bluuebunny/crossref_metadata_2025 huggingface dataset:
Stepping on Development of Small and Medium Size Oilfields through Horizontal Wells—The Way Ahead
Authors: Tewari R. D. , Malik M. , Naganathan S.
Published: December 2007

Maximization of recovery from anisotropic small and medium size oil fields is a daunting task for operators. Development strategies and concepts implemented in large fields generally are not appropriate for small and medium size fields. Inappropriate strategies and methodologies of exploitation affect the overall recoveries and economics of the project. This is further complicated in tight, viscous and sand incursion prone formations. This paper discusses about number of small fields located in Muglad basin wherein oil accumulation is found in multiple layers of late cretaceous deposits. The formations are heterogeneous, unconsolidated with higher viscosity and strong aquifer support. Some formations are tighter too. Field performance is marred by exponential rise of water cut due to adverse mobility and lifting through ESP. Production is affected due to poor influx in tighter formations through conventional wells. This behavior is limiting the producing life of existing wells, resulting into decline in production and causing significant bypassed and undrained oil.

Horizontal wells with state-of-art completion both in openhole and cased holed with suitable artificial lift techniques were considered as one of the IOR option for maximizing well productivity in these thinly bedded heavy oil field with objective for tapping the bypassed oil and delaying the water production while controlling the sand production.

This paper discusses about the challenges in planning and executing cycles of real time well site well placement, completion, perforation and artificial lift selection. Lessons learnt and results of the well placement along with cost/production analysis will be presented. Production results to date have been remarkable with productivity improvement factor varying 3-4 folds compared to vertical wells. The paper illustrates how integration of different disciplines with focused efforts led to successful well placement, sand and water management in heavy oil environment and also oil production from tight formations.
Study on High-Concentration Polymer Flooding To Further Enhance Oil Recovery
Authors: Fulin Yang , Demin Wang , Gang Wang , Xinguang Sui , Weijie Liu , Chunling Kan
Published: December 2007

Initially the field operator considered injection of high-concentration polymer to be high-risk and marginally economic. But the results of the core flood experiments show that an incremental recovery over water flooding of more than 20% OOIP (original oil in place) can be obtained by early time injection of high molecular weight, high concentration polymer solutions, and the earlier the better. The incremental recovery is comparable to surfactant flooding but at a lower cost.

A high concentration (concentration 1,500 ppm ~ 2,000 ppm, viscosity 400 mPa.S ~ 500 mPa.S) polymer flood pilot test has been started in May 2003. The pilot is located in the West Central area of Daqing Oil Field and consists of 9 injectors and 16 producers. Before high concentration polymer flooding, 0.247 pore volumes of low concentration (1,000 ppm, viscosity 44mPa.S~51 mPa.S) polymer solution had been injected and the water cut at the central area had reached its lowest point (65.5%). By the end of April 2006, the water cut at the central area was 78.9%. After injecting high concentration polymer solution, the rate of the water cut increase slowed down and then the water cut decreased from a maximum of 79.6% to a minimum of 73.1% (a decrease of 7.5%) again. The current recovery over that of water flooding at the central area is already 16.7% OOIP.According to numerical simulation, when the water cut reaches 98%, 19.8%~22.9% OOIP incremental recovery over that of water flooding will be attained.

6 dispersed wells located in the West Central area of Daqing Oil Field started to inject a higher concentration of polymer fluid also rein March and August, respectively. The 6 wells were first injected by low concentration polymer and then increased the concentration of the injected polymer solution from 1,000ppm to 1,300ppm. At present, good results have been obtained.

Another pilot is located in the northwest of Daqing Oil Field and consists of 39 injectors and 44 producers. The pilot increased the concentration of the injected polymer solution from 1,250ppm to 1,800 and the molecular weight of polymer from 25×106 to 35×106. According to numerical simulation, when the water cut reaches 98%, 19.4OOIP incremental recovery over that of water flooding will be attained.

The above results show that this technology can enhance oil recovery economically.
A Synergy of New Technologies Successfully Overcomes Openhole Horizontal Completion Problems in Malaysia
Authors: King Kim , Terwogt Jan H. , YeeChoy Chen , Azer Alfred
Published: December 2007

Sarawak Shell Bhd operates the Shallow Clastics field, which targets two shallow gas-bearing reservoirs, H1 and H2. An early appraisal well had been drilled deviated, and 9-5/8-in. casing was used. A commingled upper completion and a sand-face completion using large-OD expandable sand screens through both targets was used. Upon completion, the well was cleaned up through a temporary well clean-up and test facility. The purpose of the well was to test productivity and evaluate the integrity of the downhole sand-exclusion installation. Fines production, possibly due to the failure of the sand exclusion method, steadily increased to the extent that the well was deemed unproducible to the facilities.

