bluuebunny/crossref_metadata_2025 huggingface dataset:
Re-habilitation Plan for a Mature Oilfield On-shore Azerbaijan – Working Both Ends of the Spectrum
Authors: Maxwell Phil , Haskell Joe , Eisenbart Allan , Larijani Ray , Bischke Dick , Berent Louis , Butter Machiel
Published: December 2007

Old oil fields with a many years of productions and large mostly low productive well-stock present a new owner/operator with an interesting challenge in defining the its strategy. The low risk approach is an extensive work over recompletion program to bring back shut-in production and reduce water-cut. However in some cases this can be considered throwing good money after bad with insignificant incremental increase in production. The second approach is extensive infill and possibly exploration drilling to open new zones in the deeper part of the structure or adjacent structure. This is considered the higher risk strategy but the rewards in incremental increase in production can be great, as this could be many time larger that current production of the field.

This paper supports a two pronged strategy from both end of the spectrum namely geology and production engineering for optimium short and long term benefits and NPV supported by the following maxims ❖Know what you do not know about the geology and dynamics of the field❖Get the data that you need, eg invest in 3D seismic, run PLT's❖Take an integrated geoscience/engineering approach❖Use your gained knowledge to understand risk and options, vanilla solutions do not always present the best ROI

This paper demonstrate how this two pronged strategy was applied to the Kurovdag field in Azerbaijan and how a rejuvenation and re-development plan for the field was developed in conjunction with the operator of the field.
Chemical Stimulation of Gas/Condensate Reservoirs
Authors: Kumar V. , Bang V. , Pope G. A. , Sharma M. M. , Ayyalasomayajula P. S. , Kamath J.
Published: December 2007

Significant productivity loss occurs in gas-condensate wells when the bottom hole flowing pressure drops below the dewpoint pressure. The decline in productivity is due to nearwell accumulation of condensate in the reservoir rock, which is significant even for wells producing very lean gas with liquid dropout values less than 1%. Many different methods such as hydraulic fracturing, dry gas injection and solvent injection have been proposed and implemented to stimulate such wells. However, all of these methods offer short-lived stimulation and are sometimes not profitable. New experimental core flooding data using chemical treatments show that the steady-state gas and condensate relative permeability in both outcrop and reservoir sandstones can be increased by a factor of 2 to 3 over a wide range of temperature (145 to 275 °F). Spectroscopic data show that the sandstone surface remains modified by the chemical even after flooding the core with large volumes of gas. A relative permeability model that includes effects such as the decrease in the residual condensate saturation after treatment and the effect of capillary number is presented. Fine-grid compositional simulations of a single-well treatment were done using the calibrated relative permeability model to investigate the performance of chemical treatments under field conditions as a function of variables such as treatment radius. These simulations show that chemical treatments have the potential to greatly increase production at low cost relative to the increased revenue since only the near-well region blocked by the condensate needs to be treated.
Effect of Reservoir Mineralogy and Texture on Acid Response in Heterogeneous Sandstones
Authors: Morgenthaler L. N. , Zhu D. , Mou J. , Hill A. D.
Published: December 2007

A series of core flood experiments with the sequence of fluids typically used in HCl/HF stimulation (HCl pre-flush, followed by HCl/HF main flush, followed by NH4Cl post flush) have been conducted on a suite of cores from several Gulf of Mexico Miocene turbidite reservoirs. Using thin section petrography and computer tomography (CT) scans; the samples were characterized as more or less heterogeneous. Samples ranged from reasonably homogeneous to highly laminated. Sample mineralogy was assessed by X–ray diffraction (XRD). Core compositions ranged from relatively clean (quartz rich) to relatively "ratty" (clay and feldspar rich) and some cores contained abundant clinoptololite zeolite.

Acid response was assessed based on permeability change and effluent chemical analysis and varied dramatically among the samples. In the poorer quality, more laminated samples, channeling with significant permeability increase was observed during HC1 treatment with little additional change during later stages of the treatment. Selective pore enlargement with little alteration of the matrix framework was observed in post treatment thin sections. In more homogeneous sand samples, more general acid attack was observed. Core effluent indicated carbonate dissolution during the HCl pre-flush, while HCl/HF clearly attacked alumino-silicates and was roughly half spent during transit through the core. Comparison of thin sections before and after acidization revealed changes in sample quality. In the better quality samples, near complete (greater than 80 percent) dissolution of carbonate and an extensive "cleaning" of clays and fines from the pore space was apparent.

