bluuebunny/crossref_metadata_2025 huggingface dataset:
Subcool, Fluid Productivity, and Liquid Level Above a SAGD Producer
Authors: Yuan Jian-Yang , Nugent Daniel
Published: June 2014

Thermodynamic steam-trap control, or subcool control, in a typicalsteam-assisted gravity-drainage (SAGD) production is essential to the stabilityand longevity of the operation. It is achieved commonly through the control offluid production. The goal of such control is to maintain a steady and healthyliquid production without allowing steam from the injector to bypass to theproducer. Therefore, it is effectively a control of the liquid level above theproducer. Unfortunately, it is not practical to monitor this liquid level. Arule-of-thumb subcool-per-metre estimation of 10°C/m of liquid level is popularin the industry; however it does not prove to hold in many situations. Thispaper presents a study of the dynamics of SAGD-production control with aresulting algebraic equation that relates subcool, fluid productivity, andwellbore drawdown to the liquid level above a producer. The main conclusions ofthis study include

There is no minimum subcool value for a pure-gravity-drainage scenario;however, as the wellbore drawdown is considered, there is a minimum subcoolvalue in order to maintain the stability of fluid flow.

For a given productivity, the liquid level increases as subcool increasesor as wellbore drawdown decreases.

For each given set of operating parameters, there exists a criticalproductivity below which SAGD operation would halt.

Before the steam chamber reaches the top of the reservoir, the fluidproductivity is limited by the vertical distance between the injector and theproducer; the larger the distance, the higher the fluid production rate canbe.

A verification of this analysis was conducted by a series of numericalreservoir simulations. Although limited to two dimensions, we expect that thisanalysis captures the main physics amid the dynamic complexity ofSAGD-production control. The resulting algebraic equation can be used forbetter understanding of the dynamics of subcool control and for determiningoperation strategies.
Modelling of Bitumen-and-Solvent-Mixture Viscosity Data Using Thermodynamic Perturbation Theory
Authors: Zirrahi Mohsen , Hassanzadeh Hassan , Abedi Jalal
Published: June 2014

Viscosity is an important transport property for engineering design and simulation of bitumen production and transportation. During the production of bitumen with solvent injection, steam-assisted gravity drainage, or expanding solvent steam-assisted gravity drainage, the oil/solvent mixture encounters various temperature and pressure conditions. Therefore, a model is necessary to predict the viscosity of the mixture of bitumen and solvent in wide ranges of temperatures, pressures, and compositions (T-P-x). In this work, we propose a semitheoretical viscosity model based on the Arrhenius mixing rule and considering the effect of association between the molecules of the solvent and the bitumen. To achieve this purpose, thermodynamic perturbation theory (TPT) is used to calculate the fraction of bonding solvent molecules. We calculate the viscosity of the solvent in wide temperature and pressure ranges using the modified Enskog theory (MET). Results show an acceptable agreement between the predictions of this model and experimental viscosity data of bitumen saturated with different solvents (CH4, N2, CO2, and C2H6) at various T-P-x ranges. These experimental data cover the typical T-P-x ranges of oil-recovery methods.
Geologic Heterogeneity and Economic Uncertainty of Subsurface Carbon Dioxide Storage
Authors: Heath J.E. E , Kobos P.H. H , Roach J.D. D , Dewers T.A. A , McKenna S.A. A
Published: June 2014

Subsurface storage of carbon dioxide (CO2) has geologic and economic uncertainties that must be addressed as part of a performance assessment. A model presented herein links uncertainty in geologic heterogeneity and associated well injectivity to variability in costs. This includes a novel averaging scheme for CO2 injectivity using geostatistical realizations of petrophysical properties and a systems-level model that includes costs of drilling and completion of injection wells. Using the Mount Simon Formation in the Illinois basin, USA, as a test case, this analysis demonstrates how the underlying costs of CO2-subsurface-storage projects can be highly sensitive to geologic heterogeneity.
Field Results for Recovering Oil From a Steam-Project Pressure-Isolation Wall
Authors: Miller Karl A. , Xiao Yi
Published: June 2014

The Lloydminster, Saskatchewan, area Pikes Peak steam project has been onproduction since 1982. A key part of the development strategy was use of anundeveloped pressure-isolation wall to allow the two halves of the pool to bedeveloped with different time schedules and exploitation processes. Use of thepressure-isolation wall allowed different exploitation options to be used, butduring late project life the oil left in the wall needed to be recovered toenhance project economics. A significant challenge in recovering the oil in thewall was the lack of pressure containment or oil saturation on both flanks,resulting in the need for a gentle recovery process to avoid pushing the oiloutside the wall. On the basis of numerical-simulation results, the recoveryprocess selected for the wall was use of two cyclic-steam-stimulation (CSS)horizontal wells operated in a gentle manner. After the horizontal wells weredrilled, however, temperature logs showed the reservoir surrounding one of thehorizontal wells had already been heated by offsetting steam injection, andthat well has been continually produced at good rates without the need forsteam stimulation. The second new horizontal wall well was initially operatedsuccessfully using the CSS process designed using numerical simulation, butthat well is now also being operated in an external drive mode. The results ofthis field study show that the oil in a wall used to pressure isolate sectionsof a steam-project pool can be recovered economically without pushing the oilinto the adjacent depleted areas by use of processes designed to account forlocal wall conditions.
Dead Horizontal Well Revival Utilizing Fiber-Optic Enabled Coiled Tubing Combined with Underbalance Perforating Gun Deployment Technique (Case Study)
Authors: Subaie Fehead , Otaibi Nashi , Sultan Fouad , Burov Anton , Keong Azwan
Published: June 2014

