bluuebunny/crossref_metadata_2025 huggingface dataset:
Prediction of Sand Production Rate in Oil and Gas Reservoirs: Importance of Bean-Up Guidelines
Authors: van den Hoek P. J. , Geilikman M. B.
Published: December 2007

Most sand production prediction models to date have the capability to indicate whether initial sand production may take place during the lifetime of a reservoir but they are unable to predict whether the sand production will be ‘problematic’ (excessive erosion, plugging, well sand-up, separator fill, etc.), particularly for systems that have some tolerance towards sand production.

In order to predict whether sand production will be ‘problematic’, it is important to estimate sand volumes / rates as a function of bottom-hole load conditions, drawdown, time, etc. This paper presents a model to predict sand volumes / rates for any type of clastic oil or gas reservoir. This model captures both the geomechanical aspects (rock deformation and failure) and the transport aspects (e.g. role of drawdown and watercut) of the sand production problem. It was extensively validated comparing predicted sand volumes and rates with field observations for a variety of oil and gas fields under various stages of depletion. For all these cases, the model predictions and field observations are in reasonable to good agreement.

The main focus of the current paper is the discussion of bean-up procedures, i.e. the question is addressed as to whether an appropriate bean-up strategy (e.g. small bean-up steps) may reduce the cumulative volume of produced sand.

We show that for wells without sand control, the cumulative amount of sand produced to surface is independent of bean-up procedure. If a large sand production volume is expected in such a well, beaning it up in small steps not only increases the risk of sand-up in itself, but also the risk of repeated sand-ups before the well can finally be produced. By contrast, for wells with sand control, the risk of plugging by fines mobilization is reduced by beaning up in small steps.
Performance Step Change in Kuwait: Drilling Deep-Directional 16inch Hole Build Section Saves Operator 13 Days Rig Time
Authors: Al-Saeedi Mohd. , Sounderajan Mahesh , Al-Enezi Dakhil , Moore Ross , Sharma Maneesh , Eckstrom Darren
Published: December 2007

In 2005, Kuwait Oil Company Exploration Group (KOC) began drilling KM-05, a deep directional exploration well in their West Kra Al maru (KM) field. The well was projected to TD at 16,285 feet MD. In order to intersect the reservoir fractures at the appropriate angle to enhance production potential, the well profile required drilling a 16" directional hole section. The operator considered this a significant challenge to complete the build section with a 16" PDC as it had never been attempted at a depth below 11,500 ft, but they wanted to explore the possibilities.

Similar vertical wells required both roller cone and PDC bits to complete the section. Because roller cone had unacceptably low ROP, the operator determined PDC would offer the best option to efficiently drill the build section, therefore offering the best chance for success. Contingencies allowed for fallback to roller cone because of the PDC’s anticipated high reactive-torque, the ability to meet directional objectives and limited experience drilling deep directional wells in this large hole size.

In the preplanning stage, the operator’s drilling team closely examined new technologies which would allow them to achieve their goals, especially drilling the demanding deep directional section. The entire BHA was engineered to ensure the ROP and directional requirements would be met. A team was organized to aggressively seek technology/best practices that would efficiently deliver well objectives. The team identified that poor tool-face control in limestone would be the primary obstacle. BHA and PDC bit technology was a key focuses in optimizing the 16" directional section. Due to this careful planning and collaboration between the operator and service providers, the directional objective in the 16" hole section of one PDC bit run was achieved. By applying new technology the section was drilled 13 days faster than the directional offsets constructed with roller cones with an estimated savings of US$258,364.
Near-Wellbore Field Water/Oil Relative Permeability Inferred from Production with Increasing Water Cut
Authors: Toth J. , Bodi T. , Szucs P. , Civan F.
Published: December 2007

Oil and water relative permeability data and values of relevant displacement and petrophysical parameters are determined directly at actual in-situ conditions from the oil and water production history of wells. This is accomplished using the convenient interpretation formulae derived for radial unsteady-state two-phase immiscible fluid displacement in the near wellbore formation. The application of the new methodology is demonstrated by processing the typical literature and oil-field production well data. This approach provides a more accurate estimation of the water-oil relative permeability around the production wells than those obtained from the laboratory immiscible flow tests conducted using reservoir core and fluid samples.
Pipelines Slugging and Mitigation: Case Study for Stability and Production Optimization
Authors: Tang Y. , Danielson T.
Published: December 2007