We used a fine-scale simulator of sandstone acidizing to match the responses observed in these experiments. The model corroborates the effects of heterogeneities in the permeability field and in the mineral distribution on the sandstone acidizing process. These model results show how characterization of fine-scale heterogeneity in sandstone can improve the design of matrix stimulation treatments.
Compositional and Grid Orientation Effects in History Matching
Authors: Eydinov D. , Aanonsen S. I. , Haukås J. , Aavatsmark I.
Published: December 2007

A method for automatic history matching of a compositional reservoir simulator is presented. By coupling a gradient minimization algorithm with a forward simulator and an adjoint equation solver, permeability and porosity fields may be conditioned to production data and prior geological information, provided the permeability and porosity can be described by Gaussian random fields. However, the validity of permeability and porosity fields obtained from history matching relies on an accurate forward modeling. We have developed an automatic history matching code, based on the adjoint method, with a fully compositional, 3-dimensional, simulator utilizing a general, IMPSAT or fully implicit solver, as well as advanced discretization techniques based on the Multipoint Flux Approximation (MPFA). The compositional IMPSAT formulation reduces to a traditional black-oil formulation when the number of hydrocarbon components is equal to the number of hydrocarbon phases. Application of the simulator to several synthetic history matching cases is presented. It is shown that if the grid is distorted, permeabilities estimated using a simulator based on the traditional two-point flux approximation (TPFA) may be significantly wrong. It is also demonstrated that information about fluid component rates may be useful in the history matching process.
Improving Hydraulic Frac Diagnostics by Joint Inversion of Downhole Microseismic and Tiltmeter Data
Authors: Warpinski N. R. , Griffin L. G. , Davis E. J. , Grant T.
Published: December 2007

Downhole microseismic and downhole tiltmeter mapping are the primary direct diagnostic techniques for monitoring the geometry of hydraulic fractures at depth. Although these techniques have seldom been used together because of a lack of available monitor wells, the advent of new hybrid arrays having both microseismic receivers and downhole tiltmeters has now made application of both technologies from a single well possible. This paper discusses algorithms for joint inversion of the combined data along with the development of hybrid arrays for combined tiltmeter and microseismic. Examples from several data sets show how the combined results can be used to improve velocity models and obtain better constrained-height estimates, as well as improved confidence in other fracture geometry parameters.
Field Tests of Sulfide Removing Biologically in Surface Systems
Authors: Dongsheng L. , Hongqi Z. , Jianxing C. , Xishou S. , Wang Z.
Published: December 2007

Biogenic sulfide is really troublesome in many produced water associated surface systems. The problems include iron sulfide (FeS) pluggings (equipment and near-borehole formation), excess solids, emulsion, and H2S related corrosion, toxicity, and reservoir souring as well. Cost effectively mitigating the serial problems is quite challenge and very costly because sulfide related problems often occur in produced water treatment systems, oily sludge system, injection system and extent to reservoir. Waterflooded reservoirs can offer conditions for growth of the sulfate reducing bacteria (SRB) that would convert sulfate to sulfide constantly, and polymer and chemical tertiary recovery implementation contributes sulfide in the reservoir as well.

In recent years, many surface facilities including three-phase separators, produced water treatment stations, oily sludge systems and injection systems in Daqing oilfield not only have server the sulfide problems, but also cause electric dehydrator systems power-off because of the high conductivity FeS layer forming, which resulted of FeS emulsified with skimmed oil returning to the dehydrator systems. As a result, normal operation has been disrupted constantly and safety has been a major concern as well in those facilities.

In this paper, we present test results from three fields using the microbial technique for sulfide removing in the produced water and oily sludge, and how we did it to achieve better results in a very cost-effective manner.

By applying this microbial sulfide removal technique efficiently prevents floating/skimmed and sludge oil aging in gathering systems, and improved produced water treatment efficiency and reduced the facility corrosion for the entire oil produced fluid treatment plants. In other word, the proposed application technique can effectively put sulfide related problems under control not only in isolated facilities and short term, but also in the entire system and long term.
Modeling and Analyzing Source and Interference Data from Packer-Probe and Multiprobe Tests
Authors: Larsen L.
Published: December 2007

This paper addresses practical aspects of modeling and analyzing source and interference data from tests with a dual packer or a single or double probe source combined with a single interference probe along a vertical or deviated wellbore. Although several authors have addressed such models, there are practical issues and problems that have not been discussed in detail. The present paper addresses all aspects of such tests, starting with simple analytical models and emphasis on the use of both diagnostic loglog, semilog and Cartesian plots to match and interpret the test response. The paper also addresses effects of uniform and non-uniform layering, and the use of probe data to choose the effective thickness for the source response, e.g., for a dual-packer test.

Effects of non-uniform layering are important since such cases cannot be analyzed with a consistent single layer model with packer or probe(s) source and a point (probe) for the interference response. Of special interest are cases with low-permeability layers between the source and the probe, with the source and probe data affected quite differently by changes in the location of such layers.