In many oil fields water production often threatens the reservoir performance and economic viability of wells. Excess unwanted water production can cause an increase in production costs and a decrease in productivity. To mitigate this, it is crucial to utilize water management techniques to reduce water cut (WC), optimize oil production, extend the well life and recover idle wells.

The most effective technique for water shut off (WSO) treatments in Saudi Arabia comparatively to the costly workover rig treatments was proved to be a rigless WSO using mechanical isolation especially when it gives options to perform additional operations with the single rigup.

This paper describes the first time — in Saudi Arabia — implementation of the mechanical rigless WSO method, used to mechanically isolate a watered open hole section. This isolation is accomplished by utilizing fiber optic enabled coiled tubing (FOECT) telemetry and then setting an inflatable packer in the liner. It is capped with cement following perforation treatment, by using a completion insertion and retrieval under pressure (CIRP) deployment system, which allowed the guns to be run and pulled under live well conditions without killing the well.

The depth correlation for the packer setting — and later for perforation depth correlation — was performed by fiber optic bottom-hole assembly (FOBHA-GR). The inflation of the packer and the injection through it were monitored and adjusted realtime with the FOBHA-Pressure - Temperature - Casing Collar Locator (FOBHA-PTC) measurement inside and outside the FOCT string. FOBHA utilize deployment method from CIRP technology to perforate the new formation by using the TCP E-Fire firing head under well dynamic underbalanced conditions.

Recent production results showed a previously dead well flowed at 10 thousand barrels per day oil rate with 12% water cut.

This innovative combination of WSO solution with FOECT and CIRP techniques proved to be an effective method to minimize operational time, equipment and footprint on location, and efficient perforating in a single underbalance run at one rigup.

This paper also discusses the challenges faced during job execution, lessons learned, and experience gained to optimize similar jobs in the future.
A New Model for the Accurate Prediction of Liquid Loading in Low-Pressure Gas Wells
Authors: Luan Guohua , He Shunli
Published: June 2014

The critical gas velocity and flow rate for unloading liquids from a gas well has been the subject of much interest, especially in old gas-producing fields with declining reservoir pressures. For low-pressure gas wells, Turner's model (also called Coleman's model) is judged as more suitable for predicting liquid loading in gas wells. However, field practice proves that there are still a number of low-pressure gas wells producing without loadup when the production rate is lower than Turner's minimum production rate.

On the basis of experimental results, a new approach for calculating the critical gas-flow rate is introduced in this paper, which adopts Li's basic concepts, while taking into account the impact of the changes of gas-lifting efficiency caused by the rollover of droplets in the process of rising. A dimensionless parameter, loss factor S, is introduced in the new model to characterize the extent of the loss of gas energy.

Well data from Coleman's paper (Coleman et al. 1991) were used in this paper for validation of the new model. The predicted results from the new model are better than those from Li's model, and even better than Turner's model. The new model is simple and can be evaluated at the wellhead when the pressure is less than 500 psia and the liquid/gas ratios range from 1 to 130 bbl/MMscf, which is suggested by Turner et al. (1969) to ensure a mist flow in gas wells.
Thoughts on Simulating the VAPEX Process
Authors: Cuthiell Dave , Edmunds Neil
Published: June 2014

The vapour extraction (VAPEX) process and its many hybrid variants have attracted a great deal of attention as potentially lessenergy-intensive alternatives for exploiting heavy-oil and bitumen resources. However, despite significant work over the past 2 decades, uncertainty remains about the basic mechanisms, the scaling aspects, and the most appropriate methods of numerically simulating these processes. This paper offers some insights into several of these outstanding questions. The questions are examined in the context of an extensive and well-documented set of VAPEX experiments carried out by Maini and his colleagues over the past 10 years.

We have experimented with different methods of simulating these experiments using a physics-based reservoir simulator. Despite the high permeability (greater than 200 darcies in all of the experiments), we find that capillary pressure plays a significant role in the drainage. The simulations suggest that most of the drainage takes place in the capillary transition zone along the edge of the vapour chamber, rather than in the single-phase zone ahead of it which has not yet been contacted by vapour. It has been emphasized in the literature that the near-linear scaling of oil rate with height observed in the experiments is dramatically different from the square-root-of-height dependence predicted by the original analytic model of VAPEX. However, the experiments also show an increasing solvent fraction in the produced-oil phase as height increases. When this "solvent mixing" effect is separated from the rates, the remaining height dependence is less than linear, though still greater than square root of height. The relative roles of molecular diffusion and mechanical dispersion in VAPEX have been discussed widely in the literature.