The ConocoPhillips Alpine facility, on the Alaskan North Slope, has experienced slugging problems severe enough to trip the high-high inlet separator level, causing frequent plant shutdowns, and loss of production of 110 kbbl/d. A slugging study was commissioned to investigate the cause of the existing CD-2 pipeline slugging, and possible mitigation procedures, which could alleviate and/or eliminate slugging. Further, the Alpine expansion called for an additional two pipelines (CD-3 and CD-4) to be brought into Alpine inlet separator.

Slugging mechanism and instability analysis were performed. The instability is due to combination of its low flow rate, overly-sized pipeline ID and unfavorable pipeline profile. Flow pattern transition exists at the low spots and liquid accumulates and blocks the flow. In the low pressure system, once gas blows out and system pressure drops, the pipeline inlet gas increases velocity and picks up a new hydrodynamic slug. This slug moves through the road crossing and the pipe rack riser, becoming a long slug which arrives at the separator.

In this study, a slug-tracking model with separator gas/liquid PID controllers was built to reproduce the field SCADA data. A remarkably good match of pressure variations, slugging frequency and liquid level was achieved. A sensitivity study was performed to investigate the effective and practical ways to suppress slugging in the existing CD-1 and CD-2 pipeline. Finally, a combined control was recommended by installing a by-pass control valve at the butterfly valve location. The by-pass inlet control valve before the separator acquires separator liquid level signal, and actuates when the separator liquid level exceeds the set value. This significantly reduces slugging effect on separator performance.

The slugging model and results based on the existing CD-2 pipeline were applied to the future expanded CD-3 and CD-4 pipeline study. Some conclusions were drawn from the slugging behavior.
A New Slim-hole Drill Bit
Authors: Qingyou Liu , Hu Qin
Published: December 2007

With exploration moving into deeper waters, deserts and plateaus, operators and contractors will continue to face complex technical and financial challenges. After various advantages of slim-hole drilling, especially great reduce of cost, are well known, slim-hole drilling has become an important technology and been applied extensively. However, existing three-cone bits and PDC bits can not satisfy the requirements of slim-hole drilling owing to limited structure and short life. So, Southwest Petroleum University (SWPU) has developed a new slim-hole bit, named disc one-cone bit, which combines one-cone bit with disc bit. This new bit will have expansive application prospect in deep drilling, ultradeep drilling and slim-hole drilling because of its less torsion, higher bottom-hole coverage coefficient and longer bearing life.

During the development of new disc one-cone bit, it is very important to ascertain the arrangement and the structural size of disc tooth reasonably according to its rock-breaking mechanism. However, the factors to affect bit rock-breaking efficiency are more and restrict each other. If laboratory experiment is carried out to research a kind of new bit, it will be long period, much cost and only under very simplified conditions. Therefore, computer simulation has important technical and economic value during studying the new bit. This paper discusses rock-breaking mechanism and kinematics simulation researches of disc one-cone bit emphatically.
Predicting Primary Depletion Recovery of a Giant Light-Oil Carbonate Reservoir
Authors: Ayyalasomayajula P. , Kamath J. , Dehghani K. , Fischer D.
Published: December 2007

Predicting primary depletion recovery below the bubble point is a very difficult challenge, especially for carbonate reservoirs. Accurate predictions require sufficient laboratory data to cover the variability in response from the different rock types and laboratory procedures, and proper upscaling of laboratory data to simulation grid scales.

Many recent studies have shown that laboratory-derived gas-oil relative permeability curves often depend on whether the tests were conducted using depletion drive or steady state methods. Though it may seem preferable to use laboratory data from depletion drive experiments for modeling solution gas drive recovery, these tests are complex and there is concern using data from tests conducted at pressure depletion rates much higher than that in the field. More significantly, such tests are expensive and it is not practical to conduct many depletion tests.

