bluuebunny/crossref_metadata_2025 huggingface dataset:
The Equations Archie Forgot: Anisotropy of the Rocks
Authors: Haro Carlos F.
Published: October 2009

Archie's empirical equation is extensively used to estimate hydrocarbons in place. This power-laws combination has stood the test of time with little changes. However, it is still poorly understood and considered an ad hoc relation. Our original analysis will prove these laws rigorously, show how they must be amended, and introduce additional accompanying equations. This comprehensive model, which represents the electrical flow through the intricate conductive paths of the rock, is confirmed with Archie's and Hamada's core datasets. It corrects for Archie's inaccuracies.

A thorough appreciation of the pore scale physics behind the modified version of Archie's equation is presented. The principles can be applied in clean and complex formations (shaly-sands, thin beds, vuggy and fractured carbonates) to get enhanced values of water saturation. The theory sheds light on the role and quantification of anisotropy.

Solving for the elaborate pore geometry, we use the Laplace differential equation (not Ohm's law), appropriate in the analysis of electrostatic fields in charge-free regions. Rock morphology dictates its boundary conditions characterized as corner angles. The corresponding particular solution (flow around a corner) and modeling tactic delineate the streamlines throughout the pores. The angles establish strong mathematical links among the exponents of Archie's equation, the geometry of the rock frame and spatial fluid distribution. This quantitative method is lacking in previous saturation models.

The solution constitutes the basis to solve more complicated rock layouts. It enables the calculation of equivalent resistivities (normalized resistances) to take advantage of well-established electrical relationships. The extra equations compute the variable exponents and coefficients of Archie's equation at every depth. They obtain the saturation exponent in clean rocks as function of water saturation, crucial to quality control core electrical data, and to quantify reservoirs under changing saturation (waterflooding). Therefore, improved calculations of original and remaining hydrocarbons are achieved.
New Family of Setting Tools for Ultra Deep and High Temperature Well Condition
Authors: Kessler Calvin , Hill JIm , Shook Eddie , Housden Richard , Collum Eric V.
Published: October 2009

A new generation electro-mechanical downhole power unit for setting and retrieving packers, bridge plugs, whipstocks, subsea tree plugs, and other downhole devices has been recently developed and deployed. The new Downhole Power Unit – Intelligent, DPU-I® is designed to operate at high temperatures and extremely high pressures (400°F, 30K psi) and to provide up to 100K lbf setting force. The high force for either setting or retrieving downhole devices is independent of hydrostatic pressure and provides an alternative to jointed pipe or coiled tubing interventions, which were previously required to obtain high setting forces. New to the industry is the ability to monitor the downhole line tension, stroke length, setting force, the rate at which the force is being applied during the setting operation, and force at which the DPU-I detaches from the downhole device in real time at the wellsite or remotely by means of global satellite communications. This new functionality enables well completions experts to remotely monitor the setting or retrieval operations 24 hours per day, seven days per week. It also provides a record of the setting operation for risk mitigation, and for developing and improving best practices. This new downhole power unit conforms to our digital workflows used to model, measure, and optimize customer assets.

The slow controlled setting operation enables the slips or other anchoring mechanisms in the device to be set and to fully engage the casing/tubing and for the elastomer sealing elements to conform to the casing or tubing ID. This function is extremely critical in highly deviated well conditions and when using casing or tubing with high Rockwell hardness. Unlike setting devices that use explosives, military or governmental escorts are not required. In addition, single lift heli-operations can be used. This tool does not require radio silence operations, and there is no nonproductive time associated with tool redressing between runs. Tool sizes are available for well intervention in 2 3/8 in. tubing through 13 3/8 in. casing and can be tractor-conveyed in high angle or horizontal wells.
Upscaling of Miscible Floods in Heterogeneous Reservoirs Considering Reservoir Mixing
Authors: Garmeh Gholamreza , Johns Russell T.
Published: October 2009

Inaccurate modeling of reservoir mixing by using large grid blocks in compositional simulation can significantly affect recoveries in miscible gas floods and lead to inaccurate predictions of recovery performance. Reservoir mixing or dispersion is caused by diffusion of particles across streamlines; mixing can be significantly enhanced if the surface area of contact between the reservoir and injected fluid are increased as fluids propagate through the reservoir. A common way to convert geological models into simulation models is to upscale permeabilities based on reservoir heterogeneity. Upscaling affects the degree of mixing that is modeled, but the importance of reservoir mixing in upscaling is largely ignored. This paper shows how to estimate the level of mixing in a reservoir and how to incorporate mixing into the upscaling procedure.

We derive the key scaling groups for first-contact miscible (FCM) flow and show how they impact reservoir mixing. We examine only local mixing, not apparent mixing caused by variations in streamline path lengths (convective spreading). Local mixing is important because it affects the strength of the injected fluid, and can cause an otherwise multicontact miscible (MCM) flood to become immiscible. Over 800 2-D numerical simulations are carried out using experimental design to estimate dispersivity as a function of the derived scaling groups.