Generally, mechanical dispersion is expected to play a larger role in these high-permeability experiments (compared with the field) because of larger fluid velocities. We present a method of inferring the diffusion/dispersion present in the simulations, despite a hidden component of numerical dispersion caused by the numerical method itself. We find that the experiments are well matched with values of diffusion and dispersion in line with literature correlations, and that the contribution of mechanical dispersion is perhaps not as large as might be expected relative to that of molecular diffusion.

The paper also provides some thoughts on questions we expect are still unanswered, including mechanisms behind the height dependent mixing phenomenon and the scaling of the experimental results to the significantly greater heights and lower permeability characteristic of the field.
Reduction of Friction Loss in Fracturing Operations
Authors: Ousterhout Ray S. , Hall Colby D.
Published: June 2014

In modern fracturing treatments, friction loss in pipe often has been the limiting factor in obtaining high injection rates desired for maximum effectiveness. Additives now available can reduce the friction loss of water by 70 per cent, permitting horsepower savings or higher injection rates, and completion of wells with smaller-size casing. The additives are used at very low concentrations for reducing friction loss. Higher concentrations give even lower friction loss, even though these fluids are viscous enough to give effective viscosity control of fracture leak-off. The friction-loss reduction is attributed to viscoelasticity of the solutions, which partially suppresses turbulence.

Introduction

The major trends in hydraulic fracturing during recent years have been the use ofhigher injection rates,more efficient fluids andengineering methods in designing the treatments.

These trends focus attention On the friction pressure-drop in pipe as a major factor in the operation. The cost of power used in overcoming friction does not contribute to increasing the fracture area achieved. A surface pressure limit, set by the strength of the pipe, often determines the maximum attainable injection rate. This rate may not be high enough to give the most efficient treatment in terms of fracture area per dollar spent.

The use of chemical additives to reduce friction loss in pipe significantly improves efficiency in fracturing treatments. It is known that the soap-gelled crude oils used in fracturing have lower friction losses than the same crude oils without gelling agents. In fracturing with brine or fresh water, still larger reductions of friction losses have been attained by two types of materials: a natural gum polymer and, more recently, a synthetic water-soluble polymer. Besides reducing friction loss, both additives are used to thicken fresh water, and the natural polymer thickens brine. Such "gelled water" has a low sand-falling rate and good viscous control of leak-off from the fracture.
Wanted Dead or Live: Crude-Cocktail Viscosity--A Pseudocomponent Method to Predict the Viscosity of Dead Oils, Live Oils, and Mixtures
Authors: Yarranton Harvey , van Dorp Johan , Verlaan Marco , Lastovka Vaclav
Published: June 2014

A broadly applicable methodology is presented to reliably predict crude-oil-liquid viscosity from a gas-chromatographic (GC)-assay composition only (C30+ is recommended). The viscosity model employs a Walther-type correlation of double-log viscosity with log temperature to predict the viscosity of dead and live crude oils and mixtures. The model has three parameters: the slope and intercept of the Walther plot and a viscosibility factor to account for pressure effects. Simple mass-based mixing rules are applied on these three parameters to obtain mixture viscosity. The three parameters were correlated to component molecular weight (MW); therefore, a gas-chromatographic assay is the only required input apart from the temperature and pressure. The methodology was developed from a western Canadian (WC) data set of two bitumens, one heavy oil, and one condensate, and then tested on an independent data set of 10 conventional and heavy crude oils from the Gulf of Mexico, the Middle East, Asia, and Europe. The model provides untuned viscosity predictions within a factor of two of the measured values for dead and live crude oils ranging in viscosity from 0.5 to 500 000 mPa·s. A single multiplier is used to tune the model. Models tuned to dead-oil data predict live-oil viscosities and those of mixtures of oils with solvents to within 30% of the measured values. Models tuned to the viscosity at the saturation pressure predict the effect of temperature and pressure to within 20% of the measured values. The method retains its accuracy when components are lumped into a few pseudocomponents and is suited ideally for use in simulators for accurate liquid-phase viscosity predictions over a wide range of compositions, pressures, and temperatures. It would be necessary to include the proposed mixing rules in numerical simulators. An additional advantage of the method is the reduction in viscosity measurements needed to construct an accurate viscosity model.
Nabucco Gas Pipeline Project - A Challenging Project in the Prequalification Phase
Authors: Kuepper Michael , Roloff Joachim
Published: June 2014

The Nabucco Gas Pipeline is a transit and transport pipeline that will serve as a connection of several gas reserves in the Caspian Region as well as the Middle East to Europe. The Nabucco Gas Pipeline is one of the longest pipelines in the world. It has a length of approx. 3.300 km and will run from Turkey to Austria via Bulgaria, Romania and Hungary. Owner and operator of the Nabucco Gas Pipeline is the Nabucco Gas Pipeline International GmbH (hereafter: NIC). The company consists of the following 6 international shareholders: BOTAS (Turkey), Bulgarian Energie Holding (Bulgaria), Transgaz (Romania), MOL (Hungary), OMV (Austria) and RWE (Germany).