Also addressed in the paper are restrictions on rate, test duration and formation properties to obtain analyzable data. This has to do with gauge resolution and the inherent low rate in such tests. Screening guidelines are presented to determine if a good test can be obtained based on expected formation properties. This involves both the source and probe data.

Field data from three packer-probe tests from the Norwegian Continental Shelf have also been included in the paper to highlight some of the practical issues associated with such tests. All three cases were successful, although one is clearly affected by formation complexities that cannot be handled by a simple homogeneous model.
Boundary Effects and Depth of Investigation from Long Buildups Following Short Flow Tests
Authors: Larsen L.
Published: December 2007

Slug tests and other tests with the buildup period greatly exceeding the flow period have been addressed in the literature by several authors over the last 30 years. The present paper takes a new look at such tests with a primary objective to investigate the possibility of drawing conclusions about boundary effects. Although some of the standard techniques used to analyze slug tests in principle can detect boundaries at distances far beyond the distance affected by the flow period, special approaches must be used to avoid the need for a highly accurate estimate of the formation pressure. The problem is that the pressure change relative to the initial formation pressure is often used as a fundamental quantity in analyses. For cases with small pressure changes at the end of the buildup, the characteristics of the pressure response is highly sensitive to the choice of formation pressure, making it difficult to distinguish boundary effects from effects of erroneous input.

Because of the problem alluded to above, other and more robust methods should be used to analyze buildup data following short flow tests. This paper shows that straightforward derivative methods can be used to this end without the formation pressure as a key input parameter. This allows us to use two distinctly different approaches to analyze the data, thus reducing the uncertainty in the results. The methods do not overlap, and actually "favor" different data sets, but both require high quality data to reduce uncertainty and maximize the depth of investigation from analyses. In essence, the alternative approaches seek to move uncertainties from methodology (initial pressure estimation) to technology (data quality).

Although well-known derivative methods are advocated, the results deviate to some extent from the expected. The point is that the results look familiar but are not exactly what they appear to be. Also, the derivative approach does not work for all types of models in a theoretical sense, but it does work for all cases of practical interest.

The importance of the results should be obvious with increased interest in "green tests" with limited production without flow to surface, for instance by restricting flow to the wellbore with subsequent bullheading of hydrocarbons back into the formation. But these are not the only data sets of interest. The results apply to any data set with a shut-in period much longer than the flow period, for instance with days of flow and months of shut-in data. Another category of data comes from after-closure analyses (ACA), but such data have not been treated specifically in this paper.
How Do We Get There From Here? Global Energy Transitions Planning
Authors: Ebenhack B. W.
Published: December 2007

How shall we craft an energy future that is less dependent on petroleum? And what role will oil and gas play in that scenario? In spite of an impressive 150 year track record of increasing hydrocarbon production to meet exponential growth in demand, constraints have emerged. There will be a pinch in production rates relative to growing demand, necessitating the development and deployment of alternative energy technologies from more sustainable resources. As of yet there is no consensus on how to transition to alternative fuels, despite a great deal of talk about the need to do so. Nor is adequate consideration being paid to the pivotal role that oil and gas will continue to play well into the transition.

This paper addresses global energy planning at all organizational levels, as well as within energy producing corporations. Since future energy services will draw from an evolving mix of production sources and technologies, we propose a way for energy regulators and energy companies to optimize energy mixes, by evaluating the value added over time of each resource and applicable technology.

This paper maintains that oil and gas will continue to be important components in any energy mix for the foreseeable future. Alternative fuels will be hard-pressed to provide comparable net values either in terms of work from energy produced or in terms of environmental impact. As petroleum engineers, it is imperative that we make clear the character of the coming petroleum peak and the necessary role that petroleum must play in the coming transition period. It is essential to characterize clearly the energy value provided by our current resources and the value that will be demanded from alternatives as they do take up larger market shares.
Water Separation From Wellstream in Inclined Separation Tube with Distributed Tapping
Authors: Rivera R. M. , Golan M. , Friedemann J. D. , Bourgeois B.
Published: December 2007

This paper describes observations on water separation from wellstream in an inline separator using the concept of distributed water withdrawal from inclined tube section. The Physical observations were conducted in a laboratory using a 7" observation section applying flow rates compatible to North Sea single well rates. The distributed water withdrawal is achieved by placing a set of evenly spaced tapping points at the bottom of the tube section with facilities to control tapping rates. The observations were made in connection with a joint-industry project to validate and commercialize a new concept for downhole and seabed separations. The driver for the study is to verify possible water separation by distributed tapping from the bottom of the tube in high flow rates with high degree of agitation, turbulence and phase dispersion. Observations demonstrated that in a wide range of flow, comparable to the flow conditions in high rate oil wells, the high turbulence and phase dispersion do not erode and disperse completely a continuous layer of water on the bottom of the tube. This layer, flowing upwards or downwards depending on the flow conditions, facilitates a reasonable water separation when it is tapped properly. The scope of the test intended to capture the effect of flow and system variables on the separation efficiency. The experiments and the analysis validated the distributed separation concept. They demonstrated good separation at a wide range of flow stream conditions. They explained the reasons for good separation even in high degree of turbulence and phase dispersion. The mechanistic understanding of the separation allows a degree of predictability and guideness for separator design.
Environmental Advances in Drilling Fluids and Waste Operations Applying Novel Technology for Fluid Recovery and Recycling
Authors: Eia Jan Thore , Hernandez Edgardo
Published: December 2007