Due to the high fines produced from this first well, a re-evaluation of the sand exclusion method was undertaken before development of the remaining field. The re-evaluation included more extensive core analysis and reviews of the types of sand-face completions suitable for development of the H1/H2 reservoirs. This evaluation enabled the operator and a service/engineering company to develop an innovative sand-exclusion method that combined several new technologies.

This paper discusses the evaluation and the four wells that have been completed to date with this new sand-exclusion method and the well configuration to address the completion needs. The field implementation of the design, key success factors and results will also be summarized.
Ultralow Invasion Drilling Fluids: A Practical Route to Reduced Wellbore Instability, Reduced Mud Losses, Wellbore Strengthening, and Improved Well Productivity
Authors: Reid P. , Santos H.
Published: December 2007

Reducing the invasion of drilling, completion and workover fluids to as low a level as possible will alleviate many problems of mechanically unstable formations, differential sticking and lost circulation. A properly formulated ultra-low invasion fluid (ULIF) will also reduce formation damage and thereby often increase well productivity. In addition, certain classes of ULIF will provide wellbore strengthening.

This paper describes the technology used to produce a class of ULIF and will review the benefits that limiting fluid and pressure invasion of fluid brings to rock integrity, drilling performance and well productivity. The ULIF additives described are biodegradable, environmentally acceptable and can be used in water based, oil based and synthetic based fluids. They are easy to add to any mud system and the ultra-low invasion properties of the fluids are measured and maintained in the field by using a simple sand bed invasion test.

The paper focuses mainly on case histories from several regions of the world where ULIFs have been used. In North, Central and South America alone, over 120 wells have used the ULIF additives in the past 3 years. The products have also been used in India, the Middle East, Europe, Africa and the Far East. Log data are presented that clearly demonstrate the ability of a ULIF to reduce wellbore instability and fluid invasion. Evidence of wellbore strengthening is also presented along with several cases where well productivity has been increased. In addition to showing the enhanced technical performance obtained with ULIFs, we also demonstrate the economic benefits of using these fluids.

The same technology used to formulate Ultra-low Invasion Drilling Fluids can also be used very successfully – sometimes with modification – in completion fluids, workover fluids and cementing operations to reduce or eliminate the same problems.
Evaluation of Acid Treatment Results for Water-Injector Wells in Saudi Arabia
Authors: Al-Harbi M. S. , Al-Dhafeeri A. M. , Al-Rufaie Y. A. , Mohammed S. K.
Published: December 2007

Several acid treatments were conducted in the Ghawar filed to increase the well injectivity and to support the reservoir pressure in this area. Vertical and horizontal wells with an open hole completion in a carbonate reservoir were selected to be a candidate for post acid treatments evaluation study. These wells were stimulated using hydrochloric and emulsified acid with foamed viscoelastic-based water. Viscoelastic-based water system was used to enhance the diversion mechanism and the lifting process for the spent acid following the treatment.

In this paper new correlations for acid treatment design were obtained from an extensive study of several case histories that can be used for optimizing future acid treatments design in the Ghawar field. This study was mainly utilized the results from the post acid treatment jobs in terms of HCl acid, emulsified acid and viscoelastic volume correlated with the well's injectivity. Based on the study results, there is a strong relationship between the emulsified acid volumes with the injectivity index for the selected wells.
Reservoir Crude-Oil Viscosity Estimation from Wireline NMR Measurements—Rajasthan, India
Authors: Zittel R. J. , Beliveau D. , O'Sullivan T. , Mohanty R. , Miles J.
Published: December 2007

In 2004, the Mangala, Aishwariya, and Bhagyam fields were discovered in Rajasthan, India. Oil viscosity is a main factor controlling performance from these high-permeability paraffinic reservoirs. PVT data show areal and vertical variations in crude properties. Meter-by-meter geochemical core data corroborates vertical variations in oil composition. Continuous wireline measurements of nuclear magnetic resonance (NMR) properties and station NMR properties from wells drilled with both water- based (WBM) and synthetic oil-based muds (OBM) were also used to calculate a viscosity profile. This paper correlates results from all techniques, and shows how NMR measurements can provide oil viscosity profiles in compositionally-complex pools.

Black oil PVT samples typically test several meters of reservoir, while Rajasthan geochemical data is available at meter-scale. NMR logs provide continuous data, and calibrated to PVT and geochemistry, can provide the most detailed picture of in situ viscosity variations.

Results were used to construct a detailed spatial description of the reservoir's in situ oil viscosity. The NMR data helped define a zone of biodegraded oil up to ~25 meters thick above the oil- water contact (OWC), and showed thin accumulations of higher- viscosity oil on top of minor shale layers within oil columns. The major conclusion is that detailed in situ oil viscosity profiles can be developed from conventional wireline T2 measurements.