NIC has been supported by TUV Rheinland during the prequalification phase for suppliers of long lead items. Additionally TUV Rheinland assumed the task of reviewing and verifying material specifications prepared by the owner's engineer (hereafter: OE). NIC wished to identify the most capable suppliers for the Nabucco Gas Pipeline Project. TUV Rheinland very effectively implemented this project goal by evaluating suppliers’ technical competences, quality and performance ability.

On the basis of technical and commercial criteria companies have been preselected during the "desktop study". In the next step those preselected and found capable companies have been audited on site. In total, TUV Rheinland audited 73 vendor sites in 20 different countries for the Nabucco Gas Pipeline Project. This represented a huge challenge in both logistics and time. Due to its worldwide presence in 61 countries on all continents and its international network of inspectors TUV Rheinland mastered this challenge successfully and managed to provide NIC with the requested high quality results. TUV Rheinland prepared an absolutely traceable and non discriminating evaluation model to prevent any kind of claims in the course of the prequalification phase as the process’ traceability was of highest significance for NIC.

The result of TUV Rheinland's work has been the identification of the most capable suppliers of long lead items as well as the top performing companies and the detection of potential risks which might occur during the production process.

The prequalification process provides valuable information for both the procurement and the subsequent production process which shows TUV Rheinland's importance and relevance within the Nabucco Gas Pipeline Project.
An Engineer's View of Federal Income Taxes
Authors: Eggleston W.S.
Published: June 2014

History of the Income Tax

Although income tax and income tax calculations are discussed, it is not intended that this analysis encourage a valuation engineer to become his own tax expert. Tax matters should be referred to a tax specialist whose field is as broad as that of a petroleum or valuation engineer.

Our income tax laws and regulations had their beginning with the Revenue Act of 1913 which levied the first income tax in the United States. Since that time, the revenue acts of 1916, 1918, 1921, 1924 and 1926 have changed or modified the ground rules of the income tax regulations as applied to oil and gas production and income.

Federal income tax legislation since 1926 has provided for two types of depletion allowance for oil and gas producers:percentage depletion at 27 per cent of gross income, not to exceed 50 per cent of net income; andcost depletion. For the purpose of computing the depletion allowance, percentage depletion is applied separately to the income from each oil and gas property.

Property, for Internal Revenue purposes, means each separate interest owned by the taxpayer in each mineral deposit in each separate tract or parcel of land (unless aggregated).

Until 1954, no specific statutory authority existed for the election to deduct intangible drilling costs as an expense. The revenue acts of 1918 and 1921 gave this election by implication but not specifically. The Internal Revenue Act of 1954 gave specific statutory expression to the taxpayer's first-year option of capitalizing or expensing intangible drilling costs.
A New Method To Predict the Performance of Gas-Condensate Reservoirs
Authors: Al-Shawaf Ali , Kelkar Mohan , Sharifi Mohammad
Published: June 2014

Gas-condensate reservoirs differ from dry-gas reservoirs. The understanding of phase and fluid flow-behavior relationships is essential if we want to make accurate engineering computations for gas-condensate systems. Condensate dropout occurs in the reservoir as the pressure falls below the dewpoint, resulting in significant gas-phase production decreases.

The goal of this study is to understand the multiphase-flow behavior in gas-condensate reservoirs and, in particular, to focus on estimating gas-condensate-well deliverability. Our new method analytically generates the inflow-performance-relationship (IPR) curves of gas-condensate wells by incorporating the effect of condensate banking as the pressure near the wellbore drops below the dewpoint. The only information needed to generate the IPR is the rock relative permeability data and a constant-composition-expansion (CCE) experiment.

We have developed a concept of critical oil saturation near the wellbore by simulating both lean and rich condensate reservoirs and have observed that the loss in productivity caused by condensate accumulation can be closely tied to critical saturation. We are able to reasonably estimate re-evaporation of liquid accumulation by knowing the CCE data.

We validated our new method by comparing our analytical results with fine-scale-radial-simulation-model results. We demonstrated that our analytical tool can predict the IPR curve as a function of reservoir pressure. We also developed a method for generating an IPR curve with field data and demonstrated its application with field data. The method is easy to use and can be implemented quickly. Another advantage of this method is that it does not require the knowledge of accurate production data including the varying condensate/gas ratio (CGR).
Mud Analysis Logging
Authors: Pixler B.O.
Published: June 2014

Mud analysis logging is a direct method of detecting oil and gas in formations drilled. The factors that determine the hydrocarbon content of the drilling mud are discussed. The advantages and disadvantages of the various techniques for separation of gas from the mud and for gas detection are considered.

