bluuebunny/crossref_metadata_2025 huggingface dataset:
Optimum Operating Conditions for Steady-State Two-Phase Flow in Pore Networks: Conceptual Justification Based on Statistical Thermodynamics
Authors: Valavanides Marios S.
Published: February 2011

The mechanistic model DeProF considers steady-state two-phase flow in porous media as a composition of three flow patterns: connected-oil pathway, ganglion dynamics and drop traffic flow. Their key difference is the degree of disconnection of the non-wetting phase which affects the relative magnitude of the rate of energy dissipation caused by capillary effects compared to that caused by viscous stresses. An appropriate mesoscopic scale analysis defines the process independent variables to be the capillary number, Ca, and the oil-water flowrate ratio, r, and leads to the determination of all the internal flow arrangements that are compatible with the externally imposed flow conditions. The observed macroscopic flow is an average over the canonical ensemble of the internal flow arrangements at mesoscopic scale. Extensive simulations using the DeProF algorithm revealed that there exist a continuous line, r*(Ca), in the domain of the process operational variables, (Ca, r) on which the efficiency of the process (oil produced per kW dissipated in pumps) attains a local maximum. The locus r*(Ca) defines the process optimum operating conditions. These findings are consistent with the phenomenology already presented in many experimental works.

The scope of the present work is to introduce a rational justification of the existence of the locally optimum operating conditions predicted by the DeProF theory.

Steady-state two-phase flow in porous media is a stationary process maintained in dynamic equilibrium on the expense of energy supplied to the system (an off-equilibrium process). The efficiency of the process depends on its spontaneity, measurable by the rate of global entropy production. The latter is the sum of two components: the rate of mechanical energy dissipation at constant temperature and a conformational entropy production component, directly related to the number of internal flow arrangements.

The DeProF algorithm simulations indicate that: for every oil-water-pore network system, optimum operating conditions exist for the r*(Ca) values for which the rate of global entropy production becomes maximum, i.e. when the process is as spontaneous as physically possible.

The conceptual statement introduced here is an initial approach towards implementing aspects of statistical thermodynamics to elucidate further the underlying physics of the process.
Improving Well Productivity through Openhole Frac-Pack Completion Design
Authors: Kamps Emil J. , Chando Jesse M. , Ellis Richard C.
Published: February 2011

Formation damage due to fines migration after the onset of water production presents a major technical challenge for many sandstone reservoirs around the globe. Oftentimes, significant productivity impairment is observed shortly after water breakthrough. This is particularly true for the Chad Doba basin lower "M" and "A" Sand reservoirs where studies have shown that a major contributor to this damage mechanism is the fluid velocity near the wellbore. As a result, exponential decline in productivity index is typically observed over very short periods.

To arrest the productivity impairment, various completion techniques were evaluated for ways to reduce the velocity of the produced fluids near the borehole. Typical completion designs employed to date have been cased hole gravel packs (including frac-packs) which enhances the velocity profile of the well as produced fluids converge to the perforations. Maximizing the reservoir to the wellbore interface reduces the velocity profile and conceptually prolongs the onset of formation damage caused by fines migration. Based on that conceptual model, openhole completion techniques were evaluated for feasibility. Upon analyzing the geology of the selected candidate, it became apparent that fracturing the formation was possible as it was a relatively thin amalgamated sand package. As a result, the openhole frac-pack concept became a practical option as it results in the lowest velocity completion possible by maximizing the reservoir surface flow area.

Openhole frac-pack completion activities were executed in mid-2009 and well productivity has been sustained even after water breakthrough. This paper reviews initial openhole frac-pack design concepts, execution lessons learned, and well productivity performance.
Making High Quality Frac Water out of Oilfield Waste
Authors: Hutchings Nathan R. , Appleton Eric W. , McGinnis Robert A.
Published: February 2011

Fresh water and affordable energy are two of the most valuable resources on the planet for sustaining economic growth and development. As the demand for oil and gas continues to increase, the fresh water consumption rate by exploration and production (E&P) activities is skyrocketing. Competition for fresh water is threatening to become an industry-limiting factor in some oil and gas plays. To ensure that the fresh water needed by the oil and gas industry is available in the future, better water resource management practices must be developed and implemented.

Currently, the drilling, completion, and stimulation of each horizontal shale well consumes up to 10 million gallons (gal) of fresh water, roughly equal to daily indoor water usage of 125,000 people [U.S. Department of the Interior March 2010]. Once fresh water becomes oilfield waste, the water is typically disposed of into reservoirs below the fresh water table, permanently removing it from the fresh water cycle. Reusing the water is desirable but often presents technical problems with water quality, water management logistics, and cost.