We show that reservoir mixing is enhanced owing to fluid propagation through heterogeneous media. Because mixing is dependent on heterogeneities, upscaling is an iterative process where the level of mixing in both the longitudinal and transverse directions must be matched from the fine to coarse scale. The most important groups that affect mixing are the mobility ratio, dispersion number, correlation lengths, and the Dykstra-Parson's coefficient. Large dispersion numbers yield greater dispersivities away from the injection well. We show through simulations of both FCM and multi-contact miscible (MCM) floods that grid-block size can be significantly increased when reservoir mixing is large. Heterogeneous reservoirs with large longitudinal correlation lengths can be upscaled to larger grid blocks than reservoirs with random permeability fields. This paper shows how to determine a priori the maximum grid-block size allowed in both the x- and z-directions to predict accurately the oil recovery from miscible gas floods.
Lessons Learned While Conducting Drilling and CO2 Injection Operations at the Victor J. Daniel Power Plant in Mississippi
Authors: Koperna George , Riestenberg David , Petrusak Robin , Esposito Richar , Rhudy Dick
Published: October 2009

This paper will discuss the lessons learned from a CO2 pilot injection in southeastern Mississippi, highlighting those issues that are unique to a first-of-its-kind pilot injection at a power plant as well as unexpected results from applying conventional oil and gas technology to tracking CO2 in the subsurface.

Southern Company's Mississippi Power Victor J Daniel, Jr. electric generating facility is hosting a USDOE sponsored CO2 sequestration demonstration as part of the Southeast Carbon Sequestration Regional Partnership. The primary goal of this demonstration is to provide the foundation for safe and secure storage of CO2 in a deep saline reservoir within the confines of a power plant's property boundary.

Major field operations included: (a) collection of baseline data for subsequent monitoring, verification and accounting (MVA); (b) preparing the drill site; (c) drilling and completing the CO2 injection and observation wells, (d) characterizing the reservoir using core analyses, (e) baseline geophysical well logging and seismic surveying operations, (f) injecting more than 3,000 tons of CO2, (g) post-injection time-lapse geophysical well logging and seismic surveying operations, and (h) site closure. During the execution of these operations, additional activities unique to operations on the plant property included: (a) site access agreements and restrictions, (b) site preparation, (c) site reclamation, (d) advanced notification of field activities, and (e) operational monitoring.

With regard to the application of conventional oil and gas protocols to a sequestration pilot, there were several unexpected results, including those obtained by geophysical logging, seismic surveys, and wellhead and bottomhole pressure data acquisition.
Determination of Petrophysical Parameters and Mud Filtrate Invasion Profile Using Joint Inversion of Induction Logging and Pressure Transient Measurements
Authors: Liang Lin , Abubakar Aria , Habashy Tarek
Published: October 2009

Induction logging technique is one of the important tools for determining the formation resistivity of the subsurface. The near-wellbore formation resistivity is usually affected by the invasion of water-based mud-filtrate. The flushed-zone resistivity (Rxo), the undisturbed-zone resistivity (Rt) and the diameter of invasion (Di) can be estimated from the interpretation of array induction logging measurements through a model-based inversion process. Conventionally, the inversion assumes a layer-cake formation with three-parameter invasion model or with a four-parameter invasion model that incorporates a ramped transition zone.

In this study, we introduce a 2.5D inversion approach for interpreting the induction logging data. The inversion is constrained by using a multiphase fluid-flow model which simulates the mud-filtrate invasion process and calculates the spatial distribution of the water saturation and salt concentration, which are in turn transformed into the formation conductivity using a resistivity-saturation formula. In this way, the inverted invasion profile is consistent with the fluid flow physics. Jointly with the pressure data, the inversion estimates a parametric one-dimensional distribution of permeability and porosity.

Previous works either assumed that the mud-cake permeability is known and used the bottom-hole pressure as a boundary condition, or alternatively used an invasion model to calculate the dynamic invasion rate as a boundary condition to the fluid-flow simulator at the wellbore sandface. The dynamic invasion process is complicated and is affected by many factors. Hence, although possible, it is difficult to calculate the invasion rate. This study shows that it is possible to directly invert the mud-filtrate invasion volume from the fluid-flow-constrained inversion of the induction logging data. Moreover, this approach is not limited by the traditional interpretation of the formation test, which is based on a single phase model without taking into account invasion. The joint inversion of the induction logging and pressure data demonstrates the ability to provide a more reliable interpretation of formation permeability. The advantage of the approach presented here, is its possible generalization to three-dimensional geometries, for example dipping beds and highly deviated wells.
The Chiswick Field: Long Horizontal Wells and Innovative Fracturing Solutions in a Low Permeability, Sandstone, Gas Reservoir in the North Sea
Authors: Coghlan G. , Holland B.
Published: October 2009

In order to obtain commercial flow rates from the Chiswick field, a low permeability gas reservoir in the UK Southern Gas Basin, it was apparent that field development needed horizontal wells with multiple, propped hydraulic fractures. While this completion strategy is commonplace in US onshore tight gas and a few North Sea chalk reservoirs, only a handful of such completions were attempted historically in the sandstone reservoirs of the North Sea. Ongoing success in chalk and in deep sandstone reservoirs onshore Germany raised expectations that, using modern practises and materials, the strategy could be successfully executed in the high cost environment of offshore UKCS.