We used mercury injection, porosity, permeability, CT scans, and thin section data to classify the giant carbonate reservoir into different rock types. Steady state gas-oil relative permeability tests on plug samples were then conducted to span these rock types, and P10-50-90 curves developed. We also carried out steady state and reservoir condition multi-rate depletion on select whole cores. This data was used to apply a correction to the steady state plug data, and this typically lowered the gas relative permeability curves.

We next conducted numerous upscaling studies using sector models extracted from the full field simulation model. These studies showed that areal upscaling cause the core based critical gas saturation to be increased and the oil relative permeability to be decreased. Vertical upscaling, including the presence of high permeability streaks to represent fractured zones, has not yet shown much impact on the laboratory derived curves.

Finally we developed a template to systematically modify the steady state relative permeability plug data to account for process and scale effects. The new P10-50-90 curves were then used in simulation predictions and results compared to that from the plug based curves.
A Method for Analysis of Pressure Response with a Formation Tester Influenced by Supercharging
Authors: Banerjee R. , Thambynayagam R. K. M. , Spath J.
Published: December 2007

Interpretation of pressure transient tests conducted in a dynamic environment, like drilling, is challenging. One of the difficulties arises due to phenomenon known as supercharging which is caused by mud filtrate invasion. The supercharging results in an increase in sandface pressure which is above the reservoir pressure. Therefore, any calculation of initial pressure and permeability must take into account the supercharging effect.

We present an algorithm that takes into account the supercharging effect in analysis of pressure transient tests acquired with a single or multiple probe formation tester. The solution is obtained by successive integral transforms to the governing equations and to the associated initial and boundary conditions. Thus a complex phenomenon can be modeled, using some valid simplifying assumptions, with sufficient accuracy for the purpose of test design or interpretation. The rationale for the initial and boundary conditions deployed here, which are unique to a supercharged system, is explained in detail.
Process Data for Thermal Gas-Liquid Stimulation of Wells in Zybza-Glubokiy Yar Field
Authors: Stashok Y. I. , Antoniadi D. G.
Published: December 2007

Presented in the paper are the results of pilot-commercial thermal cyclic stimulation of wells performed in various producing intervals of Zybza-Glubokiy Yar field containing heavy (with density of 0.975-0.986 g/cm3), high-viscosity (with kinematic viscosity of 340-580 cSt@50°C) and resinous (with sulfuric acid resins content of up to 72% mass) crude oil. Cyclic steam stimulation of bottom-hole zones and reservoir steaming were the technologies realized to develop the field which is mature now. Two thermal EOR processes had been tested in the field within the period of 2000-2004. One of the said processes involves the use of a gas-liquid heat carrier (gas-steam), the other – a gaseous heat carrier (thermal gas).
Fractured Reservoir Characterisation and Modelling—A Pragmatic Approach
Authors: Wynn Tim
Published: December 2007

Fractured reservoirs are complex and technically challenging to characterize and model. To help reduce the instances of inefficient modelling schemes and inappropriate results we present a process for defining fractured reservoirs workflows optimized for the study objectives, available data and reservoir characteristics. This process contains nested levels of study issues with iterative workflow stages. This is to enable the definition and monitoring of a flexible workflow that considers relevant high level study issues whilst executing the detailed study work. Although this approach may add some administrative complexity, it is suggested that by maintaining focus on all relevant issues at each stage, the final results should be more relevant.
Borehole Fluid Reinvasion Effects on C/O Logs in Openhole Completion
Authors: Kelder O. , Al-Hajari A. A. , Crary S.
Published: December 2007