To help address these problems, a Forward Osmosis (FO) water reclamation process has been adapted for the oil and gas industry. The first generation of the process reclaims drilling waste water by converting it into high quality base fluid for hydraulic fracturing. In contrast to other water treatment systems, like reverse osmosis and evaporation, FO is a unique nano-filtration technology that harnesses the potential energy in a brine water solution as the drive mechanism, thus making the technology extremely "green" and cost competitive. Unlike conventional filtration to remove solids, the FO membrane rejects all solids and virtually all solutes from the reclaimed water, thus yielding a nano-pure water that will not react adversely with fracturing chemicals or the reservoir.

The results of laboratory and field testing from early commercial jobs show that FO is a viable technology for the reclamation of drilling waste for beneficial reuse as a high quality completion fluid. The results also show that FO can help significantly reduce both the carbon footprint and water footprint of the oil and gas industry.
An Analytical Model To Determine the Rheological Properties of Well Fluids Using a Novel Downhole Sensor
Authors: Rondon J. , Naughton Mac , Barrufet M. A. , Falcone G.
Published: February 2011

The ability to measure the true viscosity of formation fluids at downhole conditions is highly desirable in reservoir fluid characterization. A novel downhole viscosity sensor that can provide the real-time measurement of the viscosity of a flowing fluid at downhole conditions is discussed in this paper. The measurement can be obtained during open hole sampling of reservoir fluids, or during fluid profiling to characterize the reservoir properties at a vertical resolution much higher than that of traditional sampling methods. This leads to reservoir better understanding of the reservoir, leading to better decision-making with regards to field modeling, facilities planning and production optimization.

A prototype of a downhole sensor was previously calibrated and tested with fluids of 1-28 cP viscosity, under a temperature range of 100°to 160°F. The sensor's viscosity readings were validated against independent measurements taken with a Brookfield viscometer. Following on from that work, this paper presents a generalized mathematical model to describe the performance of the sensor with Newtonian and Non-Newtonian fluids. The model characterizes the response of the sensor as a function of the parameters from a power-law model rheological description and the geometry of the device. The previously gathered experimental data suggest the validity of this model for predicting the sensor response under realistic operating conditions. The model can be used to calculate optimum dimensions to fabricate a device for customized applications.
Successful Hydrofracturing Leads to Opening of New Frontiers in Shale Gas Production in the Cambay Basin in Gujarat, India
Authors: Sharma Shyam Sundar , Kulkarni P.K. , Kumar Anil , Pankaj Piyush , Ramanathan Venkateshwaran , Susanta Pande
Published: February 2011

Dholka, a small field situated in the Cambay basin of Gujarat consists of mainly oil producing horizons namely upper, lower, and middle pay. However, in a well D-A there is approximately 20 m interlaying shale above the upper pay showing a significant amount of C1 and C2 components evident from mud log showing yellow fluorescence. Around 24% of gas content was estimated, and hence, it was a considered as a potential source of gas pay that could be exploited using the hydraulic fracturing technique. This discovery occurred during the drilling and development phase for the lower, middle, and upper pay formations and is the first play in the field to have shale gas characteristics encountered. The change in cuttings and the show of gases in the chromatograph led to the careful collection of all the cuttings across these intervals, which were then sent for lithofacies and petrographic studies that confirmed that more than 50% of the facies are shale.

Apart from the upper pay and lower pay, an interesting shale pay zone was encountered in the well D-A during drilling. The hydrocarbon flow potential post perforating was very low because the formation was extremely tight. Hydraulic fracturing was critical for the successful producibility of such wells. To assess the maximum potential of both hydrocarbon bearing intervals, it was decided to hydro-fracture both shale and typical oil bearing intervals separately.

The planning and design processes of this project led to the successful execution of the hydraulic fracture. Encouraged by the results on the well D-A, another well D-B was similarly hydro-fractured as pilot test to explore shale gas in the area. Lessons learned from this successful experience have led Joshi Technologies to consider this source for further detailed exploration and development.
Case Study of Iraq: Education and Training Partnerships Among International Universities, IOCs, and NOCs
Authors: Van Kirk Craig W. , Baughman Gary L.
Published: February 2011

This paper presents a case study of the international partnerships among several universities in Iraq and the Colorado School of Mines (CSM) from the perspective of the CSM personnel involved over the past 35 years. Focus is on the several current and ongoing projects which occupy today's activities and which will continue to be active for some time to come.

These current innovative collaborations are partnerships which include CSM, one or more Iraqi universities, at least one International Oil Company (IOC), the Iraqi National Oil Company (NOC), South Oil Company (SOC), the Ministry of Oil, and the Ministry of Higher Education. The primary university programs which are engaged in these joint projects at this time are the petroleum engineering (PE) department at CSM and the PE departments at Baghdad University and other Iraqi PE-related universities. The primary project presented in this paper describes the current development of a new campus in Basra which focuses on serving the future needs of the oil and gas sector, which is known as the Basra Petroleum College (BPC).