Chiswick lies in 42m of water at the UK-Netherlands median line. Gas is located in alluvial channel sand systems of Carboniferous age. The reservoir is at 3300m TVDSS with average porosity of 10% and permeability 1 mD; initial pressure and temperature are 392 bara, 115°C respectively. Results from four appraisal wells, drilled 1984 -1999, determined that commercial rates would only be possible if development wells were horizontal and hydraulically fractured. The initial field development plan entailed two horizontal wells with 2km reservoir sections, stimulated with several massive propped fractures.

The complex reservoir is highly stratified with intermixed channel sands, coal and shale. Besides reservoir uncertainties, there were operational challenges to be overcome. A major hurdle was a constrained regional market for high-specification stimulation vessels for the Chiswick development programme. A solution was found by converting a large supply-vessel into a stimulation vessel with the installation of a large capacity, land-based frac-spread. It successfully delivered fourteen frac-jobs in three wells (two are described in this paper). Target post-stimulation flow-rates were achieved in all cases.

The paper discusses how a fundamental rethink of what was technically possible allowed a complex tight gas field in the North Sea, previously thought non-commercial, to be brought successfully onto production.
Predicting Dynamic Barite Sag in Newtonian Oil Based Drilling Fluids
Authors: Nguyen T. C. , Miska S. , Yu M. , Takach N.
Published: October 2009

Barite Sag is the settling of barite particles (or other weighting materials), which results in the undesirable fluctuations in drilling fluid density. A variety of major drilling problems including lost circulation, well control difficulties, poor cement jobs and stuck pipe can result from uncontrolled barite sag. Study of this phenomenon and how to mitigate its effects has long been of interest.

This paper describes a fundamental mathematical approach to analyze the settling of barite particles in shear flow of Newtonian fluids. A set of four coupled partial differential equations to describe dynamic barite sag in Newtonian fluids in pipe flow is obtained by applying mass and momentum conservation for solid and liquid phase. Solid concentration in axial and radial directions as a function of time is calculated by using an explicit numerical method to solve these equations. A number of experiments in a flow loop were conducted to verify the mathematical model.

A method proposed by Bern et. al.4,8 to measure the fluid density during circulation was modified to measure the change of circulating density in the test section. Two mass flow meters were installed at the inlet and outlet of the flow loop's test section. Differences in the density measurements over time were converted to the solid accumulation, which was compared with results from the modeling. In addition, based on the experimental results, three different stages of barite accumulation due to the settling and bed pickup of barite particles during circulation will be presented. The proposed methodology and results of this study will help drillers have a better understanding in terms of undesirable density fluctuations and barite bed characteristics.
The Art and Practice of Acid Placement and Diversion: History, Present State and Future
Authors: Kalfayan L. J. , Martin A. N.
Published: October 2009

With the increasing need for highly cost-effective well production enhancement applications, acid stimulation is becoming increasingly popular. To be successful, acidizing procedures require distribution of stimulation fluids across and within the desired treatment interval. Historically, this has been approached with mechanical placement or chemical diversion of treatment fluids. Method selection can be crucial to treatment success – and an increasing number of options exist – each with its own set of limitations and uncertainties. Preferences and success vary for matrix and fracture acidizing – in vertical and deviated wellbores, in sandstones and carbonates and in cased and perforated, gravel packed, and openhole completions. Method selection and implementation can be daunting but greatly rewarding – calling for creativity and field experimentation.

This paper focuses on the important role of acid placement and diversion, and the types, purposes, benefits and pitfalls of the methods currently in practice. The importance of treatment placement was evident and recognized in the earliest acid treatments conducted in the late 19th century. Although this need has been recognized since the dawn of acidizing, at no point in its history has a diversion method found universal reliability and acceptance. Insufficient interval coverage is perhaps still the most common reason why acid jobs often fail to meet expectations. A well-conceived treatment in all other aspects of design (damage assessment, selection of fluids and additives, and volumes) can count for nothing if the treatment does not enter or cover those portions of the interval with the greatest need of stimulation.

Since the first commercial acid treatments in the 1930s, mechanical placement has evolved from crude rubber "packers" to advanced coiled tubing technologies. Chemical and particulate diverters have evolved from chicken feed to specialized chemical systems, including self-diverting fluids. With chemical diversion, different methods have come into and fallen out of favor – replaced by new ideas, or those forgotten and subsequently revived.