Techniques presented allow quick and accurate calculation of oil viscosity profiles from wireline logs, and can reduce the need for time-consuming detailed geochemical measurements. Results directly impacted the static and dynamic modelling of the Rajasthan fields and proposed waterflood designs (different for each field). Procedures described are generally applicable to reservoirs with similar datasets. Finally, the wealth of data presented allows a detailed examination of the viability of several approaches advocated for estimating in situ oil viscosity from wireline NMR measurements.
Results of the World's First 4D Microgravity Surveillance of a Waterflood—Prudhoe Bay, Alaska
Authors: Brady J. L. , Hare J. L. , Ferguson J. F. , Seibert J. E. , Klopping F. J. , Chen T. , Niebauer T.
Published: December 2007

The world's first 4-D surface gravity surveillance of a waterflood has been implemented at Prudhoe Bay, Alaska. This monitoring technique is an essential component of the surveillance program for the Gas Cap Water Injection Project (GCWI). A major factor in the approval process for the waterflood was to show that we could economically monitor water movement where a very limited number of wells penetrated the waterflood area. The drilling of numerous surveilence wells to adequately monitor water movement would have been cost prohibitive. Field surveys now conclusively show that density changes associated with water replacing gas are being readily detected using high-resolution surface gravity measurements. The gravity methods used to monitor the waterflood include time-lapse (4-D) measurement of surver the reservoir followed by inversion of the 4-D signal for mass balance and flood front detection.

This paper will focus on field results of time-lapse surface gravity surveys. Differences in the gravity field over time reflect changes in the reservoir fluid densities. The inversion procedure was formulated and coded to allow for various constraints on model parameters such as density, total mass, and moment of inertia. The gravity survey was designed to permit the inversion for reservoir mass distribution with resolution on the order of hundreds of meters in the presence of uncorrelated noise of reasonable magnitude (12 µGal standard deviation).

Time differenced gravity survey results clearly show an increase in surface gravity that is a result of the injected water mass. Density-change maps deduced from measured gravity- change show that water movement is reasonably similar to the reservoir simulations and the water detected in observation wells. The overall ultimate gravity signal is predicted to increase to approximately 250 µGal ultimately resulting in accurate maps of the water movement.
Multi-Objective Decision Making: A Critical Analysis of the Applicability of Renewable Energy Technologies
Authors: Rudduck N. , Khurana A. , Congreve M. , Lourens J.
Published: December 2007

This paper provides a demonstration of the Multi-Objective Decision Making (MODM) technique to assist complex decision-making through a study of renewable energies currently available and their applicability for implementation by an Australian E&P Company Santos whose current gas operations are primarily located in Central Australia.

In the case of renewable energy technologies and their future commercialisation, it is important to note that for planning and decision-making, simple cost minimization is insufficient to fully describe their commercial potential. Thus, a technique such as MODM is required to consider all the decision parameters, some of them being unquantifiable, such as corporate reputation, in order to make unbiased and forward thinking decisions.

The paper outlines the MODM methodology for deciding between defined alternatives taking account of multiple decision criteria. By expressing the problem in a table the analyst can phrase the problem in a way that enables systematic handling of large amounts of information and conflicting points of view. By studying the company's own set of priorities (value structure) a list of the decision criteria was developed. By ranking the renewable energies against these decision criteria the most applicable technologies for Santos were found to be Photo Voltaic Cells, and Parabolic Dishes.

This study highlights how MODM can be easily modified to accommodate different types of alternatives as demonstrated by providing the flexibility to compare Geo Sequestration along with renewable energies. This comparison was relevant because the company's motivation in reviewing renewable energy was to investigate technologies with the potential to add value to the Cooper Basin business. Other key findings that surfaced during the analysis were: clear definition of project scope is critical and results are very dependant on the validity of input data not easily quantified. The result of not adequately defining the scope was that insufficient time was available to spend investigating the pitfalls and fully accounting for dependencies or bias. Most importantly, active involvement of the company personnel from a wide variety of functions relevant to the decision is critical.

The conclusions in this paper are based on the outcome of the analysis described herein undertaken as part of the research project and do not necessarily reflect the views of Santos.
Theory and Application of Buoyancy in Wells
Authors: Aadnoy B. S. , Kaarstad E.
Published: December 2007

The paper presents a generalized buoyancy model for application in wells, called the generalized law of Archemedes.

There exist confusion in the oil industry about buoyancy effects as related to the force-area method (also known as piston force) or the principle of Archimedes, the stability force in buckling and axial forces during well intervention operations. This paper will present a general model called the generalized law of Archimedes, which is valid for all cases.