The focus of these projects has always been, and continues to be, the oil and gas sector upstream Exploration and Production (E&P) disciplines of PE, geology (GE), and geophysics (GP); with appropriate attention being paid to and incorporating the other downstream and closely related groups of process engineering, petroleum economics, business management, and contracts and law.

Current and developing joint projects are described, along with an overview of the pertinent historical records which help explain how such partnerships develop and why some are more successful than others. The paper addresses knowledge transfer in PE education (and the several other disciplines identified above) at the undergraduate and graduate levels, university research, training industry and government professionals, and the essential roles of NOCs and IOCs in providing their guidance and financial support.

This paper is one of a series of connected papers and should be reviewed in conjunction with two other SPE papers by these same authors, as shown in the References.
Analysis of Nitrogen Stimulation Technique in Shallow CBM Formations
Authors: Settari A. (Tony) , Bachman R. C. , Bothwell P.
Published: February 2011

Nitrogen (N2) stimulation has become the preferred technique for stimulation of coal seams in the Horseshoe Canyon play in Alberta. It consists of stimulating each seam by pumping at very high rates for short time (2-4 mins). Because the coal is producible at shallow depths, ERCB has been developing and updating regulatory guidelines that aim to protect the freshwater supply.

This study was undertaken to improve the understanding of the process and provide recommendations on the regulatory guidelines for shallow depth (less than 200 m). The study was provided with extensive data from the industry (over 20,000 fractures in over 2000 wells) and has carried out several types of analyses in order to estimate fracture orientation and dimensions, and their dependence on N2 injection rate, duration and reservoir parameters. This included statistical analysis of large amounts of surface pressure data, pressure transient analysis of downhole pressure data, analysis of fracture mapping data, and conceptual simulations of the injection process using coupled reservoir and geomechanical models. Coupled geomechanical modeling provided realistic physical model of the process (in contrast to conventional models). Stress dependence of coal permeability and permeability anisotropy were shown to be the controlling mechanisms. This model was then used to investigate height growth mechanisms.

After considering the results of the analysis, its limitations, uncertainties in geological description of the coal and shale sequences, available case histories, and other factors, recommendations were made for modifications of the ERCB Shallow fracturing Directive 27.
Comprehensive Approach to Severe Lost Circulation Problems in Russia
Authors: Collins Natalia , Kharitonov Andrei , Whitfill Don , Miller Matthew
Published: February 2011

In the past, a favored approach may have been used to treat most or all lost circulation incidents. However, improvements in understanding all aspects of lost circulation show that the “favored approach” method can be technically unwise today. The delineation of fracture geometry induced during drilling, based on rock properties, may point out significant differences in the length and width and severity of anticipated induced fractures. Major differences in permeability between shale, sandstone and vugular limestone also show immediately that “one-size-fits-all” solutions are not going to be effective or efficient. When possible, these types of information need to be incorporated into any plan for controlling lost circulation.

Lost circulation is a principal culprit in drilling non-productive time (NPT). Generally speaking, the drilling industry handles lost circulation much as it did many years ago, but new modeling and operational techniques are changing industry perceptions. The petroleum industry has invested a significant effort into understanding the mechanisms behind lost circulation, developing new tools to help locate the thief zone, and implementing new steps to minimize or eliminate this problem.

Controlling loss of circulation during well construction is more than just selecting the proper type of lost circulation material (LCM). A fully engineered wellbore stress management (WSM) approach is required. During the planning phase, this approach incorporates borehole stability analysis, equivalent circulating density (ECD) modeling, leak-off flow-path geometry modeling, plus drilling fluid and LCM material selection to help minimize effects on ECD.

During the execution phase, real-time hydraulics modeling, pressure-while-drilling (PWD) data, connection flow monitoring techniques, and timely application of LCM and treatments are proving to minimize and in some cases eliminate losses in high-risk areas.
Multiphase Flow Splitting in Parallel/Looped Pipelines
Authors: Alvarez L. , Mohan R. S. , Shoham O. , Avila C.
Published: February 2011

A novel and unique experimental facility was design, constructed and instrumented, enabling slug flow splitting data acquisition in both parallel and looped lines. A total of 81 experimental test runs were carried out for various superficial gas and liquid velocity combinations. Uneven split conditions data were acquired by utilizing either a choke valve on one of the lines or different pipe diameters. For the symmetrical configurations of both parallel and looped equal diameter lines, the phases split equally in the lines. When the parallel and looped lines are of different resistance to flow (utilizing a choke installed on one of the lines or different line diameters), uneven split of the phases occurs. The gas-phase flows preferentially into the smaller resistance line. This results in different gas-liquid ratios in the two lines, which are different from the gas-liquid ratio at the inlet. A mechanistic model has been developed for the prediction of the uneven gas and liquid splitting and the pressure drop in two-phase looped lines. Good agreement is observed between the model predictions and the experimental data, with an average error of about 15% in the phase splitting and pressure drop.
Direct Method of Estimating Average Reservoir Pressure for Flowing Oil and Gas Wells
Authors: Agarwal Ram G.
Published: February 2011