This paper discusses the borehole fluid reinvasion effects on carbon/oxygen (C/O) saturation results in wells with openhole completions. Although the advantage of C/O technology in a fresh or mixed formation water salinity environment is evident, the main limitation of C/O technology is the relatively shallow depth of investigation ranging from 6" to 10". To overcome this problem, the general recommendation for wet producers has been to acquire data in flowing conditions to minimize reinvasion effects. Two field examples with C/O saturation data in dedicated openhole observation wells which have been shut-in for a longer period of time, have shown that reinvasion remains a major issue and is mainly controlled by the pressure differential between borehole and formation and formation permeability. The degree of pressure overbalance is evaluated with borehole fluid pressure and offset RFT formation pressure data. Flowing data from these observation wells provides a significant different answer and is the recommended solution for observation wells. Alternatively, if only shut-in data can be acquired, another field example shows that shallow reading C/O measurements should be combined with deep reading resistivity readings to evaluate the degree of invasion and assess deep formation saturation.
Jet Pump Performance With Secondary Fluids Differ in Density and Viscosity From Primary Fluid
Authors: Abdou Hesham A.M. , Mikhail S. , Abou-Ellail Mohsen
Published: December 2007

Many researches had been carried out on the water jet pumps during the last few decades, and discussed the effect of changing the pump geometric parameters on its performance. Some other researches investigated pump performance with Two-phase (liquid-gas) and (liquid-solid) flow. In spite of the several researches, which investigated the case of liquid-liquid flow (almost water-water), neither of them did have examined the case in which the secondary flow liquid differs from the power flow liquid in density and viscosity, which is the main objective of this research. The subject is treated experimentally on a special test rig, with the primary jet water and the secondary different types of oils. Performance of the jet pump and static wall pressure inside the mixing chamber, were measured as a function of the mixture Reynolds number. A one-dimensional analysis is also carried out, taking into account the difference of the viscosity and density of the two liquids (each primary and secondary fluids). Discussion of both the experimental and analytical results and comparison between them are made with the main conclusions and recommendation for further researches. Contributions of the present work are:

– Developing an equation giving the performance of the jet pump when the viscosity and density of the primary fluid is different from those of the secondary fluid. – Proposing pressure loss coefficient in the mixing chamber due to turbulent of mixing, as a function of Reynolds number which is calculated based on the density, viscosity and velocity of the mixture in the mixing chamber. – Turbulent mixing for the power and secondary fluids, in the mixing chamber, distribution of axial and radial velocity for both of carrier and carried phases are determined numerically by using the assumption of Two-phase, Two-dimensional flow.
A Novel Wireless Solution to Address Uncertainties in Reservoir Connectivity
Authors: Champion B. P.
Published: December 2007

Reservoir connectivity is a common uncertainty when considering any new field appraisal or development options. Having a better understanding of reservoir connectivity provides significant benefits in optimising the field development plan. By the application of a new wireless telemetry technology, it is now possible to cost effectively gather high value reservoir connectivity information in situations that previously may have been considered technically impractical or commercially non-viable.

Consider for instance, the situation where an appraisal or step-out subsea well is drilled close to an existing producing field, or a new field under development. Today, these appraisal wells are typically permanently abandoned after logging and testing without obtaining any long term pressure data, thus losing a valuable opportunity to gain a better understanding of connectivity in the reservoir and thus prove the reservoir model. Using existing technologies to acquire such data, whilst technically viable, is typically not a cost effective option, requiring either well intervention or high up-front capex. By installing a battery powered wireless telemetry system in the well at the time of well abandonment, but without in any way compromising the integrity of the abandonment, it is now possible to acquire high quality reservoir pressure and temperature data for periods of up to 2 years and beyond. Data from the abandoned well, is transmitted from reservoir depth to the seabed using wireless technology, where it is stored for subsequent collection, on demand, by a supply vessel passing overhead.

The paper will review prior methods used for long term reservoir appraisal monitoring and demonstrate how advances in wireless telemetry technology now enable critical information about reservoir connectivity to be obtained from suspended/abandoned wells or zones, where previously there was no cost effective means to do so. It will describe several applications of how the wireless technology has been, or will be applied for the purpose of gaining a better understanding of the reservoir model.
Big Bore Completion and Sand Control for High Rate Gas Wells
Authors: Bourgeois Alain , Bourgoin Sebastien , Puyo Pierre
Published: December 2007

This paper outlines and discusses the issues surrounding the TOTAL AUSTRAL Carina and Aries field development project and the engineering issues addressed to facilitate achieving the project goals of producing gas at high rates from the shallow unconsolidated sand stone reservoirs.