The paper also presents examples of application to ordinary drilling operations, deviated wells and different fluid densities inside and outside the pipe. For well intervention scenarios, the effects of wellhead shut-in pressures on buoyancy are demonstrated. This simple model, not requiring use of a "stability force", can also analyze buckling.

Using the generalized law of Archimedes, a correct assessment of the real axial load of the pipe is obtained, a critical factor for tubular work in petroleum wells. The model is also significant as it is simple and can be applied to all well operations.
Extreme Multistage Fracturing Improves Vertical Coverage and Well Performance in the Lost Hills Field
Authors: Hejl K. A. , Madding A. M. , Morea M. F. , Glatz C. W. , Luna J. , Minner W. A. , Singh T. , Stanley G. R.
Published: December 2007

In an attempt to improve production response, fracturing designs in the Lost Hills field went from a standard 3 to 6 stage design to an extreme 15 to 18 stage design to stimulate approximately 1000' of net pay. The previous standard designs were becoming borderline economic and if development was to continue then either production response had to improve or costs had to be reduced. Previous emphasis was placed on reducing fracture treatment costs by pumping fewer stages and lower proppant volumes, but the cumulative production response decreased as a result. Previous tests using an increased number of fracture stages did not improve economics because of the increased fracturing costs and minimal production increases. When a new coiled tubing fracturing technique was implemented to perform multi-stage jobs at reduced costs and the stage count per well was increased, production response and economics improved. This paper will discuss the differences in job execution, analysis of vertical fracture coverage using surface and downhole tiltmeter data, and cumulative production response from the different designs tested. Both treatment and stage design with this fracturing technique are being further refined as performance and statistical analysis of previous design changes is completed.
Novel Cement Composition for Completion of Thermal Recovery (ISC) Wellbores
Authors: Suyan K. M. , Dasgupta D. , Garg S. P. , Jain V. K.
Published: December 2007

This paper presents a new process for development of a novel cementing composition to provide ductility and thermal stability to the cement sheath in thermal recovery wells subjected to high temperature cycling during ISC process. In this novel composition a carbon-containing natural mineral fiber and an aluminum silicate additive are introduced along with Portland cement to perform effectively in wellbores having conditions prone to stress-induced cement failure.

ONGC's heavy crude oil-fields in north Gujarat, India necessitate the inroduction of thermal recovery process for improving the oil recovery. However the durability of the cement sheath consisting of API Class G cement admixed with silica is endangering the success of EOR process. The developed composition with carbon-containing natural mineral fiber (graphite) and an aluminum silicate additive (metakaolin) because of its durability at high temperature thermal cycling (<4500C) and compatibality with of Portland cement is an ideal composition for application in thermal recovery wells. The formulated thermally stable cement slurry with graphite and metakaolin has no significant effect on compressive strength and liquid permeability at high temperature thermal cycling (<4500C), thereby making it suitable for placement against combustion zone.

The field evaluation of this cement system in ISC wells of Balol & Santhal fields of ONGC in Mehsana asset is under-way. The developed novel cement system will solve the problem of charging of the subsurface shallow layers because of cement sheath failured during the in-situ combustion process.
Determining Cutting Transport Parameter in a Horizontal Coiled Tubing Underbalanced Drilling Operation
Authors: Gunawan Indra , Rubiandini Rudi
Published: December 2007

Underbalanced drilling is a drilling method that designs the hydrodynamic pressure to be lower than the formation pressure. At this condition, the formation's fluid flows to the well and circulated to the surface. This will surely affect the fluids properties at the annulus.

Fluids physical properties at the annulus are not easy to determine. This is because of fluids physical properties depend on hydrodynamic pressure and fluids composition, while the hydrodynamic pressure also depending on fluids physical properties. The composition of annulus fluids also affected by the influx rate that depends on the hydrodynamic pressure. Therefore, everything is connected to each other, and that's make the cutting transport parameter calculation become complicated. To solve this problem, we must make iteration between pressure, fluids physical properties, and the influx rate until we can find the correct value.

In this study, underbalanced flow modeling uses foam, emulsion, oil base mud as drilling fluid system and aerated mud with three kinds of influx, oil, water, and gas. Combinations of drilling fluids and influxes make a various result in cutting transport parameter and hydrostatic pressure.