A knowledge of the average reservoir pressure (p¯) and its changes as a function of time or cumulative production is essential to determine the oil-in-place (OIP) or original gas-in-place (OGIP), to estimate reserves and to track and optimize reservoir performance. The common practice of determining p¯ in moderate permeability reservoirs has been to run pressure buildup tests. In the current economic environment, buildup tests are almost non-existent except for very expensive exploratory wells. Moreover, time required for a pressure buildup test to reach p¯ in low permeability reservoirs is prohibitively long. Fortunately, flowing pressures and rate data are continually collected from oil and gas wells. Data quality and quantity is usually good especially from wells installed with permanent pressure gauges. Such data for gas wells is currently being analyzed by assuming OGIP and estimating p¯ required for calculating pseudo time. This is done in an iterative manner for using advanced decline curve analysis methods.

The purpose of this paper is to discuss a new finding that will enable direct estimation of p¯ using flowing pressures and rate data obtained from oil and gas wells during the pseudo steady-state flow period. In theory, pseudo steady-state flow requires that a well is produced at a constant rate. However, this limitation can be easily removed based on the work published in the SPE literature by this author and others whereby variable rate data can be converted to constant rate production data.

The significance of the subject paper is that it will permit: a) direct determination of p¯ using flowing wellbore pressures and rate data thus facilitating estimates of OGIP and OIP, b) estimation and/or validation of the value of the initial reservoir pressure (pi), which is normally suspect, and finally, c) enhancement or possible elimination of the current iterative process used for determining OGIP by advanced decline curve analysis methods.
Variations in Permeability of Coals-The Importance of Stress Path
Authors: Gray Ian
Published: February 2011

This paper examines the factors which influence the permeability of coals with particular reference to coal stresses and mechanical properties including cleat spacing, Young's Modulus, Poisson's ratio and the effects of shrinkage caused by the loss of gas and water. This paper updates the work of the author in published in1983 (SPE 12514). The approach presented is mathematically based with reference to field examples and laboratory work. These include measurements of stress and permeability. The application of the work is in establishing how the permeability of a coal seam will vary during production.

The prime contribution is a theoretically sound, experimentally based, unified approach to determine the effective stress path and hence gain an indication of permeability changes through production.
Reservoir Pressure and Well Performance in Multi-well System
Authors: Khasanov Mars , Krasnov Vitaly , Musabirov Timur , Yudin Evgeniy
Published: February 2011

Novel simplified method of well performance calculation in multi-well system is considered. Differences between engineering content of various pressures in multi-well system traditionally denoted by one term "reservoir pressure" are shown. A new terminology to designate these pressures and estimation methods based on production and well test data are proposed.

In practice due to the complexity of well productivity analysis in multi-well system single well is often "extracted" from the environment. The influence of neighboring wells is taken into account by assigning for each well a certain value of reservoir pressure at the certain drainage area. At first glance, this simplification procedure seems so natural that does not require any justification. However, unlike the unambiguous and well-defined single well concept of "reservoir pressure", for wells in multi-well system this approach depends strongly on the context. In order to distinguish the concepts traditionally designated a single term "reservoir pressure" the definition of three types of pressure is introduced. Instantaneous and static reservoir pressures are the local parameters describing well performance subject to interference effects. The average (integral) reservoir pressure characterizes the energy state of the reservoir in whole. For the case of a single well system all these pressures are equal that creates the semantic difficulties in multi-well system consideration.

Reservoir pressures proposed can be used to provide well productivity calculations at different time periods after the change of well operation conditions. Instantaneous reservoir pressure enables to determine production rate changes at the end of transient flow regime and static reservoir pressure gives an estimation of production rate reached at the new steady state regime. The impact of well operation condition changes to the performance of surrounding wells can be also analyzed.
Innovative Design Features on PDC Bit Result in Record Run in Orenburg Region, Russia
Authors: Mortimer Laurence
Published: February 2011

The oil and gas fields in the Orenburg region are some of the oldest and largest in Russia. Drilling through carbonates with low mud flow rates is common in this region along with the associated challenges that these conditions present to polycrystalline diamond compact (PDC) drilling. This paper details how these conditions and others, were addressed as part of the design process culminating in a novel bit design with appreciably higher penetration rates and associated cost savings.

Having encountered a series of unusual dull conditions on PDC bits run in Orenburg, a systematic design approach was adopted in order to solve a series of specific regional issues resulting in new design features which lend themselves to other applications worldwide.

The team established that the best practice for drilling a particular vertical section in this region was to use a bent motor due to experiences of uncontrolled deviation close to total depth (TD). The objective was therefore not only to take into consideration the carbonate formation and flow rate issues, but also to establish the effect of the bent housing on PDC bits in order to improve the bit condition and overall performance.