Within its historical perspective, this paper discusses present-day acid placement and diversion methods, their best applications and their limitations – with a view and emphasis on industry needs and direction for the future.
Enhanced Natural Gas and Condensate Recovery by Injection of Pure SCCO2, Pure CH4 and Their Mixtures: Experimental Investigation
Authors: Al-Abri Abdullah , Sidiq Hiwa , Amin Robert
Published: October 2009

This paper quantitatively investigates the fractional condensate recovery and relative permeability following supercritical carbon dioxide (SCCO2) injection, methane injection and the injection of their mixtures; and compositionally-sensitive reservoir gas relative permeability following SCCO2 injection. A high pressure high temperature experimental laboratory was established to simulate reservoir conditions and to perform relative permeability measurements on sandstone cores. All tests were made at measured miscible conditions of 5900psi, 95-160°C and constant flow velocity inside the cores of 10cm/h. Two sequences of coreflooding experiments were employed to replicate the displacement of reservoir gas by pure SCCO2 injection, and the displacement of condensate by injection of different SCCO2-methane concentrations. This work is part of an integrated enhanced gas and condensate recovery project conducted for a local reservoir in Western Australia.

The results provide valuable insights into gas and condensate recovery following SCCO2 injection with various methane impurities. The results demonstrate that SCCO2 injection appears to offer less capillary instabilities and better mobility ratios resulting in a delayed breakthrough and favorable condensate sweep efficiency (79% recovery and 0.62 PV BT); as opposed to the injection of SCCO2-methane mixtures, or pure methane injection (45% recovery and 0.27 PV BT). Further, the relative permeability curves to condensate improve following SCCO2 injection due to decrease in condensate-to-gas viscosity ratio (curves cross at 58% gas saturation with SCCO2 injection compared to 24% gas saturation with methane injection). On the gas-gas side, experiments confirm that the greater the methane concentration in the reservoir gas (i.e. less CO2 contamination) the better relative permeability and sweep efficiency data become at the flooding temperatures and pressures (curves cross at 40% SCCO2 saturation when 90% methane is present in the reservoir compared to less than 5% SCCO2 saturation when only 25% methane is present in the porous medium).

These data will help the operators develop operational and design strategies for their current and future EOR projects, as well as to input parameters for full-field simulation practices.
Well Treatment Fluids Prepared with Oilfield Produced Water
Authors: Li Leiming , Eliseeva Ksenia , Eliseev Vasily , Bustos Oscar A. , England Kevin , Howard Paul R. , Boney Curtis L. , Parris Michael D. , Ali Syed A.
Published: October 2009

Oilfield produced water usually comprises both the formation water and injected fluids from prior treatments. Produced water may be environmentally hazardous and usually contains bacteria, hydrocarbons, and high levels of dissolved salts. As such, the proper disposal of produced water is often expensive. Meanwhile, fresh water used to formulate oilfield treatment fluids is becoming more costly and more difficult to obtain. Operators, as well as service companies, have therefore shown a strong desire to use produced water in field operations to reduce costs. Consequently, a series of laboratory experiments have been performed to optimize the viscosity profile of fracturing fluids prepared with produced water. Preparation of polysaccharide-based fracturing fluids with produced water frequently resulted in fluids with poor viscosity profiles despite the fact that the produced water was pretreated with biocide. Furthermore, the problem could not be resolved by just adding more biocide. In a number of representative cases, the guar-based fracturing fluids, prepared with produced water and regular biocide, quickly lost their viscosity after hydration, possibly because of the degradation of the guar by the bacterial enzymes in the produced water. A new fluid stabilizer was recently invented to address the problem, and it was observed that the addition of the stabilizer dramatically extended the lifetime of the polysaccharide-based fracturing fluids prepared with produced water.

The fluid stabilizer was simply added to produced water prior to mixing the polymer. The polysaccharide-based fluids prepared with the stabilizer-treated produced water showed stable viscosity profiles at both surface and bottomhole temperatures.

The use of the fluid stabilizer has greatly enhanced the fluid performance and job efficiency since its initial introduction in the field in June 2008 and was implemented in about 80 successful fracturing and sand control jobs by the end of 2008.