This paper presents a concept designed to meet and be compliant with the environmental legislation requirements of managing drilling fluids, completion fluids and waste from the oil and gas industry in the arctic and Barents Sea region. Data will be presented in this paper to document the reduction in direct environmental impact, reduced risk as well as the profitable returns; like cost savings for the operators and the drilling fluid supplier as a result from applying these novel technologies.

A total drilling fluid and waste management concept for drilling and well operations was developed to merge the operators cost reduction strategies and reduced environmental impact with the fluids and equipment supplier's technology and business incentives. Key elements in this concept was; (1) the development of both water based and oil based environmental friendly drilling fluids for challenging arctic conditions, (2) the EnviroUnit for separation, recovery and recycling on location, (3) CleanCut for enclosed cuttings containment completely reliable with no operational downtime or due to harsh weather conditions when drilling operations are distant from shore and finally (4) the onshore EnviroCenter with capacity and technology to receive, treat, store, manufacture and deliver drilling fluids and related liquid and cuttings waste streams.

Presented data show oil based drilling special waste reduction of over 90%. All recovered oil based drilling fluid has been recycled, upgraded and reused. A reduction in the new oil based drilling fluid consumption has been experienced reducing manufacturing, transport and storage cost. All separated waste water has been cleaned to well within the approved discharge regulations.

Whenever possible, the total fluids and waste management concept should be applied. Oil recovered from cuttings transported onshore and processed via thermal treatment has been successfully recycled as drilling fluid base oil. This total fluids and waste management concept has been established as a business "standard". The success is however closely linked to the close team-work with the operator and across the traditional service lines of fluids; solids control, waste management, associated waste handling logistics, processing, treatment and disposal. It will achieve full environmental impact and benefit when applied to large-scale operation.
Improved Understanding of Proppant Transport Yields New Insight to the Design and Placement of Fracturing Treatments
Authors: Brannon H. D. , Wood W. D. , Wheeler R. S.
Published: December 2007

Post-frac production analyses frequently suggest that effective fracture area is significantly less than that designed, implying either the existence of excessive proppant-pack damage or, that the proppant was not placed in designated areal location. The conductive fracture area is defined by the propped fracture height and the effective fracture length. Optimization of effective fracture area is among the principal tenets of fracturing design engineering. It is well understood that effective fracture area is a first order driver for well productivity, and optimization of such is often critical to economic exploitation of reservoir assets.

The results of extensive testing in a large-scale slot apparatus to delineate the relative effects of various component and treatment parameters on proppant transport capability were reported previously. In an extension of that effort, an empirical proppant transport model has been developed using the information gleaned from previous testing and then refined using newly generated data to expand the range of the various component parameters. The model has input parameters including fluid viscosity, proppant size, both fluid and proppant specific gravity, injection rate, and fracture geometry. The model output is the estimated propped fracture length of a given treatment design incorporating a fracturing fluid slurry having the input parameters.

Utilizing the new model, the most favorable combination of fracturing slurry component properties and pumping parameters can identified and incorporated in fracturing treatment design and applications to optimize effective propped fracture length, and thereby well performance.
Isolating Water Production at the Source Utilizing Through-Tubing Inflatable Technology
Authors: Kelbie Graeme M. , Garfield Garry L.
Published: December 2007

With continual increase in water production from maturing reservoirs comes the expense of installation of surface handling equipment, disposal and environmental concerns and a reduction in production efficiency from hydrocarbon producing wells. These costs run into millions of dollars every year, dealing with this problem. The operators of these wells have utilized differing technologies and procedures in efforts to control production of these unwanted fluids. Water shut-off applications in one way or another are an everyday part of well servicing work. Some of the methods and practices currently used today to help combat this problem include, placement of cements, plugging back the zone with the aid of mechanical isolation devices, pulling the completion and performing work-overs, and the utilization of purposely designed cements or chemical water blocking agents. Initial efforts to utilize such fluids proved encouraging but methods were required by the operators in order to allow accurate placement of these chemicals. Some of the drivers are;

Economics, in terms of the relatively high cost of such fluids and; The reaction of such water blocking chemicals when placed incorrectly within producing formations and the inability to reverse engineer such misplacements.