Subsequent 3D CAD modeling and analytical studies enabled a common approach design solution for both bent housing and carbonate type applications. These studies, together with Computational Fluid Dynamics (CFD) analyses, enabled new innovative design features to be introduced into the bit to address hydraulics, formation and eccentric bit rotation. These new features resulted in far superior drilling performance and dull characteristics, which ultimately led to record runs being achieved in the region over a 1200m section of predominantly carbonate, inter-bedded formation.

The features would also prove to be transparent to the drilling contractor should they be running a bit on a straight or bent housing motor with low or high flow rates, thus acting to enhance the existing drilling practices in the region.
A New Model For Wellbore Stability And Stress Prediction In Underbalanced Wells
Authors: Moos Daniel , Perumalla Satya , Kowan Julie , Finkbeiner Thomas , Peska Pavel , Van Der Zee Wouter , Brudy Martin
Published: February 2011

We have developed a new analytical model for underbalanced drilling (UBD) that takes into account that rocks have scale dependent strengths, that the full stress concentration is not developed at a given depth in a well until sometime after the drill bit has passed, and that fluid flow into the advancing wellbore leads to a zone of locally lower pore pressure surrounding the well that extends beneath the drill bit. The model predicts regions within which compressive shear failure will occur and also provides predictions of where spalling (tensile failure) is a possibility. The results provide a more realistic and less conservative prediction of wellbore risk than models developed to study the stability of overbalanced wells. This new model can be applied to predict whether underbalanced operations are possible in a given well, and also the severity of wellbore instability as a function of underbalance. In addition, the model allows constraints to be placed on the in situ stress field (magnitudes and orientations) based on observations of wellbore failure in wells which have been drilled underbalanced. Wells designed utilizing model predictions were drilled without incident, and the model also provided reasonable predictions of the state of stress.
4D-Seismic to Support the Astokh Field Development Offshore Sakhalin
Authors: Boekholt Martin , Broker Koen , Bell Doug , Terwogt Dorine
Published: February 2011

In June 2010 Sakhalin Energy Investment Company Ltd. (Sakhalin Energy) successfully acquired a 4D seismic survey offshore Sakhalin covering the Astokh oil field development. This survey is the first 4D seismic survey carried out in Russia. The aim of this survey is to aid further field development optimization and infill drilling in the Astokh field, onstream since 1999. Rock property and 4D-seismic modeling studies indicated that hydrocarbon saturation and pressure effects can over time potentially be identified with 4D repeat seismic surveys. Feasibility studies were followed by the acquisition of a seismic test line in autumn 2009. This test showed amplitude and time differences at reservoir level in the seismic section when comparing the 2009 test line with the 1997 pre-production seismic survey. These differences can be correlated with the production history. Disturbances of seismic events were minimized by accounting for azimuthal velocity anisotropy during seismic data processing.

The proximity of the Astokh field development to the feeding grounds of the Western Gray Whales (WGW) offshore Sakhalin was fully taken into account for the planning and execution of this seismic survey. To this extent, Sakhalin Energy has benefited from collaborative efforts with independent scientific bodies and the Russian Government. This collaboration with recognized Russian and International scientific experts has yielded an exemplary set of monitoring and mitigation measures to protect the whales, whilst allowing responsible surveying activities to proceed without unnecessary delay. This includes: Execution of the survey as early as possible in the summer season, when the sea is ice-free and before the whale-feeding seasonReal-time measurement of acoustic sound generated at the edge of the feeding area to steer operationsStrict operating and shut-down criteria when WGWs are observed in the near-survey feeding areaContinued monitoring of distribution and behavior of the WGWs during and after the survey
New Methods and Treating Units for Electrical Dehydration and Desalting of Oil
Authors: Shvetsov Dr. V.N. , Yunusov Dr. A.A.
Published: February 2011

In recent years, due to the switchover of the increasing number of fields to mature production stages characterized by high water cut and mineralization of wells production, and due to extensive involvement of heavier carbonic oils forming high- resistant emulsions into development as well, which is more significant, the problem of oil preparation for its refining becomes more pressing at a time, when the requirements for commercial oil have toughened.

Among all presently known methods of oil demulsification the most progressive and efficient ones are the methods of electrical demulsification [1, 2], used both at the stage of deep dehydration (as a rule) and at the stage of deep desalting under field and refinery conditions (always). Deep desalting of the oil coming from fields (up to 3÷5 mg/dm3 of salts) to Refinery, particularly, is achieved only with application of electrical dehydrators.
The Role of Fault Seal of Middle Miocene (Chokrak Formation) Fields at Northern Edge of West Kuban Trough in Fluid Migration Throughout Reservoir Development
Authors: Derduga A.V.
Published: February 2011

One of the basic objects of exploration works and hydrocarbon extraction in Krasnodar territory in recent decades are Chokrak depositions in the northern edge of West Kuban Trough. About twenty light oil and gas condensate deposits were discovered there. In the 90’s and 2000’s the major scope of seismic studies and drilling activities were concentrated in this direction.