Examples included show field results of the latest mud logging development - the quantitative analysis of drilling mud for volatile hydrocarbons. Mud analysis provides the means for obtaining valuable formation information not otherwise available. Now, the system furnishes even greater diagnostic data for interpretation.

Introduction

Mud analysis well logging is not a recent development. Even before the introduction of rotary drilling, cable tool drillers logged their hole with ballings. The early rotary drillers kept a watchful eye on the mud returns for telltale gas bubbles. They continued to examine formation fragments - this time bit cuttings - removed from the mud by screens or by settling. The "feel" of the bit told them whether they were drilling in sand or shale, and changes in rates of penetration indicated changes in subsurface rock strata. Tops and thicknesses of formations were logged on the rotary drilling reports.

Mud logging technology has come a long way since 1939 when it was first introduced commercially. While all mud logging techniques have been continually improved, the greatest strides in development have been made in Mud gas separators and mud gas detectors.

Release of Hydrocarbons to Mud Flow

The most important diagnostic in mud analysis logging is the record of gas detected in the mud. Hydrocarbons in the formation drilled are released to the mud flow, first, at the instant the section is drilled and, second, by gas expansion in cuttings as the mud pressure decreases while the cuttings are carried to the surface. The relative concentration in mud of hydrocarbons released from the reservoir rock during drilling depends on the extent to which the rock is flushed by the mud filtrate and on the rate of mud circulation. The following three factors influence the amount of flushing.
Technology of High-Pressure Transport of Multicomponent Hydrocarbon Gases
Authors: Vykhodtsev A. V. , Panov R. A.
Published: June 2014

The main problem of pipeline transport of associated petroleum gas (APG) and natural gas – the need for transfer of a multicomponent hydrocarbon mixture. The purpose of this paper is the disclosure of technical, methodological, and economic aspects of a comprehensive approach to training, transportation and processing of gas through the use of supercritical states of multicomponent hydrocarbon mixtures for deposits of oil company OAO "Rosneft" in the Western and Eastern Siberia. The development of this technological approach allows oil and gas organizations to more effectively utilize resources and achieve routine associated gas utilization degree of the problem which, to date, is associated with a weak refinement and low cost-effectiveness of technologies proposed for utilization of associated gas. Of particular importance in this context takes the introduction of innovative technologies capable of solving many problems faced by the subsoil user during transportation of hydrocarbon gases.
Techniques of Electric Log Interpretation
Authors: Atkins E.R.
Published: June 2014

The generally used techniques of electric log interpretation are reviewed and discussed, including the determination offormation water resistivity from the SP curve,true resistivity values from log data,water saturation from electric logs, andformation porosity from resistivity data.

Particular emphasis is placed on the assumptions made in log interpretation. It is hoped that efforts will be stimulated which, in the future, will make it possible to reduce the number of assumptions necessary for log interpretation.

Introduction

Petroleum engineering and geology can be said to be based upon both facts and assumptions. So too, are the various techniques of electric log interpretation. For the last few years, some assumptions which have been made in developing log interpretation methods have been repeated so often that they are now accepted by many persons as facts. In reviewing the principles of resistivity and potential curve interpretations, many of the assumptions (and how they affect the results of interpretation) will be considered.

Because this is a review, the purpose of this paper is not to present new methods of interpretation. However, the reader of this review should be stimulated to consider whether he should accept these assumptions as they are made now or whether he would prefer to explore possible ways to reduce the number of assumptions required for log interpretation.

Assumptions

To emphasize the assumptions used in most interpretations of electric logs, they will be tabulated here and then referred to as each technique of interpretation is discussed. No particular emphasis is inferred by the order of tabulation.
Use of Liner Drilling Technology as a Mitigation to Lost Circulation in The Faja De Oro (Golden Lane) Oil Fields Offshore Veracruz, Mexico
Authors: Aguilera Naveja L. F. , Fermin G. R. , Ramos R. Gamiño , Rosenberg Steven M. , Dominguez M Marco A.
Published: June 2014

This paper will demonstrate the benefit of liner drilling technology to drill and cement an operator's 9-5/8" and 7" liners in place allowing for the continued development of oil reserves from the naturally fractured El Abra formation in the Carpa and Bagre fields of the Faja de Oro area. Prior to the introduction of liner drilling, two previous wells drilled in the Carpa field encountered massive lost circulation and hole instability while drilling into the El Abra limestone resulting in a total of 55 days of NPT (non productive time) for the two wells. An estimated 2,700 bbls of fluid were lost in these wells with both wells having to be sidetracked to reach their El Abra objective. The total economic impact related to this NPT was estimated at USD$ 5.68 MM.