The invention and successful application of the fluid stabilizer have reduced the operating costs for the operators and service companies. At the same time, this new technology has also helped improve the environment by cutting the fresh water usage in the field. This paper will discuss the chemistry, experimental studies, and case histories.
Openhole Stability and Solids Production Simulation in Emerging Reservoir Shale Using Transversely Isotropic Thick Wall Cylinders
Authors: Hoang Son K. , Abousleiman Younane N. , Ewy Russell T.
Published: October 2009

Even with the emerging gas and oil shale plays, little laboratory data exists for the simulation of openhole completion and production accounting for the inherent anisotropy of shale. Contrary to the success of the thick wall cylinder test in simulating openhole production stability and/or solids production in sandstone and carbonate formations, the application and modeling of this test in shale, while subjecting the sample to in-situ openhole conditions, presents considerably greater complexity. Shale in general possesses anisotropic mechanical material properties that will alter the stress distribution around an open hole. Moreover, time-dependent pore pressure and permeability effects will modify the effective stresses and can cause delayed formation failure. In this study, the response of anisotropic hollow cylindrical shale samples under laboratory time-dependent loading, simulating near-wellbore production stresses, is investigated under the realm of coupled fluid and shale matrix interaction to address these challenging issues. Experimental results on thick wall cylinder testing of an anisotropic and low permeability shale were analyzed using the developed physical and mathematical model. The results showed that significant pore pressure could be generated and sustained in even small shale specimens (3.81 cm outer diameter and 1.27 cm inner diameter), depending on shale anisotropic properties, permeability, and loading rate, and cannot be ignored when the collapse strength from thick wall cylinder tests is interpreted for field conditions. Furthermore, commonly employed elasticity analyses for the thick wall cylinder test fail to account for the coupled fluid and shale matrix interaction under time-dependent loading condition and produce oversimplified and inaccurate results for not only the effective stress distribution but also failure analysis. The new modeling, therefore, will be essential for designing, simulating, and interpreting laboratory thick wall cylinder tests on shales as well as the subsequent modeling of sustainable gas and oil production from these formations.
Real Time Decision Support in Drilling Operations Using Bayesian Decision Networks
Authors: Rajaieyamchee Mohamad A. , Bratvold Reidar B.
Published: October 2009

Today's decision makers in the petroleum industry have access to remarkable new technologies, huge amounts of information to help them make high-quality decisions, and the ability to share information at unprecedented speeds and quantities. A central hypothesis in the concept of digital oil field is that these tools and resources should lead to better decisions. Yet, the tools bring with them daunting new problems: the available data, though massive, are uncertain and often incomplete, unreliable, or distributed; interoperating/distributed decision makers and decision-making devices need to be coordinated; and many sources of data need to be fused to yield a good decision.

In this paper, we shall illustrate the use of influence diagrams, also known as Bayesian Decision Networks, to frame, analyze, and support real-time drilling decisions. Influence diagrams provide compact graphical representational and computational frameworks that are based on rigorous probability theory. They consist of a framing part, which encodes the decision basis elements along with their interrelationships, and a probabilistic part, which uses conditional probability distributions to quantify the strengths of the relationships.

Following a systematic decision analytic framework, particularly the decision analysis cycle, we developed influence diagram models for drilling operational decision situations. Also, an object-oriented influence diagram is built and tested for a real world casing setting decision situation. The influence diagram models are updated with the arrival of new data to reflect the current state of knowledge about the decision situation.

The study shows that influence diagrams are well-suited and efficient decision analysis tools for real-time support of the large and complex drilling decisions in which uncertainty is predominant.
The Growing Importance of Petroleum Reserves Estimating and Auditing Standards
Authors: Harrell D. Ronald
Published: October 2009

The most recent version of the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" (the Standards) was approved by the SPE Board contemporaneously with the release of the March 2007 SPE/WPC/AAPG/SPEE Petroleum Resources Management System (PRMS). This represents the first significant revision of the Standards since their issuance by SPE in 1977. A few minor changes were made to the Standards in 2001 but only as necessary to achieve conformance with the 1997 SPE/WPC Reserves Definitions. The 2007 Standards incorporate revisions targeted to elevate the qualifications of evaluators and auditors along with clarifying several previously undefined terms and conditions. A copy can be obtained through www.spe.org.
Conditioning on Effective Permeabilities from Well Tests in Geostatistical Reservoir Characterization: Real Test Case Evaluation
Authors: Skorstad A. , Islam M. A. , Smørgrav E.
Published: October 2009

The effect of including permeabilities obtained from well tests in geomodeling of permeability and porosity fields is tested on real data from the Heidrun reservoir in the Norwegian Sea. Dynamic data are integrated into the reservoir description on a geologically detailed resolution by handling well log data and well test data in the same manner. The test shows that both the predictive power of the reservoir model in terms of history match and the local inflow probed by Production Logging Tool (PLT) data are improved.

Effective permeabilities derived from PLT data will hereon be denoted well test data. The conditioning method uses an inverse block co-kriging of both log and well test data, and a Fast Fourier Transform to speed up the calculations. Well log data and well test data are observations on different length scales. In order to condition geological models on an intermediate resolution, the data must be associated with an uncertainty. This uncertainty is estimated from the data.