The main challenge in terms of completion architecture was to maximize the well head flowing pressure while insuring "long term integrity" of wells. This was addressed through implementation of limited - or even not - proven technologies.
Application of an Integrated Approach for the Characterization of a Naturally Fractured Reservoir in the West Siberian Basement (Example of Maloichskoe Field)
Authors: Pinous O. , Sokolov E. P. , Bahir S. Y. , Zellou Abdel M. , Robinson Gary , Royer Ted , Svikhnushin N. , Borisenok D. , Blank A.
Published: December 2007

The Maloichskoe field is located in the southeastern part of the West Siberian basin in Novosibirsk oblast (Fig. 1). It was the first field in the basin where commercial oil was produced from the Paleozoic basement. The reservoir consists mostly of limestones and dolomites that are intensively fractured and contain numerous vugs in some zones. The reservoir properties of the matrix are generally negligible, and the production potential of wells is mostly associated with natural fractures and vugs.

The presented study was our first project in Russia where a complete integrated approach was implemented to properly characterize a fractured reservoir. The approach included the following tasks: 1) Identification of fractured intervals in wells using a special technique of BKZ logs processing, 2) Spectral imaging and high-resolution inversion of the seismic data, 3) structural analysis of the field, 4) construction of the reservoir properties model, 5) construction of the fracture distribution model using the Continuous Fracture Modeling approach (CFM).

The final geologic model served as a basis to select the locations for the new wells. The new locations were proposed in the zones with the most intensive development of a network of natural fractures (according to the model). The drilling was associated with significant losses of drilling mud that was an indirect indication of presence of significantly fractured zones. The wellbore image FMS that was recorded in the well, showed a good level of correspondence between the model forecast and the actual result. The well contains interval of numerous fractures and large vugs. Eventually, the well showed a good production results and currently is one of the best producers in the field.

As such, we recommend application of the described integrated approach for modeling complex fractured reservoirs in the other fields of Russian Federation.
Hydraulic Fracturing and Filtration in Porous Medium
Authors: Smirnov N. N. , Kisselev A. B. , Nikitin V. F. , Zvyaguin A. V. , Thiercelin M. , Legros J. C.
Published: December 2007

The practical problem arises in enhancing oil recovery and is relevant to hydraulic fracturing process and subsequent frontal displacement of fluids from subterranean environment. Entrapment of residual fluid by the displacing one lowers down the displacement quality leaving most of residual viscous fluid in porous matrix.

The present paper provides the data on hydraulic fracture simulation accounting for accumulation of damages in elastoviscoplastic medium, as well as the effect of inhomogenity of porous media properties on fracture propagation. After hydraulic fracture formation terminated the cleanup procedure begins. Fracturing fluid is evacuated from the well and fracture being displaced by the oil and gas flow under the influence of pressure differential. The quality of fracture cleanup determines in the long run the effectiveness of oil recovery measures. Fracturing fluid being left entrapped in the fracture decreases its effective oil collecting area. Thus stability and quality of displacement of fracturing fluid is of key importance to provide free way for the oil and gas flow.

However, in frontal displacement of a more viscous fluid by a less viscous one from porous medium by applying pressure differential the Rayleigh-Taylor or Saffman-Taylor instability of the interface could bring to formation and growth of "fingers" of gas penetrating the bulk fluid. The growth of fingers and their further coalescence could not be described by the linear analysis. Growth of fingers causes irregularity of the mixing zone.

The present study investigates analytically, numerically and experimentally the instability of the displacement of viscous fluid by a less viscous one from porous medium and evaluates characteristic size of entrapment zones. Both miscible and immiscible displacement was investigated. Extensive direct numerical simulations allowed to investigate the sensitivity of the displacement process to variation of values of the main governing parameters.