Couple these problems with the well geometry to be worked in and the solution of placement can be seen to involve many diverse complications. For this reason the requirement for innovative through-tubing zonal isolation solutions has never been greater. Through-tubing inflatable technology has, for some time now, been providing high-expansion devices in order to provide our industry with an economical and reliable method of isolating and placing water blocking treatment fluids. In this paper we will focus on current inflatable tools that are available today and how they can be utilized to provide cost effective water shut-off solutions at the source of the problem.
Influence of Shrinkage and Swelling of Coal on Production of Coalbed Methane and Sequestration of Carbon Dioxide
Authors: Siriwardane H. J. , Smith D. H. , Gorucu F. , Ertekin T.
Published: December 2007

The potential for enhanced methane production and geologic sequestration of carbon dioxide in unmineable coal seams needs to be evaluated before large-scale sequestration projects are undertaken. Coal is known to competitively adsorb carbon dioxide and methane gases. Laboratory experiments indicate that coal will swell when a gas is adsorbed and shrink when a gas is desorbed. The swelling and shrinkage may change the cleat porosity and permeability of the coal. This paper deals with the influence of shrinkage and swelling of coal on the production of methane from, and injection of carbon dioxide into, a coalbed reservoir. A three-dimensional swelling and shrinkage model was developed. This model is based on constitutive equations that account for coupled fluid pressure-deformation behavior of a porous medium that undergoes swelling and shrinkage. The swelling and shrinkage strains are computed on the basis of the amounts of different gases adsorbed or desorbed. The permeability of the reservoir is modified by the shrinkage or swelling. The paper presents numerical results on the reservoir performance during injection of carbon dioxide in a previous field test that has been reported in the literature. The results indicate that coal swelling and shrinkage can influence the production rates and reservoir pressure distribution in the field.
A New Pulsed Neutron Sonde for Derivation of Formation Lithology and Mineralogy
Authors: Pemper R. , Sommer A. , Guo P. , Jacobi D. , Longo J. , Bliven S. , Rodriguez E. , Mendez F. , Han X.
Published: December 2007

A new openhole logging service, RockViewSM, has been developed which provides lithological and quantitative mineralogical information for accurate formation evaluation. The assessment begins with elemental formation weights and follows with an interpretation of lithology and mineralogy. Lithologies are divided into general categories including sand, shale, coal, carbonates, and evaporites. Potentially identifiable minerals are quartz, potassium-feldspar, albite, calcite, dolomite, siderite, anhydrite, illite/smectite, kaolinite, glauconite, chlorite, pyrite, and others.

The logging system utilizes an electronic pulsed source to send high energy neutrons into the surrounding formation1-8. These neutrons quickly lose energy as a result of scattering, after which they are absorbed by the various atoms within the ambient environment. The scattered as well as the absorbed neutrons cause the atoms of the various elements to emit gamma rays with characteristic energies. These are measured with a scintillation detector, resulting in both inelastic and capture gamma ray energy spectra. A matrix inversion spectral fit algorithm is used to analyze these spectra in order to separate the total response into its individual elemental components. The prominent measured elements associated with subsurface rock formations include calcium, silicon, magnesium, carbon, sulfur, aluminum, and iron. Potassium, thorium, and uranium are measured separately with a natural gamma ray spectroscopy instrument9-11. The tool response is characterized for each individual element by placing it into formations of known chemical composition.

Interpretation of the data begins with an assessment of the elemental formation weights, which then leads to a determination of lithology and mineralogy. Each step in the process is guided by the examination of ternary plots containing selected elements. Magnesium is an extremely important part of the interpretation process since it distinguishes dolomite from calcite and helps to identify various types of clay.

Data from field examples is presented in order to illustrate the effectiveness of this technology.
Borehole Deviation Surveys Are Necessary for Hydraulic Fracture Monitoring
Authors: Bulant P. , Eisner L. , Pšencík I. , Le Calvez J.
Published: December 2007

Significant errors in the calculated azimuth and other parameters of a monitored fracture can be caused by not performing accurate borehole deviation surveys for hydraulic fracture monitoring (HFM) and neglecting the effects of the deviating borehole trajectory. For common HFM geometries, a 2° deviation uncertainty of the positions of monitoring or treatment well surveys can cause more than a 40° uncertainty of the inverted fracture azimuths. Furthermore, if the positions of the injection point and the receiver array are not known accurately and the velocity model is artificially adjusted to locate perforations on assumed positions, several milliseconds discrepancies between measured and modelled SH-P-wave traveltime differences may appear along the receiver array. These traveltime discrepancies may then be misinterpreted as an effect of TI anisotropy, and use of such an anisotropic model may lead to the mislocation of the detected fracture(s). The uncertainty of the relative positions between the monitoring and treatment wells can have a cumulative, non-linear effect on inverted fracture parameters.
Interfacial Instability in Reactive Miscible Flow Displacements
Authors: Ghesmat K. , Azaiez J.
Published: December 2007