The test is performed on the Ile formation of the Heidrun reservoir. Well log permeabilities and porosities from 26 wells are available in the studied area, and three wells also contain well test data. The mismatch between the responses from flow simulations of the geostatistical realizations and the real dynamic data is reduced compared to the flow simulations from a benchmark suite of geostatistical realization without the well test conditioning; obtaining an improved reservoir characterization. A detailed comparison of measured PLT data with the simulated well inflow of the three wells containing well test data shows that the local subzone inflow is significantly improved by accounting also for the well test data in the geostatistical reservoir characterization. The inflow match is improved in 83% of the investigated subzones. In particular, the largest improvement is found in the least permeable zone where the deviances from the true to the calculated inflow were on average only 17% of that from the benchmark case.

The paper presents a general methodology for including effective permeabilities from well tests when modeling petrophysical fields. Using real data, we demonstrate that the proposed methodology can be successfully used in direct conditioning of geological realizations. Thereby, both improved detailed geological models and better forecasting from coarser flow simulation models can be obtained.
Catenary Well Profiles for Extended and Ultra-Extended Reach Wells
Authors: Liu Xiushan , Samuel Robello
Published: October 2009

Extended-reach drilling (ERD) technology has rapidly developed during the past two decades and the drilling of ultraextended-reach (u-ERD) wells to extend their reach to greater depths requires improved models. Wellbore friction is an important issue for ultra-long wells, and optimizing the well path design is an effective means of reducing torque and drag.

This paper presents the dimensionless mathematical model and provides a new method for planning a catenary well profile. The new mathematical model of a catenary well path does not involve hyperbolic functions and uses an exact mathematical solution. The method of explicit solution avoids a trial-and-error procedure and provides excellent maneuverability of planning requirements.

Conversely, bit-walk is a natural tendency of the drill bit to drift sideways while drilling. To reduce azimuth correction frequencies and wellbore tortuosity, effective well path planning and design should account for bit-walk effects. This paper presents a newly developed a 3D mathematical model of the catenary well path and the method for planning bit-walk catenary paths to fit the bit-walk rate by a given rock layer. This paper analyzes the compositive relation of inclination units and azimuth units, provides a method to divide the catenary well profile into many shorter intervals for calculation, discusses the characteristics of planning bit-walk paths, and presents the constraint equations and solutions for ERD wells.

The results show that the essential elements of planning a 2D or 3D catenary profile include determining the position of the catenary section, parameters, such as starting and ending inclinations, and length of the succeeding hold-up section. The model and methods provided use an exact mathematical solution and results. The planned catenary well path completely fits the predetermined bit-walk rates and is absolutely smooth from the wellhead to the given target.
MEOR Success in Southern Saskatchewan
Authors: Town K. , Sheehy A. J. , Govreau B. R.
Published: October 2009

A Microbial Enhanced Oil Recovery (MEOR) Process was successfully applied in a mature waterflooded reservoir in Saskatchewan, Canada. A nutrient solution, which was designed specifically for this reservoir to stimulate certain indigenous microbes to grow, multiply and help to release oil was tested and piloted. A significant decrease in water cut and increase in oil production has been realized through the selective stimulation of bacteria using nutrient injection.

The field is a mature waterflood averaging over 95% water cut. To combat the increasing water cut issue an In-Situ Microbial Response Analysis (ISMRA) was performed on a typical high water cut producer in the area. The test well was treated with a nutrient solution and then shut-in for a number of days to allow specific indigenous microbes to grow and multiply. Upon return to production the well produced at an average of 200% more oil with a 10% decrease in water cut for a year. Pretreatment rates averaged 1.2 m3/day oil and post-ISMRA treatment daily production peaked at 4.1 m3/day oil.

As a result of the successful test, a pilot project was initiated and the nutrients were applied in three batch treatments on an injector with three offset production wells. Three weeks after the first batch treatment, a water cut decrease was seen at one of the offset producers. This well's oil production gradually increased from 1.4 to over 8 m3/day. Oil production in another producer doubled from 1.5 to over 3.0 m3/day. Subsequent treatments were tried on marginally economic wells and on a reactivated idle producer. The average decrease in water cut on these wells was over 10%. On the idle well oil production increased from 0.5 m3/day pre-treatment to an average of 3.0 m3/day post treatment.

Throughout the world there remains a huge target for EOR processes to target. This successful MEOR application will have tremendous impact on ultimate recovery in many of these reservoirs not only through an increase in production, but a decrease in operating costs through associated reduction in lifting costs with less water production.
WITSML "Comes of Age" for the Global Drilling & Completions Industry
Authors: Pickering J. G. , Kreijger J. , Grøvik L. O. , Franssens D. , Deeks N. R. , Doniger A. , Schey J.
Published: October 2009

The development of WITSML started in 2000 with the objective of building an XML standard for the transmission of wellsite data in a consistent form that would enable the integration of information from different suppliers. Energistics (formerly POSC) was involved from the outset and has provided independent hosting of the standard since early 2003. BP and Statoil were early sponsors and a Special Interest Group was formed. This has evolved steadily and today it includes representatives from all major energy and service companies.

