulator were used as constraints in production profile analyses. The analyses will illustrate the identification and quantification of zonal gas and water production, even when some of the wells were flowing under adverse conditions of low gas rate, severe slug flow and high water production.

Enhanced production profiling has enabled the operator to enhance their reservoir characterization, completion strategies and production performance of future offset wells. Other applications for the technology include: 1) production profiling in similar regions with complex lithology and non-linear geothermal gradient, and 2) distributed temperature sensing used for continuous temperature and production profile monitoring.
Estimation Of Uncertainty In Microseismic Event Location Associated With Hydraulic Fracturing
Authors: Castano A. F. , Sondergeld C. H. , Rai C. S.
Published: February 2011

The efficiency of hydraulic fractures largely determines the economics of tight sands and gas shale reservoirs. Efficiency is defined by the fracture conductivity which results from the stimulation treatment. This is a function of fracture half length and height. Independent measures of fracture length and height, and containment provide prime data in evaluating stimulation treatments. Downhole or surface microseismic monitoring produce spatial distributions of microseismic events associated with hydraulic fracturing. These distributions provide the constraints on fracture length, height and containment. Most commercial product offerings ignore uncertainty in locations and biases produced by limited observation arrays. We examine these uncertainties and biases through an analysis of a simulation of event locations and sensor arrays. In addition, we investigate the errors produced by ignoring velocity anisotropy characteristic of gas shale.

We studied a set of synthetic microseisms locations. Simulations results demonstrate that mapping fracturing geometry with subsurface sensor arrays requires at least two observation wells (not a common field practice); this minimizes the geometry bias generated when only one observation well is used. One of the two observation wells should be aligned in the direction of the fracture azimuth. Failure to do so results in underestimation of the fracture half-length by approximately 10%. This requires knowledge of the prevailing in-situ stresses directions prior to stimulation. Downhole sensors should be located at the same depth of the fractured formation to avoid errors in fracture height estimation which can be as much as 50%. Velocity anisotropy has a minimal influence on uncertainty in event locations when subsurface sensor arrays are modeled with horizontal velocities. Surface sensor arrays can lead to underestimation of the fracture half-length in the order of 30% to 40% depending on the anisotropy effect whereas fracture height estimation error can be as much as 4%. Analysis of surface sensors arrays which avoid production shutdowns, reveals fracture half-lengths can be underestimated by about 17% to 31% depending on the velocity anisotropy. Uncertainty in event locations using only the vertical velocity in an anisotropic velocity field reduces with increasing depth as expected. Recent analysis of spatial distributions of microseismic activity for effective permeability and diffusion coefficients requires improved location accuracy and estimations of uncertainty.
Unconventional Well Profitability vs. Asset Profitability
Authors: Sedillos Lia , Roundtree Russell , Wright John , Miskimins Jennifer
Published: February 2011

The reserves growth in unconventional resources over the last three years has taken everyone by surprise and the ramifications are only now being fully realized by the marketplace and government. The role of shale basins in this growth has forever changed the skill expectations of oil industry professionals. This growth, primarily focused in North America today, will almost assuredly spread globally.

The economics of unconventional resource plays are quite different from those of conventional plays. Even the business metrics of success are usually ranked differently (Roundtree et al, 2009). This paper examines the overall cost structure of unconventional plays (land, drilling, completion, and well operation) versus the potential return. Prudent application of front end exploration to enter a play under favorable land price conditions, pragmatic well construction and completion practices to control costs, and efficient development drilling programs to optimize the resource recovery factors must all be considered in overall resource play economics. We demonstrate how irrational pursuit of lower development costs can often be detrimental to overall play economics and ultimate resource recovery.

Investor and governmental pressure may grow as these stakeholders segregate the operators who excel in achieving a balance of the different factors to sustainably produce better economic returns for their shareholders while extracting the maximum recoverable resource from the reservoirs in question. Stranded reserves will be seen ever more so as a measure of engineering malfeasance and not just sub-optimum economics.
Integrating Nuclear Magnetic Resonance, Production Logging, and Well DST Data: A Case Study in Carbonates From Brazil
Authors: Netto P. , Tinoco F. L. , Souza A. M. , Beer R. , Araujo M.
Published: February 2011

Modern logging tools, including Nuclear Magnetic Resonance (NMR), allow geoscientists to integrate data and use advanced petrophysics techniques. The NMR logs estimate permeability curves based on empirical equations and their response are sensitive to the permeability trends in rock layers of a heterogeneous reservoir. Therefore, it is possible to define flow units based on NMR flow capacity. This process can even be enhanced if there are Production Logging results available.