Flow processes that involve the displacement of a viscous fluid by a less viscous one often lead to a hydrodynamic instability known as viscous fingering. In this study the viscous fingering instability for reactive flows will be addressed. In order to understand the physics of this reactive flow displacement, the basic equations of conservation of mass, energy and momentum are solved for a two-dimensional porous medium. The flow is modeled numerically using a spectral method based on the Hartley transformation. The streamfunction and concentration fields are determined for the two dimensional flow in every time-step to track the development of the flow. In this study, two different kinds of auto-catalytic reactions are considered and the effects of stoichiometry on finger patterns are examined. Finger patterns are analyzed for different values of the viscosity ratio, reaction rate and order. We will discuss how the interplay between chemical reaction and hydrodynamics could result in interesting instability schemes. Physical discussions of how the reactions may affect the viscous fingering patterns are also presented.
Field and Laboratory Observations of Post-Failure Stabilizations During Sand Production
Authors: Morita N. , Fuh G. -F. , Burton B.
Published: December 2007

Sand flow models have been successfully applied to heavy oil reservoirs1,2,3. However, when these models are applied to light oil and gas reservoirs, the equations controlling generation of eroded solid mass or sand release rate are vastly simplified4–11 necessitating further field observations controlling sand flow rate in order to improve accuracy. Sand flow is catastrophic when formation is soft. However, if certain conditions are satisfied, the sand rate is reasonably stable. This paper clarifies nine forms of post-failure stabilization. Subsequently, field methods to deal with sand problems with uncertain sand rate predictions are proposed.
Focused Risk-Management Brings a Step-Change Improvement in Drilling Performance at Sakhalin's Odoptu ERD Development
Authors: Mohammed N. , Chernov M. , Mañalac-Trøan E. , Kaydalov Y.
Published: December 2007

Since 1998 Rosneft SMNG (Sakhalinmorneftegas) has been developing the northern part of the Odoptu structure, near-shore to eastern Sakhalin Island, using ERD (extended reach drilling). Discovered in 1977, North Odoptu is alone among Sakhalin ERD projects in that it is entirely Russian operated and utilizes a unique hybrid of both Russian and international capabilities to address the considerable challenges of ERD well construction. To date 21 wells, with horizontal displacement/TVD aspect ratios up to 4.1, have been drilled and completed from two land-based drilling locations.

The use of rotary steerable (RSS) technology has more than doubled net drilling performance compared with early wells drilled using positive displacement motors (PDM's). A hole-cleaning challenge remains however, due to a practical necessity for back-reaming while tripping out of the hole. This has led to serious delays as localized unstable sections of the well-bore collapse due to mechanical disturbance, forming cavities that complicate hole-cleaning operations with pack-offs and stuck-pipe.

Low-resolution 2-D seismic has been a limitation on understanding the detailed nature of the over-burden stratigraphy and thus the ability to characterize the cavities. Geo-mechanical models, while clarifying the impact of the regional stress regime, have indicated that the origin of this instability phenomenon may not be due to compressive shear-failure.

The primary focus has therefore been on the development of cost-effective and innovative drilling optimization techniques to predict and identify cavity zones early in the drilling operation, and application of a fit-for-purpose, rig-based, risk-management approach to well-bore instability events. The progressive application of these techniques and the adopted risk-mitigation strategies is documented. This approach, in conjunction with the use of a regularly updated geo-mechanical model, has resulted in a successful outcome for well construction in a previously severely problematic region of the field.

The ability to recover well from instability-related setbacks has helped to foster a co-operative, continuous-improvement culture among the extended drilling team - Russian operator and international contractors alike. Recommendations are made for follow-on technologies and strategies that will have the greatest impact on the next phase of field development.
A Semianalytical, Pressure-Transient Model for Horizontal and Multilateral Wells in Composite, Layered, and Compartmentalized Reservoirs
Authors: Medeiros F. , Ozkan E. , Kazemi H.
Published: December 2007

This paper presents a semianalytical model for the pressure-transient analysis of horizontal wells in composite, layered, and compartmentalized reservoirs. The model divides the reservoir into blocks that represent locally homogeneous substructures of the reservoir and couples the analytical, pressure-transient solutions at the block boundaries. This approach is consistent with the averaging effect of pressure transients and provides an alternative to full numerical modeling of horizontal-well pressure-transient responses in heterogeneous formations. The model can also be generalized for multiple wells of different geometry including multiple laterals.
Integrating People and Technology: Successful Implementation of Six Key Elements Towards Project Excellence in Angsi Field Development, Malaysia
Authors: Karim Rahimah Abd. , Dahlan M. Shaufi , Noordin Khairul Annuar , Noor Harun M.
Published: December 2007

Angsi is an integrated oil and gas development project in offshore east coast of Peninsular Malaysia. It is one of the biggest oil producers in Malaysia, contributing one-sixth of the total national daily oil production. During its planning and execution stages, the project has had many successes and positive outcomes. It has been recognized as the model of success for all domestic and international operations in PETRONAS Carigali Sdn. Bhd. (PCSB).