Most energy companies have now either implemented WITSML technology for real-time and historical wellsite data transmission or are planning to do so in the near future. The number of WITSML compliant products is growing rapidly in response to this demand and increasingly WITSML is being specified as a contractual requirement, particularly at green field sites. The industry is approaching a position where the non-use of WITSML will be by exception.

This paper has two main areas of focus. The first is the technical delivery of the new version 1.4.0 WITSML release and the second is the business justification for the continued energy company uptake which is based on successful use cases. The paper is co-authored by members of the WITSML SIG and therefore contains detailed information from end users and suppliers with considerable working experience.

More than ever there are now compelling reasons to deploy WITSML. It is an enabler for data integration and smart tools and is the underlying technology behind many drilling collaboration centres. It is helping drilling operations globally to benefit from better access to engineering expertise at a time when the number of experts is declining and the complexity of operations is increasing.
Permeability Variations in an Upper Freeport Coal Core Due to Changes in Effective Stress and Sorption
Authors: Jikich Sinisha A. , McLendon T. Robert , Smith Duane H.
Published: October 2009

Permeability is a key property for injectivity of carbon dioxide in enhanced coalbed methane/carbon sequestration projects. In addition to cleat spacing and connectivity, permeability is affected by the in situ stresses, the geomechanical properties (Young's modulus, Poisson's ratio) of the coal, the amounts and compositions of the fluids (e.g., CH4, CO2) sorbed by the coal matrix, and the dependence of the matrix swelling on the amounts and compositions of the sorbed fluids.

In this paper, we have tested bituminous coal coal cores from the Upper Freeport formation, Marshall County, West Virginia in the Appalachian Basin. This coal has generated considerable interest, because of a current industry/DOE/NETL sponsored project to inject carbon dioxide into this seam for the purpose of developing and testing carbon sequestration.

The cores were tested in a composite core holder allowing hydrostatic confinement and X-ray computerized tomography (CT). Permeabilities for helium, methane, and carbon dioxide were measured using a conventional method of simultaneous pressure-drop and flow-rate measurements. Compressibility and carbon dioxide sorption of the sample were calculated from CT measurements of density variations in the core.

Permeability was reduced considerably by increases of effective stresses in the coal, and by sorption of carbon dioxide in the coal. Due to the heterogeneous nature of the coal, its sorption and elastic properties varied greatly among different locations within the core. As a corollary, samples from the same well and coal seam may show large variations in methane content, carbon dioxide storage capacity, permeability, and mechanical properties.
Unique String Tools Combine to Save Over USD 11 Million in Challenging Hole Opening Rotary-Steerable Applications
Authors: Barton Steve , Garcia Alexis , Luther Charles , Noriega Ivan , Cordova Adrian , Aguilar Rafael
Published: October 2009

The May field in Offshore Mexico is difficult to drill due to the presence of boulders and conglomerates within the top hole section. The interval is traditionally drilled with a conventional 18 1/2" bit and BHA. However, an enlarged hole is planned as contingency to provide an improved cement bond with the casing utilized. Due to casing drift, this requires the use of hole opening string tools to provide a final hole diameter of 21".

Prior hole opening runs have endured significant vibration and resultant mechanical damage to the tools and pilot bits. An offset well utilized commercial concentric hole opening tools that have cutter blocks that can be activated and retracted so that it can be pulled back through the casing. The hole opening section required a total of eight string reamer tools and three 18 1/2" pilot bits to reach TD.

A unique eccentric string reamer tool was selected that utilizes a mid-reamer section for improved string stabilization and hole enlargement. This was coupled with an eccentric vibration dampening tool, specifically positioned in the string to disturb damaging vibration harmonics. In order to refine parameter recommendations, Finite Element Analysis Software was utilized to model the harmonic behavior of the drill string. This assembly, combined with a point-the-bit rotary steerable tool drilled this challenging hole section in 9 days, delivering low vibrations and gauge hole. An estimated $4.4 M was saved compared to the original well plan and $11.5 million compared to the direct offset well for this interval.
Development and Application of a New Well Pattern Optimization Algorithm for Optimizing Large-Scale Field Development
Authors: Onwunalu J. E. , Durlofsky L. J.
Published: October 2009

The optimization of large-scale field development is challenging because the number of optimization variables can become excessive. A way to circumvent this difficulty is to constrain wells to exist within patterns and to then optimize parameters associated with the pattern type and geometry. In this paper, we introduce a general framework for accomplishing this type of optimization. The overall procedure, which we refer to as well pattern optimization (WPO), entails a new well pattern description (WPD) incorporated into an underlying optimization method. The WPD encodes potential solutions in terms of pattern types (e.g., five-spot, nine-spot) and pattern operators. The operators define geometric transformations (e.g., stretching, rotating) quantified by appropriate sets of parameters. It is the parameters that specify the well patterns and the pattern operators, along with additional variables that define the sequence of operations, that are optimized by WPO. The well pattern description developed here could be used with a variety of underlying optimization methods. Here we combine it with a particle swarm optimization (PSO) technique, as PSO methods have recently been shown to provide robust and efficient optimizations for well placement problems.