Liner drilling technology has been identified as the most suitable solution to isolate the loss and hole instability intervals because:

Documented lost circulation problems have been mitigated through use of liner drilling technology due to the "smear effect" phenomenon, especially in shale fractured zones, before reaching chalk intervals. Also the narrow annular geometry characteristic of liner drilling allows for management of the annular fluid level. The hydraulic liner system selected provided for high torsional capacity as well as excellent cyclic fatigue resistance, key criteria for liner drilling operations. Additionally this system had been proven in multiple liner drilling operations. The drillable PDC casing bit was capable of drilling the respective required hole sections.

The nine wells portrayed in this paper incorporated liner drilling in their respective basis of design allowing the operator to reach the intended liner setting depths, eliminating contingency liners, and ultimately meeting well construction objectives. The equipment selection, operation, results, and lessons learned will be presented, also have been optimized due to the numbers of well drilled consecuently.
Comparing Soft-String and Stiff-String Methods Used to Compute Casing Centralization
Authors: Gorokhova Lidia , Parry Andrew , Flamant Nicolas
Published: June 2014

Good casing centralization during cementing operations is a key factor for achieving proper mud displacement and obtaining hydraulic isolation in the annulus. To this end, centralizers are often placed along the casing to position it centrally in the borehole. The optimal number of centralizers and their spacing are determined with simulation software.

Until now, the industry has typically used calculation methods derived from American Petroleum Institute (API) Spec. 10D (2002, 2004) to predict casing eccentricity in the wellbore. The calculations are based on an analytical soft-string method, which models an element of casing string between two centralizers as a bifixed-ends beam.

However, in drilling operations, the use of a numerical stiff-string method to compute torque-and-drag forces is now becoming widespread. It accounts for tubular bending stiffness and provides a more realistic analysis of the stresses and loads acting upon the drillstring and the borehole. The stiff-string technique that is based on the finite-element method is thus proposed as an alternative and more effective solution for computing casing centralization for cementing operations.

Measured and calculated casing centralizations were compared in several field cases. The casing eccentricity was measured after the cement placement by use of recently developed ultrasonic logging tools and diagnostics. Discrepancies between analytical and numerical calculation methods were analyzed; then, advantages and disadvantages to each method were assessed. The results of the calculation methods were used to formulate an optimal approach to casing centralization.
Cost-Effective Ultralarge-Diameter Polycrystalline-Diamond-Compact-Bit Drilling in Deepwater Gulf of Mexico
Authors: D'Ambrosio Piero , Hart Sofiri , Prochaska Ernest , Bouska Reisha , Tinsley Douglas
Published: June 2014

Ultralarge-diameter polycrystalline-diamond-compact (PDC)-bit drilling is a fast-growing cost-effective solution in high-tier deepwater drilling operations in the US Gulf of Mexico (GOM) where salt is encountered in the shallow part of the wellbore. Conventional design called for roller-cone (RC) (IADC Code 111-115) drill bits on positive-displacement motors (PDMs) in these ultralarge-diameter intervals. Cost savings on drilling fluid alone, in the form of rate-of-penetration (ROP) gains through the salt interval, has the industry trending to drill these riserless sections with the use of PDC drill bits on rotary-steerable-system (RSS) drilling assemblies.

New robust high-torque-capacity topdrives, stronger drillpipe (DP) connections, larger-diameter RSS tools, and improved mud programs have all largely contributed to this step change in drilling performance. In addition, evolved bit and bottomhole-assembly (BHA) design, efficient operating parameters, improved hydraulics, and vibration-prediction modeling have all aided in the success of these runs.

Although this emerging new trend reduces drilling times and associated cost, experience has shown there are multiple challenges that must be overcome to complete a successful run in a single trip. These challenges vary from well to well and include, but are not limited to, BHA steerability, rig-equipment limitations, efficient operating parameters, identification of both sediment and salt formations, hole cleaning and hydraulics, salt creep, drilling-fluid displacement, DP torque limitations, stabilization placement, lateral/ torsional BHA vibrations, and others.

This paper will concentrate on the multiple aspects of ultralarge-diameter riserless PDC-bit drilling applications and the considerations that have been used to optimize them. Prior SPE papers and data from previous deepwater GOM case histories were heavily researched and scrutinized to support the conclusions provided within the body of this paper. Together with industry experience available, these findings have resulted in a set of defined recommendations, providing operators with a guide to justify a lower-cost-per-foot approach through the potential reduction of drilling time in these challenging applications.
Managed Pressure Drilling Experience on deepwater application in West Africa
Authors: Sammat E. , Pavesi R. , Besenzoni L. , Copercini P.
Published: June 2014

Since hydrocarbon reserves located in benign environments are more difficult to find, the oil and gas industry has been forced to gravitate toward more complex and challenging accumulations. The difficulties faced therein often increase non-productive time (NPT), costs and risk. The deep water offshore West Africa exemplifies this scenario, requiring new and innovative ways to economically locate and exploit smaller reserves. Managed pressure drilling (MPD), despite being a relatively new technology, has been progressively proven as one that can significantly change the way wells are drilled—not only reducing NPT but also enabling access to reserves in areas previously considered undrillable while reducing the associated risks.