The uniqueness of achievements in Angsi project relies on the successfulness of integrating its people and technology. With the recent skyrocketing oil price, the trend has been to chase for additional reserves and maximize crude production, and make it happen by whatever means possible (new technologies, joint ventures, aggressive recruitments etc). However, many projects failed to achieve these targets, despite being equipped with niche and advanced technologies.

Angsi project has successfully overcome these obstacles. The secret relies in the six key elements that have been nurtured in the working culture of every team member, which are; people, focus, integrated approach, planning, communication and feedback loop. With this unique culture, it has allowed the team to achieve major successes over the past 5 years.

Among those is the successful implementation of the largest platform-based hydraulic fracturing program worldwide, and first in Malaysia. This allows the development 0.5 TCF gas from the otherwise uneconomic tight gas reservoir. The team also managed to increase its reserves level 2.5 times from its initial size. Consequently, it increases Angsi's daily production rate from 65 to 115 kbpd. Finally, Angsi project successfully reduces its unit development cost (UDC) by 67%, lowering it from 5.1 USD/boe to 1.7 USD/boe.

This paper discusses how the six key elements have contributed to the successes of Angsi Field Development Project.
Reaction of Calcite With Surfactant-Based Acids
Authors: Al-Mohammad A. M. , Nasr-El-Din H. A. , Al-Aamri A. M. , Al-Fuwaires O.
Published: December 2007

Surfactant-based acids have been extensively used in matrix and acid fracturing treatments in carbonate formations. As the acid spends and the pH rises, the surfactant molecules aggregate and form long entangled micelles, which enhance the apparent viscosity of the solution. The high viscosity is required for proper acid diversion, which is needed in horizontal and vertical wells with long target zones. Successful field data were obtained with surfactant-based acid, however the impact of the viscoelastic surfactant used on the reaction of the acid with the rock was not systematically examined before. Therefore the objective of the present work is to examine in detail the effect of a viscoelastic surfactant (amphoteric) on the reaction of HCl acid with calcite.

The reaction between calcite and surfactant-based acids was thoroughly investigated using the rotating disk apparatus. The effects of disk rotational speed, surfactant concentration and temperature on the dissolution rate were determined. All experiments were conducted using 20 wt% HCl and various combinations of corrosion inhibitor and surfactant concentrations. The system pressure was maintained at 1,000 psi and the reaction was allowed to proceed for 20 minutes only. Samples from the reaction vessel were collected at various times and were analyzed for calcium using ICP. The apparent viscosity of surfactant-based acids was measured as a function of shear rate, temperature, and surfactant concentration using a HTHP Brookfield viscometer.

The results obtained indicated that the viscoelastic surfactant significantly reduced the dissolution rate of calcite with HCl. This trend continued as the concentration of the surfactant was increased to 4 wt%. The effect of temperature on the dissolution rate was similar to that of temperature on the apparent viscosity of surfactant solutions where there was a maximum in viscosity at 50-60°C. The dissolution rate was controlled by mass transfer of H+ to the surface of calcite.
Buckling of Tubulars in Actual Field Conditions
Authors: Menand S. , Sellami H. , Tijani M. , Akowanou J.
Published: December 2007

Buckling of tubulars inside wellbore has been the subject of many researches and articles in the past. However, these theories have always followed the same assumptions: the wellbore has a perfect and unrealistic geometry (vertical, horizontal, deviated, curved) and the friction is ignored, conditions relatively far from actual field conditions. How do tubulars buckle in actual field conditions, that is, in a naturally tortuous wellbore with friction and rotation ? Can we apply conservatively theories developped for perfect well conditions (no tortuosity, no friction) to actual well conditions ? This paper gives answers to these questions in comparing results obtained from existant models with results obtained from an advanced model dedicated to drillstring mechanics.