Taking into account non-linear effects in fluids displacement allowed to explain new experimental results on the pear-shape of fingers and periodical separation of their tip elements from the main body of displacing fluid. The effects of porous medium inhomogenity on the instability of fluids displacement were investigated both numerically and experimentally. It was demonstrated that definite inhomogenity could essentially stabilize displacement.
Riserless Mud Recovery (RMR) System Evaluation for Top Hole Drilling with Shallow Gas
Authors: Frøyen Johnny , Rommetveit Rolv , Jaising Hitesh , Stave Roger , Rolland Nils Lennart
Published: December 2007

The Riserless Mud Recovery (RMR) System is a new and emerging technology for top hole/open hole drilling. The technology is planned to be used in Russia in 2006. The RMR Technology is applied for the open hole sections (no BOP installed), enabling return of fluid and cuttings in a closed system. A subsea mud pump is returning mud and cuttings to the drilling rig for treatment/recirculation instead of dispersal on the seabed. Since weighted mud is used the risk of shallow gas influx is reduced compared to conventional top hole/open hole drilling. However, since the return is routed to the platform, shallow gas is a cause of concern.

A new transient coupled reservoir-well two phase well control simulator for modelling drilling and well control scenarios with a dual pump drilling system has been developed.

The paper describes the RMR System and its potential related to shallow gas detection and control compared to conventional top hole drilling.

Shallow gas scenarios during top hole drilling with the RMR System have been simulated and the results evaluated. The focus has been to detect a kick before gas reaches the return line. The evaluations have confirmed that the RMR System is a safe system, which can detect a shallow gas influx prior to gas reaching the return line, and also handle the influx in a safe manner. Modelling further shows that pit gain, sub sea power and RPM of subsea pump are the main parameters for kick indication. These results verify the feasibility of the RMR System related to safety and well control. In addition this System will reduce discharges to sea during top hole drilling, as well as significantly reduce the frequencies of shallow gas incidents.
A New Cement Developed for High-Temperature Sidetracks
Authors: Al-Yami A. , Jennings Scott , Nasr-El-Din H. A. , Khafaji AbdulKarim , Al-Humaidi Ahmed
Published: December 2007

Directional drilling makes it possible to drill multilateral wells into different parts of a reservoir from a single wellbore. Many directional wells are drilled to reach reservoirs inaccessible from a point directly above because of surface obstacles or geologic obstruction. Wellbore sidetrack drilling operations with hard cement plugs have been used for years. Placing cement plug in the borehole and allowing the cement to develop high compressive strength perform sidetracking technique. The hardened cement plug when drilled deflects the bit away from the current borehole, starting another open hole section.

Conventional cement formulations for sidetrack kickoffs usually fail when the ROP (rate of Penetration) for the cement plugs is much more than the ROP in the formation Sidetracking failures, in building up kickoff angles, results in operation delays and cost overrun. High compressive strength cement system with slow ROP should be designed and developed specifically for side tracking operations.

A rate of penetration device helped optimizing cement formulations to determine the ROP through cement plugs. This is done by controlled circulation of drilling fluid through the drill bit and rotating the bit at a fixed load and speed. Different chemicals for buildingup compressive strength were evaluated. Special types of cements were designed and evaluated for possible use for sidetrack kick off plugs. Addition of inert particles to cement and their effect on the compressive strength and ROP were investigated.

In this paper, a new system was developed and results in a slow ROP for the use in sidetrack drilling. The performance of this system outstand any known existing cement formulations for side track drilling and has great potential to improve sidetrack angle builds up.
Fracture Treatment Optimization for Horizontal Well Completion
Authors: Soliman M. Y. , Pongratz Reinhard , Rylance Martin , Prather Dean
Published: December 2007

Fracturing has become a viable and important option for completing horizontal wells. There are many fracturing processes and methods to consider for placement fractures. Optimization of the completion process including the number and size of fractures is still a challenge.

Although fundamentally similar to fracturing vertical wells, horizontal well fracturing has unique aspects that require special attention to ensure successful treatment. Differences exist between horizontal and vertical wells in the areas of rock mechanics, reservoir engineering, and operations. These aspects affect the optimization process for successful placement of treatments and optimum asset performance.

In this paper we discuss the various factors crucial to successful completion of a fractured horizontal well. We discuss these factors in relation to both longitudinal and transverse fracture applications. Success factors include the optimum perforation process, overcoming fluid flow convergence towards the wellbore in case of a transverse fracture, and the fluid flow and stress interference between multiple fractures.