This paper presents a technique applicable to well test interpretation which consists in estimating the permeability of flow units through the integration of NMR, formation tests and production log data.

The properties of each flow unit such as thickness, average permeability and effective porosity are estimated from the NMR log. Using these data a multilayer flow model is built, in order to determine a multiplicative factor for the prior defined average permeability from each flow unit honoring the results of DST data. Several simulations are performed by changing the horizontal and vertical permeabilities and skin factor for each flow unit, to obtain compatible results with the well test.

This technique is applied in Brazilian carbonates. The cumulative NMR permeability curves shows good agreement with PLT data, which means that the NMR can be used as a predictive flow unit identifier when PLT data are not available.

In conclusion, the technique permits the interpreter to test various scenarios in a multilayer model, using different combinations of permeability and skin values for the flow units. This petrophysical model can also be used as an input for the dynamic simulation of the reservoir.
Solid-Particle Erosion in Slug Flow
Authors: Throneberry J. M. , Zhang Y. , McLaury B. S. , Shirazi S. A. , Rybicki E. F.
Published: February 2011

Sand erosion in multiphase flow is receiving widespread attention from the oil and gas industry. Several tools to predict erosion have been developed. One tool, called SPPS (Sand Production Pipe Saver), predicts penetration rates (pipe thickness loss rate) in fittings such as elbows. This tool accounts for many different operating conditions and can also be used to predict threshold flow rates that will result in only a tolerable amount of erosion. The SPPS model can be used to help avoid major pipeline failures, plan inspections and maintenance, develop cost to benefit projections, or estimate life expectancy of a pipeline for known flow conditions and sand production rates. Many flow regimes can occur in multiphase flow. This study focuses on the flow properties that effect sand erosion rates for slug flow. Experiments were conducted and a mechanistic flow model was developed. Erosion data were obtained for slug flow through an elbow and in a straight section of pipe. Erosion data show the effects of varying the superficial liquid and gas velocities, the liquid viscosity, the sand size, and sand rate. Data acquisition was accomplished through electrical resistance (ER) probes. Two flat-head ER probes were positioned in an elbow at 45° and 90° flush with the pipe wall. One intrusive probe was deployed in a straight section and protruded into the flow. Increasing the superficial gas velocity in these flow regimes extensively increases the erosion rate while increasing the superficial liquid velocity does not significantly increase erosion. Increased viscosity decreases the impacting velocity of impinging particles, and thereby reducing the magnitude of erosion on the pipe wall. The affect of particle size has been investigated and found to vary with viscosity. These trends were also found to vary with location of the probe. A mechanistic erosion model was also been developed. Model results are compared with sand erosion data. Predicted erosion rates from the model developed during this investigation agree well with the data collected in the present work and in previous studies.
Rethinking World Oil-Shale Resource Estimates
Authors: Biglarbigi Khosrow , Crawford Peter , Carolus Marshall , Dean Christopher
Published: February 2011

World oil shale resources are massive compared to conventional oil, making oil shale one of the world's largest known fossil fuel resources. The estimated oil shale resource in place for various countries is an evolving and growing number. The total world resource estimated by the USGS is currently 2.8 trillion barrels of shale oil; but may be as high as 8 trillion barrels depending on the quality of oil shale deposits considered.

In 2009, the USGS updated the resource base estimate for the U. S. Piceance Creek Basin, part of the Green River Formation, from 1.0 to 1.5 trillion barrels of oil shale. More than 1.8 trillion barrels of oil are believed to be trapped in shale in Federal lands in the western United States in the states of Colorado, Utah and Wyoming. This resource alone is over three times the proven reserves of Saudi Arabia. While the Green River Formation is the largest deposit of oil shale, there are over 30 countries with known oil shale deposits world wide.