This paper discusses the determination of hydrodynamic pressure in a horizontal coiled tubing underbalanced drilling operation, the determination of mixture fluids physical properties, and the determination of cutting transport parameter. This paper also discusses the effect of few other factors, such as coiled tubing size, hole size, drilling fluids and influx fluids to cutting transport parameters.
New Strategy for Seismic Facies Upscaling to the Reservoir Grid Scale
Authors: Duplantier O. , Hadj-Kacem N. , Vittori J.
Published: December 2007

We here present a new strategy for seismic facies upscaling to the reservoir grid. This methodology has been developed on the deep offshore Angola Girassol field data. Based on seismic attributes, it directly assigns facies associations and petrophysical properties to the reservoir model. The new strategy divided in two steps proposes to be more consistent with the petrophysical data and to ensure a better geological facies organization and a better facies continuity than classical upscaling approaches.

Step 1. Litho-seismic petrophysical properties, the dominant seismic facies and seismic facies probabilities are predicted. This creation is based on interpreted upscaled stratilogs (Facies Groups) and calibrated on all available petrophysical attributes.

Step 2. Seismic facies probabilities are upscaled from the seismic scale to the reservoir one. This upscaling is constrained by the dominant seismic facies and/or constrained by pseudo-petrophysical seismic cubes (Vclay, Porosity). Reservoir connectivity, geological organization and fine sandy channel definition are better preserved by this optimized upscaling than with a standard arithmetic average.

This new strategy, based on seismic attributes, allows a combined detection of geological facies organization and small scale internal heterogeneities as well as their preservation during the upscaling phase. It provides more suitable data for quantitative estimation of the uncertainties related to the reservoir properties.
Study on Flow Behaviors of Viscoelastic Polymer Solution in Micropore With Dead End
Authors: Yin Hongjun , Wang Demin , Zhong Huiying
Published: December 2007

The Upper-Convected Maxwell (UCM) model has been normally used to describe the rheological properties of polymer solutions. However, this model considers only viscosity and elasticity of a fluid without including the non-Newtonian power law behavior, a very important property to polymer solutions in reservoirs. Therefore, we present a Modified Upper-Convected Maxwell (MUCM) in this paper to take into account this property.

The steady flow mathematical model of MUCM fluids is established. The flow characteristics of viscoelastic fluids in the dead ends of porous pores in reservoirs are simulated numerically. The contours of velocity and stream function are drawn and micro-scale sweep efficiency is calculated quantitatively. The various regularities, corresponding to the change in visco-elastic properties of the fluid, are studied.

Numerical results show the visco-elasticity of polymer solutions is the main factor influencing sweep efficiency. With increasing elasticity, the flowing area in the dead end of pores is enlarged significantly, thus the area with immobile zones becomes smaller. Flow velocity is much larger than that for a Newtonian fluid, the sweep area and displacement efficiency increase as the elasticity increases. The visco-elastic nature of the displacing polymer fluids can in general improve the displacement efficiency in pores compared to using Newtonian fluids. This conclusion should be useful in selecting polymer fluids and designing polymer flooding operations.
Wellbore Cleanup Best Practices: A North Sea Operator's Experience
Authors: Fleming A. J. A. , Appleby R. R.
Published: December 2007

Wellbore clean up is a critical component of any new well construction. Failure to adequately clean the wellbore can cause major difficulties in running the completion resulting in large amounts of NPT with all the associated costs. Conversely, performing over-complicated clean ups to ensure success adds additional risks and unnecessary extra cost.

This paper examines an operator's experience with wellbore clean ups over a wide range of assets in the UK and Norwegian sectors of the North Sea. The operator wished to reduce the time taken by developing best practice guidelines. This would provide a common approach to wellbore clean up operations over all assets.

Using reports from 19 offshore wells completed between 2002 and 2004, the time taken during clean up operations was split between nine categories: ➢Running Tools➢Chemical Clean up / Displacement➢Pit Cleaning➢Waiting on Equipment➢Waiting on Weather➢Pressure Testing➢Non clean up Ops➢Safety Events➢Waiting on Permits

This allowed the causes of extended time to be identified and pinpointed the areas where most time could potentially be saved. Some of these were: ➢Clean up tool failures➢Over-complicated tool-strings➢Becoming stuck due to over ambitious toolstrings➢Rig equipment failures➢Incomplete tools being sent offshore➢Repeating of chemical clean up due to wellbore filters being full of mud/debris➢Delays while waiting for pit cleaning to be completed➢Lessons not being learned from other assets

These and other causes were further examined and discussed by operator staff in a workshop and vendor interviews. Guidelines were then developed by combining existing good practices from different assets and other industry experience.
Ultradeepwater Cementing: Challenges and Solutions
Authors: Mishra P. K.
Published: December 2007