Most of the fields discovered are related to tectonic (disjunctive) faults and deformational traps. Genetically disjunctive tectonics is represented by listric faults having their roots in middle-upper Maikop and their flattening in Sarmatian-Meotic stratum. Faults have great influence both on deposit formation, and on the process of hydrocarbon extraction. It is necessary to understand and forecast fluid penetrating ability of disjunctive dislocations in order to create and improve geological models both during exploration works, and in the course of field development. The estimation of breakdown pressure value sufficient for tectonic disturbance fracturing can be also used during drilling of wells with a view of reducing risks of drilling mud loss and loss of circulation.
New Approach in Real-Time Bit Wear Prediction
Authors: Rashidi B. , Hareland G. , Wu Z.
Published: February 2011

Challenging wells have been drilled recently utilizing advanced real time tools and techniques to optimize drilling operation while reducing risk and increasing safety. Moreover, the real time tools and techniques help identify upcoming drilling problems using real time data before they occur. Real time drilling analysis begins when real time drilling data are available and transmitted to the office locations via a remote server. The data can then be interpreted and analyzed by the engineers implementing various models for appropriate decision making. Lately, real time bit wear estimation has been a challenge in drilling a well to reach to the highest drilling performance and avoid bringing serious problems to the bit.

It has been shown that the combination of Mechanical Specific Energy (MSE) and drilling rate models can be used for real time bit wear estimation while drilling. As MSE does not take the bit wear effect into account while drilling rate or rate of penetration (ROP) models do, their difference can be used to monitor and identify bit wear status while bit is in the hole. This paper demonstrates a new form of a developed model to predict bit wear status while drilling which is built by combining rock energy (MSE) model with a newly developed drilling rate model for roller cone bits as well as a previously developed model for PDC bits. Rock confined compressive strength (CCS) is obtained from ROP models and used in conjunction with MSE values to predict bit wear trend. Several bit run sections from offset wells in Alberta, Canada were tested utilizing the model and final results are compared with the reported bit wear outs from the field. Encouraging results show that this methodology can be applied to detect changes in drilling efficiency by monitoring bit wear trend in real time while drilling.
Special Issues of Well Test Design and Analysis for Fractured Wells in Waterflood
Authors: Khasanov Mars , Krasnov Vitaly , Musabirov Timur
Published: February 2011

Novel approach to well test design and analysis for the wells with hydraulic fractures in waterflooded reservoirs is considered. General pitfalls and misuses of single well approach when applied to such systems are shown. It is revealed that for many practically important fractured wells cases conventional methods of infinite-acting radial flow regime identification are inapplicable. New technique of radial flow identification for such wells and capturing neighbor wells impact is introduced, practical examples are considered.

Approach proposed is based on the exact line-source solution in the form of integral exponent unlike the traditional method of interpretation which implies the logarithmic approximation. It is shown that for wells with highly conductive extensive fractures typical time of the beginning of logarithmic approximation can substantially exceed the actual time of the beginning of infinite-acting radial flow. In this case end of bilinear flow and beginning of radial flow can be estimated based on reservoir permeability assumptions or on comparison of the bottomhole pressure dynamics with exact line-source solution for a radial well with effective radius.
Utilization of Associated Petroleum Gas (APG) —the Norwegian Experience
Authors: Hinderaker Leif , Njaa Steinar
Published: February 2011

The goal of any petroleum producing country is to maximise the long-term social value of the hydrocarbon assets. To protect society's interests in development and operation of oil and gas fields, the Norwegian authorities have established frameworks for these activities, which are intended to ensure that the companies makes decisions that are also beneficial to the society at large.

In Norway the Norwegian Petroleum Directorate (NPD) has the authority to monitor the development of the different oil and gas fields and to ensure that the fields are being produced in accordance with best practice reflected in regulations and the framework established.

As for use of associated gas the regulation pertaining to proper utilization of the petroleum resources has been of paramount importance. In the regulations it is stated that flaring of petroleum is not allowed, unless in quantities needed for safe operation.

From day one the oil companies thus had to find a proper way of utilizing the associated gas. In most cases the gas was transported in pipelines and sold to the market, but in some cases there was no pipeline available and re-injection into the reservoir was the only option.

Improved recovery has been and still is of great concern for Norwegian authorities. Several initiatives have been made to evaluate the possibilities for improving oil recovery. The results of gas injection have been studied together with other methods for enhancing the oil recovery. For the Norwegian oil fields pressure maintenance by use of associated gas has proved to be very successful.