With the price of oil staying well above $50 per barrel, new production technologies being considered by private companies for oil shale development may be economic. As these technologies are developed, resource estimates are also becoming more accurate. This paper describes some of recent resource estimates that have been further analyzed with measures such as resource yield and thickness also being described. Estimates will include the USGS update of the Green River Basin and results of Canadian exploration in the Albert Mines and in the Pasquia Hills. The paper will also provide an overview of global oil shale operations, including those in Estonia, China, and Brazil. Finally, this paper will provide a comparison of world oil shale resources and potential production profiles providing a world view of oil shale resources.
Shale Gas Well Completion Logistics
Authors: Tymko Dean W.
Published: February 2011

The introduction of large, multi-stage fracturing to the shale gas industry has made previous uneconomic shales economic to complete. These large scale stimulations present a new challenge in planning and logistics in order for the completion operation to be successful.

This paper provides an overview of the planning, execution, and improvement of logistics that went into the first two shale gas well completions in Northeast British Columbia, Canada for a large Canadian Energy Company. The logistical requirements taken into consideration when designing the first multi-stage horizontal well completion were: Fracture Stimulation, Lease, Fluid, Proppant, Equipment, and Completion Procedure. Planning these requirements started six months before completion operations commenced in order to meet the target pumping date of the stimulation and avoid costly delays.

The learning from the first shale gas well completion improved the logistics on the second shale gas well completion and the experience from the first two completion operations will shape future logistics as the project proceeds into the future. This paper shows that proper planning on large shale gas completions can pay off in well run, efficient completion operations that meet timing and cost objectives.
A Major Advancement in Expandable Connection Performance, Enabling Reliable Gastight Expandable Connections
Authors: DeLange Richard , Gandikota Raju , Osburn Scott
Published: February 2011

Since the introduction almost fifteen years ago of today's solid expandable liner systems, threaded connection technologies have advanced very little compared to the development of sophisticated, state-of-the-art expansion tools and systems. The severity of damage caused to threaded connections during the downhole expansion process leaves some threads unengaged and badly deformed reducing the connections’ mechanical dependability. Even worse, traditional metal seals incorporated into most proprietary premium connections are destroyed during the expansion process or damaged to the point of being undependable.

Even though solid expandable liner systems offer a large number of important and valuable solutions, connection performance is obviously a problem. For more than a decade, engineers have worked on the development of connection features that are more resistant to damage caused during expansion. Although there has been some advancement, today most or all expanded connections today share little resemblance to unexpanded connections when subjected to ISO 13679 qualification tests with gas.

This paper details new expansion cone technology that eliminates the majority of damage caused to connections when expanded with traditional cones. This paper will provide Finite Element Analyses and physical testing verification to show how this new technology leaves connections with minimal visible damage to the threads and metal seals after expansion.
High-Fluid-Loss, High-Strength Lost Circulation Treatments
Authors: Sanders Mark W. , Scorsone Jason T. , Friedheim James E.
Published: February 2011

A new high-fluid-loss, high-strength (HFHS) pill system has been developed and optimized using innovative test methods and trialed to ensure that it meets field criteria for addressing lost circulation problems. This new HFHS pill system works over a wide range of loss rates and provides a more effective and stronger seal than traditional treatments.

While the issue of lost circulation is one of the drilling industry’s most singular problems, the solutions are numerous and varied. Estimates of direct and associated costs to the lost circulation problem run into hundreds of millions of dollars globally, including whole mud losses, cost of treatment as well as lost time and tools. Discrete pills, formulated using a specific chemical and/or material blend, is one of the more popular approaches for curing severe lost circulation. These pills are mixed, pumped and spotted with the intention to either seal the loss zone or at least mitigate the losses sufficiently to regain the ability to circulate the wellbore fluid, control the well, and either continue drilling or set a string of casing.

Using new and innovative laboratory test methods, this paper evaluates the effectiveness of several commercially available defluidizing lost circulation treatments and discusses the development of a new HFHS lost circulation system. This new treatment has been designed and optimized using unique methodology to meet a set of “ideal” criteria for use in the field. Specifically, it must be easy to deploy, carry a low operational risk, as well as being effective at curing losses.