The high cost of offshore drilling means that offshore MPD delivers significant savings when NPT associated with fluid losses or a well control event are eliminated. Drawing from past successful experience where the circulating device and MPD system were used on a high-pressure/high-temperature (HPHT) well enabled reaching all the well targets, it was decided to use this combination of technologies to drill this challenging well.

This paper discusses the application of the combination of the circulating device and MPD system on a deepwater well in Ghana, West Africa. This MPD technique was used from the start—drilling the 14-3/4 in. section to the end of drilling a 8-1/2 in. section on deepwater application in West Africa. One of the main benefits of using this MPD technique was to control the bottomhole pressure drilling through inherently unstable zone. This helped drilling to target depth while effectively handling influxes with significant time savings. The planning, development and execution phases of the MPD project are detailed in this technical paper.
The Use of Sidewall Core Analysis in Formation Evaluation
Authors: Koepf E.H. , Granberry R.J.
Published: June 2014

Analytical techniques and procedures which permit accurate measurement of important physical properties and of fluid content of sidewall core samples as received in the laboratory are available. However, hole conditions prior to and during sampling affect the values as measured on the core samples. Also, the impact of the percussion sampler in the sampling process alters some of the physical characteristics of the sample. Comparisons of data on conventional and sidewall core samples and experience have shown the general direction of these effects. Normally, formations along the Gulf Coast have a greater productive capacity than the sidewall core sample data indicate. Water saturations associated with gas, condensate or oil production are greater in sidewall than in conventional core samples. Sidewall core data are valuable as exploratory aids, but data from conventional or wireline cores are generally required for evaluating recoverable reserves, the distribution of reservoir fluids and formation flow characteristics.

Sidewall core data usually establish the presence or absence of hydrocarbon content and indicate the probable type of production. Measured permeability and porosity values indicate productive capacity. The data show gas-oil and water-oil contacts. Sidewall sample data are particularly valuable as a basis for "calibrating" electrical log data. They are used to check lithology changes indicated by log data, and they permit evaluation of thin and stray sands. Sidewall core samples probably provide the most reliable data normally obtained on "dirty" or ashy sand zones which show low resistivity on the electrical logs, on sand sections drilled with high-salt-content muds and on shallow bentonitic sands containing fresh water. Consideration of both sidewall core analysis data and electrical log data together increases the value of each. In many instances, it is necessary to consider both types of data in arriving at a correct interpretation. Greatest value can be obtained from the sidewall core data if the analyst has an electrical log of the zone as a guide for general formation characteristics and for zoning the various samples.
Experience from Hardware-In-the-Loop Testing of Drilling Control Systems
Authors: Pedersen Tom , Smogeli Øyvind
Published: June 2014

Modem Drilling ships and rigs have advanced computer systems for dynamic positioning, power generation and distribution, and Drilling operations. It is well known that software errors may lead to delays and non-productive time, and compromise safety. While the testing and verification regime for structures and machinery systems is well established, most of the computer systems on today's Drilling vessels are put into operation without independent testing and verification. Hardware-In-the-Loop (HIL) testing is a well proven test methodology from several other industries. It facilitates systematic testing of control system design philosophy, functionality, performance, and failure handling capability, both in normal and off-design operating conditions, and is conducted in a virtual test-bed where there is no risk to man, vessel, or equipment. Automatic Drilling systems which rely on software to function properly often consist of a combination of components delivered by several suppliers. This means that also control system software from several suppliers must run and work together as an integrated system in order to maintain safety and achieve the desired operational performance. Marine Cybernetics has finalized testing of Drill floor control systems for 7 rigs, involving 9 different vendors. This paper presents experiences from these projects in terms of project execution, test timing and vendor cooperation and participation. Examples of typical observations are also presented.
Experience From Hardware-in-the-Loop Testing of Drilling Control Systems
Authors: Pedersen Tom , Smogeli Øyvind
Published: June 2014

Modern drilling ships and rigs are equipped with advanced computer systems for dynamic positioning, power generation and distribution, and drilling operations. It is well-known that software errors may lead to delays and nonproductive time and may compromise safety. Although the testing and verification regime for structures and machinery systems is well-established, most of the computer systems on today's drilling vessels are put into operation without independent testing and verification.

Hardware-in-the-loop (HIL) testing is a test methodology used in several other industries. It facilitates the systematic testing of control-system design philosophy, functionality, performance, and failure-handling capability, in both normal and off-design operating conditions, and is conducted in a virtual test bed in which there is no risk to personnel, vessel, or equipment.

Automatic drilling systems that rely on software to function properly often consist of a combination of components delivered by several suppliers. This means that, to maintain safety and to achieve the desired operational performance, control-system software from several suppliers must also run and work together as an integrated system.