Detailed optimization results are presented for three different example cases using several variants of the WPO algorithm. In one case, multiple reservoir models are considered to account for geological uncertainty. For all examples, significant improvement in the objective function is observed as the algorithm proceeds, particularly at early iterations. A two-stage optimization procedure, in which the first-stage optimization considers multiple well pattern types while the second stage focuses on the most promising pattern, is applied and shown to be effective. Limited comparisons with results using standard well patterns of various sizes demonstrate that the net present values achieved by the WPO algorithm are considerably greater. Taken in total, the optimization results highlight the potential of the WPO procedure for use in practical field development.
Modeling Analysis of Sand-Screen Collapse Resistance Under Geotectonic Load
Authors: Fuh Giin-Fa , Morita Nobuo , Furui Kenji
Published: October 2009

The manufacturer's specifications of sand screen usually provide information such as base pipe collapse pressure, maximum tensile load, and bending strength. However, the problem is that a very heavy base pipe is thus required to satisfy such specifications if the pipe collapse pressure indicated by manufacturer is used for field application. The reason is that the screen collapse tests are conducted under hydrostatic loading for screens wrapped with rubber jacket by screen manufacturers. Observation of these tests shows that screen collapse occurs immediately after the base pipe starts yielding. However, this is not the case if screens are installed in the wellbore under geotectonic load. A series of laboratory tests are conducted using either straight pipes without screen or pipes with screen installed in a drilled borehole of some large rock sample. Since the base pipe failure is the dominant factor for screen failure, half of the experiments shown in this paper used straight pipe without including screen or shroud. These tests show that tubular strings may initiate yielding earlier than the specified yielding data provided by screen manufacturers. However, after the initial yielding, the base pipe deforms gradually and it never collapses even after exceeding the ordinary base pipe yielding (0.2-0.4% deformational strain) by more than 10 times.

Based on these laboratory tests, a numerical model is constructed for screen design along with gravel pack or standalone screen in openhole completions. The numerical model first simulates hydrostatic screen collapse tests conducted by manufacturers to confirm the design specifications as measured. Then, it is extended to simulate screen behavior after it is installed downhole. It assumes that a screen is placed in the borehole, and then gravel-pack covers the screen, followed by reservoir depletion and drawdown in production mode.

This paper sheds light on the sand screen collapse resistance under three typical loading types: hydrostatic, geotechtonic load without void around sand screen and geotectonic load with void for openhole standalone screen applications. Distinctly different failure scriteria are proposed for these three types of loadings. Empirical data undedr such high stress levels are rarely found in the literatures.
Digital Oilfield Projects: A Perspective Using Examples From Reservoir and Reserves Management
Authors: Lasrado Vineet
Published: October 2009

Digital Oilfield programs are underway in many oil and gas companies. The term ‘Digital Oilfield’ covers a wide range of areas from the usage of smart downhole sensors to the integration and transformation of data across technical and business applications for decision making in the oilfield. Ultimately the decisions made at the operational level affect the company's performance and hence Digital oilfield projects are connected with the decision making at different levels in the company.

This paper analyzes different types of digital oilfield projects from the literature and draws upon the authors experience to create a perspective based on the common requirements of such projects. Such a perspective should help reducing silos within organization often looking at their own data and work processes. Examples from the area of Real-time Reservoir management and Reserves management will be analyzed by going into the details of the common elements across these areas in terms of process and data requirements, data standards and components of the work processes. By understanding the common requirements organizations can lower cost in terms of reuse and deployment of the solutions across the company.

This paper will help engineers understanding of digital oilfield projects and assist in increasing the uptake of such projects within their organization.
Formation and Removal of Hydrates inside Wellhead Connectors
Authors: Akers T. J.
Published: October 2009

Natural gas hydrates have long plagued drilling operations in deepwater environments. Professional papers to date have focused on hydrate formation inside the wellbore. This paper discusses the problem of hydrates that form within the BOP-wellhead connector. A case history is presented of a blowout preventer (BOP) stack stuck on a subsea wellhead due to the formation of methane gas hydrates external to the wellbore but inside of the BOP-wellhead connector. Efforts to release the connector are discussed as well as the thermal modeling undertaken of the hydrate melting attempts. Alternative release methods considered during the event are given along with the final resolution to the event. A discussion of the effectiveness of both thermal and chemical methods of removing hydrates from inside the connector is presented along with expectations of strategy effectiveness. Providences to prevent and mitigate future occurrences of hydrated BOP connectors are offered.