By the end of 2009 and since the oil production started on the Norwegian Continental Shelf in 1971 a total of more than 3526 million Sm3 of oil and 2138 billion Sm3 of gas has been produced. Most of the gas produced has been exported to the European market. Some gas has been used as fuel on the platforms and for transportation purposes and a small amount has been used in Norway as feed-stock for petrochemical plants.

Due to strict regulations and economical incentives just a minor part has been flared. However it is reported that gas in the order of 595 billion Sm3 has been re-injected into the reservoirs to sustain pressure and to enhance oil recovery. The average oil recovery factor for fields in production today is estimated to be 46%. It has been estimated that re-injection of gas so far has yielded an extra oil recovery of between 240 and 270 million Sm3 oil and condensate compared to the case without gas injection. If existing plans for further gas injection are executed, the total gains are in the range 320 to 360 extra million Sm3 oil and condensate.
Integrated Modeling of Fracture System and Evaluation of its Impact on Carbonate Heavy Oil Reservoir Performance
Authors: Ursegov Stanislav , Taraskin Evgeny , Chertenkov Michail , Habig Pierre , Ranjan Amit
Published: February 2011

In the Usinsk field located in the Timano-Pechora region of Russia, heavy oil is produced from vuggy-fractured carbonate Permian-Carboniferous reservoir. It has a more than 30 years history of operations and has produced mostly by natural water drive and in some pilot areas by hot water and steam injection. The presence of fractures highly affects the reservoir performance and is critical for current and new pilot projects of steam injection efficiency.

This study presents an integrated approach to characterize and model the fractures, and assess their dynamic impact in the south-west (SW) sector with 85 wells where new steam injection pads are being organized.

The approach included the detailed analysis of available core data, FMI logs, 3 D seismic, production data, well testing, etc, fully integrated by a unique advanced technology. The obtained results of the characterization allow developing the discrete fractured model of the SW sector which takes both into account the effect of seismic faults and several sets of diffuse fractures related to the fold structure of the reservoir.

The fracture model was then tuned and verified using the well test results to match KH and pressure responses. The end product was a 3 D model of the equivalent fracture parameters (permeability, porosity, and matrix block size) directly usable for the dual - porosity dual - permeability model reservoir simulation.

The conducted simulation runs confirmed the significant improvement of the history matching process using the created model and its applicability to clarify the effect of the fracture system on natural water flooding and steam injection results in the SW sector of the reservoir.
Effects of Pressure, CO2 Volume, and the CO2 to Water Volumetric Ratio on Permeability Change During CO2 Sequestration
Authors: Mohamed I. M. , He J. , Mahmoud M. A. , Nasr-El-Din H. A.
Published: February 2011

Carbon dioxide sequestration in underground formations is being considered on a massive scale to reduce the amount of CO2 emitted into the atmosphere. However, a better understanding of the chemical and physical interactions with formation fluids and rock is necessary before implementing sequestration in a depleted reservoir, aquifer, or during enhanced oil recovery operations. These interactions are affected by many parameters, including pressure, temperature, brine salinity, and CO2 injection rate. They can be evaluated by the change in water composition before and after injection, or from the change in CO2 injectivity over time. CO2 may affect the permeability positively due to carbonate rock dissolution, or negatively due to precipitation of reaction products, mainly CaCO3.

CO2 dissolves in the formation brine, generating carbonic acid, which dissolves carbonate rock. Dissolution impacts brine composition, which affects solubility. Calcium carbonate may tend to precipitate with changing concentration of bicarbonates. Precipitation may occur in either EOR operations or during primary CO2 sequestration. Injectivity changes are a concern during EOR operations, while storage capacity and seal integrity are primary concerns during CO2 sequestration. This paper addresses the effect of the pressure, injected CO2 volume, and the CO2 to water volumetric ratio during water alternating gas (WAG) operations on precipitation and the relative impact of dissolution or precipitation on the formation injectivity.

A core flood study was conducted using limestone cores. CO2 was injected under supercritical conditions at a pressure of 1,300 psi, and a temperature of 200°F. Core effluent samples were collected and the concentration of calcium ions was measured.

The results showed that the outlet pressure had the greatest effect on the bicarbonate presentation. Keeping the outlet pressure below the supercritical pressure of CO2 minimized precipitation of calcium carbonate. Additionally, maintaining the CO2/water volumetric ratio above 1.0, reduced bicarbonate formation in the formation water and helped in minimizing precipitation of calcium carbonate.
Further Developments and Application of a Real-Time Directional Drilling Digital Interface
Authors: Torres Russel , Gawski Victor , Snyder John , Kharitonov Alexander
Published: February 2011

This paper describes the further development of a real-time directional drilling digital interface (DDDI) that dynamically illustrates many aspects of the directional drilling process, specifically those that apply to positive displacement downhole drilling motors (PDM), rotary steerable systems (RSS), and motor driven rotary steerable systems (MD-RSS) while operating downhole.