Marine Cybernetics has finalized the testing of drill-floor control systems for seven rigs, involving nine different vendors. This paper presents experiences from these projects in terms of project execution, test timing, and vendor cooperation and participation. Examples of typical observations are also presented.
The Stability of a Pipe Stand Racked in a Derrick, Part 2—A General Pipe-Stand Model
Authors: Sawaryn S.J.. J. , Pattillo P.D.. D.
Published: June 2014

This paper builds on the information contained in Part 1 (the body of the paper preceding the appendices) and presents a general pipe-stand model. The model is based on the Fourier-series solution of the energy equation for calculating the deflection and buckling condition of an inclined, nonuniform pipe stand with an arbitrary number of intermediate loads and stick-up above the top racking board. Full details of the derivation and algorithms are included in the paper. This flexible approach is used to examine more-complex, practical situations that include the buckling sensitivity to the position of the upper support and added loads such as tool joints or running tools racked with the stand.

Using a Fourier-sine-series solution avoids dealing with the less familiar higher-order functions encountered in Part 1, so the algorithms can be coded with standard spreadsheet functions. This approach also increases the model's capability and practical worth, providing a tool suitable for field use. The results for loaded, uniform stands compare within 0.01% with the limiting cases represented by the analytical solutions presented in Part 1. Nonuniformity of the stand can add significantly to the number of series terms required.

Several practical examples are used to illustrate the model's application, including the analysis of the stand with a heavy intermediate load where buckling occurred. The model successfully distinguishes between the buckled and nonbuckled conditions.
Investigation of the Critical Velocity Required for a Gravity-Stable Surfactant Flood
Authors: Tavassoli Shayan , Lu Jun , Pope Gary A. , Sepehrnoori Kamy
Published: June 2014

Classical stability theory predicts the critical velocity for a miscible fluid to be stabilized by gravity forces. This theory was tested for surfactant floods with ultralow interfacial tension (IFT) and was found to be optimistic compared with both laboratory displacement experiments and fine-grid simulations. The inaccurate prediction of instabilities on the basis of available analytical models is because of the complex physics of surfactant floods. First, we simulated vertical sandpack experiments to validate the numerical model. Then, we performed systematic numerical simulations in two and three dimensions to predict formation of instabilities in surfactant floods and to determine the velocity required to prevent instabilities by taking advantage of buoyancy. The 3D numerical grid was refined until the numerical results converged. A third-order total-variation-diminishing (TVD) finite-difference method was used for these simulations. We investigated the effects of dispersion, heterogeneity, oil viscosity, relative permeability, and microemulsion viscosity. These results indicate that it is possible to design a very efficient surfactant flood without any mobility control if the surfactant solution is injected at a low velocity in horizontal wells at the bottom of the geological zone and the oil is captured in horizontal wells at the top of the zone. This approach is practical only if the vertical permeability of the geological zone is high. These experiments and simulations have provided new insight into how a gravity-stable, low-tension displacement behaves and in particular the importance of the microemulsion phase and its properties, especially its viscosity. Numerical simulations show high oil-recovery efficiencies on the order of 60% of waterflood residual oil saturation (ROS) for gravity-stable surfactant floods by use of horizontal wells. Thus, under favorable reservoir conditions, gravity-stable surfactant floods are very attractive alternatives to surfactant/polymer floods. Some of the world's largest oil reservoirs are deep, high-temperature, high-permeability, light-oil reservoirs, and thus candidates for gravity-stable surfactant floods.
Generalized Field-Development Optimization With Derivative-Free Procedures
Authors: Isebor Obiajulu J. , Ciaurri David Echeverría , Durlofsky Louis J.
Published: June 2014

The optimization of general oilfield development problems is considered. Techniques are presented to simultaneously determine the optimal number and type of new wells, the sequence in which they should be drilled, and their corresponding locations and (time-varying) controls. The optimization is posed as a mixed-integer nonlinear programming (MINLP) problem and involves categorical, integer-valued, and real-valued variables. The formulation handles bound, linear, and nonlinear constraints, with the latter treated with filter-based techniques. Noninvasive derivative-free approaches are applied for the optimizations. Methods considered include branch and bound (B&B), a rigorous global-search procedure that requires the relaxation of the categorical variables; mesh adaptive direct search (MADS), a local pattern-search method; particle swarm optimization (PSO), a heuristic global-search method; and a PSO-MADS hybrid. Four example cases involving channelized-reservoir models are presented. The recently developed PSO-MADS hybrid is shown to consistently outperform the standalone MADS and PSO procedures. In the two cases in which B&B is applied, the heuristic PSO-MADS approach is shown to give comparable solutions but at a much lower computational cost. This is significant because B&B provides a systematic search in the categorical variables. We conclude that, although it is demanding in terms of computation, the methodology presented here, with PSO-MADS as the core optimization method, appears to be applicable for realistic reservoir development and management.