Ultra Deep water drilling operation under Sagar Samriddhi Project started with two charted hire rigs Belford dolphin and Discoverer Seven Seas from Nov. 03. Since the commissioning of two rigs, total no. of 24 wells have been completed. This paper discusses real challenges faced during cementation of critical surface casing as well as liner and production casing. The maximum operating water depth was 3008 mt. Shallow water hazards like shallow water and gas flow also encountered during drilling of top hole sections. The lowest sea bed temp. Of 2 °C encountered in no. of wells. The narrow margin of pore and fracture. Pressure window necessitated the requirement of cement slurry of wt. not more than 11 ppg in many wells. The requirement of 5oo psi compressive strength of light wt. slurry within 24 hrs. time span at 15/20 ° C was one of the main challenges. All the above challenges were resolved using Schlumberger's PSD system combined with low temp. Gas Migration control additive, used for the first time in India. Proper cementing of liner more than 1500mts. Length with slurry wt. of 12.2 ppg was the biggest challenge faced during planning. Also the big temp. difference between the liner shoe and hanger top further aggravated the problem. However, the problems were solved using PSD system with proper Gas Migration control additive packages. Reduction of ECD during 7" liner cementation of well having high temp., was dealt effectively using high temp. Gas Migration control additive in well K1 X, the deepest well drilled in Indian Offshore. Production casing in four wells, having very narrow window of pore and fracture. pressure, perfect isolation was achieved using PSD system and proper Gas Migration control additive system.
Production Data Analysis—Challenges, Pitfalls, Diagnostics
Authors: Anderson D. M. , Stotts G. W. J. , Mattar L. , Ilk D. , Blasingame T. A.
Published: December 2007

Although production analysis (PA) for reservoir characterization is approaching the popularity of pressure transient analysis (PTA), there are few consistent diagnostic methods in practice for the analysis of production data. Many of the "diagnostic" methods for production data analysis are little more than observation-based approaches — and some are essentially "rules of thumb."

In this work we provide guidelines for the analysis of production data, as well as identify common pitfalls and challenges. Although pressure transient and production data analyses have the same governing theory (and solutions), we must recognize that pressure transient data are acquired as part of a controlled "experiment," performed as a specific event [e.g., a pressure buildup (or PBU) test]. In contrast, production data are generally considered to be surveillance/monitoring data — with little control and considerable variance occurring during the acquisition of the production data.

This paper attempts to provide a "state-of-the-technology" review of current production data analysis techniques/tools — particularly tools to diagnose the reservoir model and assess the reservoir condition. This work also identifies the challenges and pitfalls of production analysis — and we try to provide guidance towards best practices and best tools. To compliment this mission, we use relevant field examples to address specific issues, and we illustrate the value and function of production data analysis for a wide range of reservoir types and properties.
Modeling of Pig Operations in Natural Gas and Liquid Pipeline
Authors: Esmaeilzadeh F. , Mowla D. , Asemani M.
Published: December 2007

The use of pigs has become a standard industry procedure. This expanding demand has driven manufactures to produce a great variety of pig models. Most of the available knowledge is based on field experience. Hence, selecting the best pig, estimating its speed and required driving pressure, often involves some guesswork and consequently, a high degree of uncertainty. The pig is most effective when it runs at a near constant speed but will not be effective when it runs at too high speed. The typical speeds for pigging are about 1-5 m/s for on stream liquids and 2-7 m/s for on-stream gas (Cordell and Vanzout 1999).

In this work, the pig motion is modeled using Continuity, Momentum, Energy and State equations. These equations simultaneously are solved under unsteady state condition to obtain the pressure; pig velocity profile and the time that pig reaches at the end of the pipeline.

This information can help the operator to control speed of pig before the pig reaches the end of pipelines. The change area and elevation profile has been investigated.

The results are obtained for gas and liquid pipelines. The programs have been run for various values of time step and distance increment. The results are more accurate when time step and distance increment are getting smaller according to CFL (Courant-Friedrich-Lewy) condition
Natural Gas: Overcoming Limitations Toward Energy Supremacy
Authors: Harrison M. C. , Campbell P. , Coelho F. M. , Grecco C. , Ikeocha C. , Wang X. T. , Economides M. J.
Published: December 2007

The World, headed by North America, is shifting its energy focus towards natural gas for power generation as a substitute for coal and oil. Nuclear, which could be the obvious recourse, at least for now, seems to be losing to natural gas. Eventually, the "holy grail" of natural gas use must be its major contribution as a transportation fuel, not necessarily directly as compressed natural gas for engine combustion but indirectly, providing the necessary electricity in electrified transportation.