The ongoing development of advanced drilling engineering packages and intelligent downhole drilling tools provides increasing amounts of available drilling-related data. The DDDI uses data supplied by means of an existing real-time, rigsitebased drilling information acquisition and database system to help to address many of the challenges encountered during directional drilling. The interface processes data based on engineering models, empirical knowledge, and technical data; it presents dynamic operating parameter information and graphical representations of functioning downhole drilling equipment. Subject matter experts located in diverse global areas can remotely access the interface to observe and to contribute to multiple drilling applications.

This paper provides details about the further development of the existing interface and its application to better optimize the real-time directional drilling process and to promote a balanced downhole system approach. The results have included reduced drilling equipment wear and damage, greater reliability, and reduced drilling costs.

In addition to downhole motor and rotary steerable system applications, the DDDI was used during downhole motor-driven rotary steerable system (MD-RSS) operations; benefits were realized through the simultaneous monitoring of both rotary steerable tools and PDMs.

After achieving real-time benefits in diverse global locations through the additional technical capabilities of the enhanced version of the DDDI, the potential benefits of a Russian language version were identified. The Russian language version enhanced the collaboration between English- and Russian-speaking personnel.

The most recent DDDI version aids in the comprehensive conceptualization, reporting, and control of directional drilling operations. It has a positive effect on the overall drilling process and expands the technical knowledge base, which provides additional support of the directional drilling expert system objective.
Fractal Description of Pore Structures of Low Permeability Oil Reservoirs and its Relationship with Gemini Surfactant Flooding
Authors: Wei Heng , Liu Junhan , Wei Guoqi , Liu Xiangui , Liu Weidong
Published: February 2011

Gemini surfactant flooding is a promising technique to enhance oil recovery from medium-high permeability oil reservoirs. The screening of the gemini surfactants are mainly based on their capability of lowering the surface tension between oil and water. However, gemini surfactants with high capability of lowering the surface tension do not necessarily enhance oil recovery from low permeability oil reservoirs. Based on fractal method and the mercury injection curve data, the fractal dimensions of the pore structures of low permeability oil reservoirs are different from those of medium-high permeability oil reservoirs. Based on the fractal dimensions of molecular fragments, the fractal dimensions of gemini surfactants are in relation to the fractal dimensions of the pore structures of low permeability oil reservoirs.

Based on the fractal dimensions of the pore structures of low permeability oil reservoir Z and molecular fragments, gemini surfactant D is designed and applied in developing the reservoir. Gemini surfactant D enhanced oil recovery 5% more than conventional gemini surfactants.

The fractal dimensions of the pore structures of medium-high permeability oil reservoirs range from 2 to 3. The fractal dimensions of the pore structures of low permeability oil reservoir Z are less than 2. The fractal dimension of the spacer group should match with fractal dimensions of the pore structures. The gemini surfactants are absorbed more onto the rock surface as the spacer groups of the gemini surfactants are less complicated than the rock surface.

Fractal dimension is supplementary to the parameters (permeability and porosity) that are used to estimate low permeability oil reservoirs. Low permeability oil reservoirs which were not able to be developed are able to be developed. This helps more and more low quality reserves be turned into producing reserves.
Best Practices & Innovations for Improved ESP Performance; Mature Field Case History; TNK-BP Company, Russian Federation
Authors: Borling Daniel C. , Sviderskiy Sergey V. , Gorlanov Sergey F.
Published: February 2011

Leadership, teamwork and technical ingenuity were critical strategy elements that resulted in an 82% run life improvement for Electric Submersible Pump (ESP) systems in the TNK-BP Company. During the past four years, the 12-month rolling Mean Time Between Failure (MTBF) steadily improved from 295 days during January 2006 to the current 541 days in July 2010. This 246 day improvement was achieved across more than 14,250 ESP’s and achieved $307 million value to date.

This case history paper contains insights, best practices and technical innovations used by TNK-BP to safely improve relatively low ESP run life. As of July 2010, TNK-BP had 15,700 active producing wells and approximately 98% used some form of artificial lift. Average production was 200,000 tonnes of oil per day (1.5 million barrels per day) from more than 200 mature fields across Western Siberia and Orenburg region.

The most significant insight during the past four years was the amount of effort it took to change the way the Company viewed ESP run life.

TNK-BP improved ESP equipment reliability with specific technical protocols and innovations. Benefits from longer run time resulted in less deferred oil, reduced equipment repairs, fewer new replacement equipment purchases and better deployment of rigs to perform other production enhancing wellwork. An important technical learning early in the program was reduced early-time failures. A TNK-BP best practice was its ESP MTBF Sector Team for unified communication of strategy, work plans and learnings across 14 regional businesses.

Understanding true root causes for ESP failures had a profound effect for improved run time. TNK-BP participated in the Joint Industry Project called ESP- RIFTS (Reliability Information and Failure Tracking System) and developed its own “state-of-the-art” failure analysis methodology to better classify failures across the Company.