Firslty, this paper presents the new developements integrated in a recently advanced model for drillstring mechanics and enabling to take into account the buckling phenomenom in any actual well trajectory. Secondly, this paper shows the influence of tortuosity and friction on the buckling phenomenom for some practical and critical case met in the drilling industry. These tortuosity and friction effects are demonstrated with an experimental set up that enables to confirm theoretical features. Lastly, we compare results obtained from existant models with results obtained from our new model to evaluate the tortuosity and friction effects on the critical buckling load found in the litterature.
North Sea Completions: Trends, Reliability, Services, and Resources
Authors: Elliot G.
Published: December 2007

BP's North Sea Strategic Performance Unit, headquartered in Aberdeen, is a large, geographically and technically diverse business. It encompasses some 45 fields in the UK and Norwegian North Sea, mainland UK and the Netherlands, with wells drilled from all rigs; subsea, platform, and land. There is a wide range of completion requirements in these wells, from open-hole to sand-control to horizontal perforation across the reservoir, and all forms of artificial lift, together with intelligent completion components. From 2001–2005, approximately 150 operated wells have been completed with the number per year ranging from 9 to 37 planned for 2006. BP will invest ca. $640MM in Drilling and Completions in the region during 2006, with completion spend a significant percentage of this figure ( > 30%).

With this high activity and spend, ensuring completion reliability is key to maximizing reserves, and hence the return from each well. Reliability starts at the completion design phase and goes through to installation and on-going well management activity. The purpose of this paper is to articulate key directions taken in an attempt to maintain (and improve) overall completion effectiveness, against a backdrop of high oil price, increasing activity and competition for services and resources. I have discussed ‘where we were, where we are now and where we intend to go’ in various important areas, all ultimately linked to optimizing completion performance.

Areas of focus include; People (resource planning, training, organization structure and the impact of market pressure), Completion Equipment and Services (equipment standardization and inventory management), evolution of Completion Design (type and size of well, material, lifetime). Reliability and performance data will be presented. An internal study in 2004 showed that approximately 20% of wells less than 3 years old were having completions integrity problems. The causes will be highlighted and discussed, together with the key reasons for completion Non-Productive Time.
An Investigative Study of Potential Emulsion Problems Before Field Development
Authors: Kokal S. , Al-Ghamdi A. , Meeranpillai N. S.
Published: December 2007

Before the development of a field it is worthwhile to determine the characteristics of crude oil emulsions. This may be even more important if the wells are to be equipped with electrical submersible pumps (ESPs) which can create a shearing environment resulting in tight emulsions. One such study was conducted to determine the characteristics of emulsions from a cluster of oil fields planned for development. The proposed development is to produce from three fields and several different reservoirs. The central crude processing facility will process ~500 MBD of crude and 50 MBD of water. A study was conducted to determine the impact of ESP on emulsions and hence on the ESP design (horsepower) and the possibility of demulsifier injection downhole. The emulsion properties are also needed for the design of central wet crude handling facilities. A series of emulsion tests were conducted with crudes from different reservoirs at bottomhole and surface temperatures, range of watercuts and shearing conditions. The results are provided in terms of ‘relative’ tightness of emulsions from different reservoirs. The viscosities of various emulsions were also determined. The results indicate that demulsifier injection facilities will be needed at the wet crude handling facilities and possibly in wells from one reservoir that has a high asphaltenic and viscous crude. The paper provides a framework of laboratory emulsions studies that can provide valuable information for the design of processing facilities before they are built. The paper also discusses some practical aspects of demulsifier treatment program including demulsifier selection and optimization and methods to prevent emulsion problems.
Balanced Pressure Drilling With Continuous Circulation Using Jointed Drillpipe—Case History, Port Fouad Marine Deep 1, Exploration Well Offshore Egypt
Authors: Calderoni A. , Chiura A. , Valente P. , Soliman F. , Squintani E. , Vogel R. E. , Jenner J. W.
Published: December 2007

This paper presents the industry's first application of balanced pressure drilling to drill a difficult well section with continuous circulation using jointed pipe. Previous attempts to drill the section in 2004 failed and balance pressure drilling was identified as the only safe and practical drilling technique to use.

The paper will present the reasons for employing a new drilling technique, together with the associated changes to conventional drilling and well control procedures.

In the Port Fouad Marine Deep–1 (PFMD–1) well below 4000m, there exists a critical pressure gradient zone with pore pressures exceeding 2.0 sg EMW, with the difference between pore and fracture pressure gradients as low as 0.10 sg EMW. The dynamic hydrostatic pressure difference between the Equivalent Circulating Density (ECD) and the mud weight was equivalent to about 0.07 sg during drilling operations. The well was re-entered in June 2005 using the Continuous Circulation System (CCS™) and the problem zone drilled maintaining constant ECD. Drilling difficulties resulting in the earlier suspension were successfully overcome.

Balance Pressure Drilling (BPD) with uninterrupted circulation and revised drilling and well control procedures significantly improved drilling performance and operational safety in the critical gradient zone. This resulted in adding significant new hydrocarbon reserves that could not previously be drilled.