One of the clear advantages is that natural gas burns more cleanly and efficiently than other fossil fuels. Worldwide supplies are plentiful and diverse but with an imposing presence of Russia which houses the lion's share in proven reserves. Transportation has always been the issue and once recent major activities come to fruition (such as liquid natural gas, LNG) prices will be kept reasonable for decades. In the past few years, countries with traditionally modest gas reserves suddenly started declaring huge proven reserves to attract private investment. With the uncertainty associated with some of these claims it has become worthwhile to review all natural gas sources and the factors that will affect the supply, price and developments for the next 20 years. During the autumn and Winter of 2005-2006, the price of natural gas was driven to an unprecedented high (over $16/MMBtu) and had it not been for uncharacteristically mild winter in the United States the price would have escalated even higher. Emerging or speculated consumption by China and India, the always large U.S. energy appetite, along with maturing U.S. domestic production are the primary reasons for this predicament. The four-year run-up in natural gas prices is actually normal behavior for an economic or energy transitional period. However, serious energy-shortages loom on the horizon impacting more than just the price of a single commodity. Regulatory policies, ‘concerned’ environmental groups, and industrial inaction create choke points in the supply chain. Such manmade barriers, no matter how well intentioned, will needlessly generate energy woes and hardship for millions of consumers in the near future.

However, we are very bullish on natural gas and predict that it will emerge as the premier fuel for the world economy and we believe that supply, transportation and utilization challenges will be overcome by the industry and the consuming world.
Barnett Shale Hybrid Fracs—One Operator's Design, Application, and Results
Authors: Coulter G. R. , Gross B. C. , Benton E. G. , Thomson C. L.
Published: December 2007

The Ft Worth Basin Barnett Shale gas play has extended significantly from what was originally considered the ‘core’ area. The extension has taken activity South and West of Ft Worth, TX into Parker, Hill, Johnson, and other Counties. Operators in these areas have been using a number of different Barnett frac approaches. This paper discusses the Chief Oil and Gas, LLC (Chief) approach in these and the core areas. Based on work Chief published in 2004 (SPE 90891)1 it was shown that larger quantities of sand in Barnett fracs were beneficial. Continuing with this focus, studies were conducted in the core area with Hybrid Fracs. There have been numerous publications in the literature regarding Hybrid Fracs with no standard definition, other than some combination of slick water and gel stages with varying quantities of proppant. For the work reported here, we are defining our Hybrid designs based upon how the viscous gel is used. Some of the more recent Hybrid frac publications are referenced here2, 3, 4.

Chief has employed viscous gel slugs in Barnett Shale fracs in various designs. The C-Hybrid Frac design approach came from a three well study where we evaluated placing large quantities of sand using viscous gel slugs in one well (C-Hybrid Frac), a large quantity of slick water to place our ‘normal’ quantity of sand and the third well fraced with a ‘standard’ Chief slick water frac. The three well study was carried out on vertical Barnett wells in Tarrant County. Based on the results, one additional vertical Barnett well was fraced using the C-Hybrid Frac design. The results were sufficiently successful that the Hybrid Frac design was employed on horizontal wells in Parker, Hill, and Tarrant Counties of Texas. The design, application and results of this work are presented in the paper. Other applications of viscous gels in Hybrid type designs are also presented.
Forecasting Future U.S. Energy Needs
Authors: Skov A. M.
Published: December 2007

A reliable long range forecast of US energy demand would seem to be important for meaningful planning by government, industry, and academia. Yet actual forecasts are generally either short-term or poorly match long-term history or both. This paper describes a simple function that fits historical US data through many turbulent economic times from 1929 through 2002 with a correlation coefficient of 0.99. Population and real US Gross Domestic Product (GDP) are the only independent variables needed.

Some counterintuitive conclusions emerge. For example, price of oil is not a component of the history matching function. High prices have an offsetting negative impact on both energy demand and GDP. Hence, artificially increasing energy prices with a large consumption tax to reduce demand is a bad idea. Historically, high prices have jacked up inflation, too, which impacts real GDP and mitigates historical price effects. Inflation jumped four-fold with the high prices in the 70's and 80's.

During the 74-year period of history match, US energy demand grew fourfold, population more than doubled, and real GDP grew 12-fold. Oil and gas use rose from 18% of total commercial energy to 63%, and coal declined from 78% to only 23%, changes of staggering magnitude.

Use of this forecasting relationship for long-term projections of US energy demand also yields surprising results. For assumed long term real economic growth rates of one or three percent (the historical average), and generally accepted estimates of future US population growth, forecast energy demand, in the year 2100, are 52 quads and 366 quads, respectively, or either half, or four times, today's use, an astonishing range of outcomes for such a seemingly small difference in US economic growth rate. This suggests remarkable sensitivity of energy consumption to economic growth rate.

Other current and historical energy forecast methods and results, and possible applications to other economic entities, are also discussed and analyzed.
From Straight Lines to Deconvolution: The Evolution of the State of the Art in Well Test Analysis
Authors: Gringarten A. C.
Published: December 2007

Well test analysis has been used for many years to assess well condition and obtain reservoir parameters. Early interpretation methods (using straight-lines or log-log pressure plots) were limited to the estimation of well performance. With the introduction of pressure derivative analysis in 1983 and the development of complex interpretation models that are able to account for detailed geological features, well test analysis has become a very powerful tool for reservoir characterization. A new milestone has been reached recently with the introduction of deconvolution. Deconvolution is a process which converts pressure data at variable rate into a single drawdown at constant rate, thus making more data available for interpretation than in the original data set, where only periods at constant rate can be analyzed. Consequently, it is possible to see boundaries in deconvolved data, a considerable advantage compared to conventional analysis, where boundaries are often not seen and must be inferred. This has a significant impact on the ability to certify reserves.

The paper reviews the evolution of analysis techniques over the last half-century and shows how improvements have come in a series of step changes twenty years apart. Each one has increased the ability to discriminate between potential interpretation models and to verify the consistency of the analysis. This has increasing drastically the amount of information that can be extracted from well test data and more importantly, the confidence in that information.
Quantifying Resources for the Surmont Lease with 2D Mapping and Multivariate Statistics
Authors: Ren W. , Deutsch C. V. , Garner D. , Wheeler T. J. , Richy J.-F. , Mus E.
Published: December 2007

The McMurray formation consists of heterogeneous Cretaceous bitumen-saturated sands. The reservoirs are thick and laterally extensive in the main fairways. Many commercial projects are in the early stages of development. Resources too deep to mine are considering Steam Assisted Gravity Drainage (SAGD). Detailed high resolution 3-D geostatistical modeling is useful for individual well pair or pad flow simulation, but is neither practical nor necessary for resource assessment over large areas.

This paper presents a practical and tested methodology for resource assessment in the Surmont Lease. The uncertainty in over 30 correlated variables is calculated on a dense 2-D grid using all available information including wells, seismic and geologic trends. The correlation structure between the variables is modeled under a multivariate Gaussian model. The local distributions of uncertainty have been checked with cross validation and with more than 100 new wells drilled during the last two drilling seasons. Resource uncertainty over the entire lease area and a number of arbitrary development areas is derived from the 2-D maps of uncertainty. A combined P-field / LU simulation approach is used; the global uncertainty is consistent with the local uncertainty.
Effective Software Practices To Leverage Software Development Process in Sand-Control Engineering Software—A Case Study
Authors: Li J. , Chok P.
Published: December 2007

The quest by E&P companies and their service providers to gain a competitive edge through technology is driving a demand for higher standards in engineering software. Time to market is a critical success factor and is often viewed as contradictory to higher standards and other factors such as limited resources and budgets. An optimum approach to engineering software development can successfully satisfy both time-to-market and budgetary requirements while continually raising standards.

This paper will discuss software practices that have proven effective during a full oilfield engineering software application development life cycle. Although the process activities – including specification, design, development, testing and deployment – were conventional, they were sequenced in a non-conventional manner and augmented with techniques such as risk management, use cases analysis, software modeling and configuration management.

The paper presents a case study that illustrates how these practices were used in a sand control engineering software development project to successfully design and remodel an existing horizontal gravel pack spreadsheet application into a standalone desktop application. The new application provides a user-friendly interface to design and analyze gravel transport for solids of varying density in Newtonian fluids. A computation engine was developed as a plug-in component to perform various computations during the gravel packing process. An object-oriented architecture and framework were designed and built to avoid having to rebuild every new application from scratch. The authors will explain how the system was built and extended to incorporate new capabilities and how adopting optimized development practices has enabled reuse of software components in new applications and increased both the standards and cost-effectiveness of engineering software development.
Nondamaging Drilling Fluid Enhances Borehole Quality and Productivity in Conventional Wells of Mehsana Asset, North Cambay Basin
Authors: Mandal N. G. , Jain U. K. , Kumar B. S. Anil , Gupta Ashok K.
Published: December 2007

Mehsana Asset of ONGC, in North Cambay Basin in India, emphasizes on increased oil production with the use of new technologies. Non Damaging Drilling Fluid (NDDF) is the basic part of this paradigm shift. Application of NDDF is the most direct method for controlling formation damage during drilling. NDDF was introduced in Linch field of the Asset for drilling of pay zones. The paper covers formulation, field optimization and application of NDDF in three wells of Linch field and subsequent application in North Kadi field. Laboratory results as well as field behaviour and parameters of NDDF along with drilling parameters and production testing results are discussed. The paper also touches the constraints in application and their solution by coordination and ingenious use of available resources. Field optimization of NDDF formulation has shown encouraging results in terms of compatible mud parameters. No complications were faced while drilling and testing. Gauged holes have shown good quality of logs. The wells have given a distinctively increased productivity in terms of oil production with instant activation.