The paper presents a field case and laboratory and numerical experimentations illustrating the impact of the various factors on the completion of the horizontal wells and the optimization of the fracturing process.
Sustaining Well Productivity
Authors: Weaver Jim , Nguyen Philip , Ingram Stephen
Published: December 2007

Surface modification agents (SMAs) and their coating onto proppant have been used in thousands of wells in the past 10 years resulting in significant improvement in productivity in terms of production rates and duration. In a recent field study1 involving more than 100 well stimulations, these SMAs were found to dramatically enhance the recovery of aqueous-based fracturing fluids during well cleanup following the fracturing treatments. This paper describes how a simple modification to proppant surfaces resulted in these dramatic post-frac well cleanups and subsequent well productivity. A comparison of laboratory results along with actual case histories will help explain the significant improvement in hydrocarbon production observed in fracture stimulated wells using SMA-coated proppant.
Advanced Technology To Reduce Water Cut: Case Studies From the Pemex Southern Region
Authors: Farrera Romo Gustavo A. , Leyva Héctor Hernández , Aguilar Raúl Bonifacio , Campos Carlos Caballero , Eoff Larry , Dalrymple Dwyann
Published: December 2007

This paper presents the results of a successful application of a new-generation polymeric relative permeability modifier (RPM) that enables treatments to reduce water cut without workover equipment. The new RPM can be bullheaded into open intervals without the need for isolating water zones from hydrocarbon zones. This treatment was applied to several wells in the Pemex southern region. As a result of the treatment, the productive life of the wells has been extended, with a gradual decrease in water cut. These results indicate high potential profitability values for mature fields with high water cut requiring a simple, low-cost treatment without the need for workover equipment or shut-in times. The new treatment can increase the hydrocarbon recovery percentage in sands that in all probability otherwise would be destined for abandonment.

This paper describes the treatment methodology, which begins with problem identification and an understanding of the origin of the water breakthrough. Next, the paper describes the new technology, which uses hydrophobically modified water-soluble polymers and explains how applying such polymers can control water selectively. In addition, the detailed execution of the treatment is described, followed by the very positive production results of the treatment. The results of this low-investment, high-profit technology are very promising for other wells under similar conditions in which workovers with conventional technologies would be cost prohibitive.
Wellbore Stability Study for the SAFOD Borehole Through the San Andreas Fault
Authors: Paul P. , Zoback M.
Published: December 2007

This paper presents a wellbore stability study of the SAFOD (San Andreas Fault Observatory at Depth) research borehole at Parkfield, central California. In the summer of 2005, the SAFOD borehole was successfully drilled through the San Andreas Fault (SAF) in an area characterized by fault creep and frequent microearthquakes. In this study we report how the analysis of wellbore failures in the upper part of the hole, geophysical logs and a model for stress gradients in the vicinity of the fault were used to estimate the mud weights required to successfully drill through the fault. Logging-whiledrilling acoustic caliper data and real-time hole volume calculations both show that relatively little failure occurred while passing through the SAF. Thus, the predicted mud weight was successful in drilling a stable borehole. However, a six-arm caliper log run after drilling was completed indicates that there was deterioration of the borehole with time. We suspect this was caused by failures along the weak bedding planes around the borehole, exacerbated by fluid penetration and key seating.
Applicability of Flow Assurance Solutions for Russian Oil & Gas Developments
Authors: Dykhno L. , Mehta A. , Moiseyenkov Alexey Vladimirovich
Published: December 2007

Over the past decade, flow assurance applications have been extremely successful in many offshore deepwater gas and oil project developments, where the cold ambient sea bottom temperature and water depth pose enormous technical challenges. Flow Assurance encompasses a broad range of technical areas, including management of solids such as hydrates, wax, asphaltenes to avoid blockages in subsea equipment and multiphase transport of produced reservoir fluids to a host facility. The high cost of remediation and limited accessibility for intervention of subsea equipment has highlighted the importance of developing robust flow assurance solutions in such severe operating environments. The operating environment that exists in many Russian gas and oil fields - both offshore and onshore - poses similar technical challenges. This paper notionally classifies Russian fields based upon their expected flow assurance issues and challenges and describes issues that are in common between deepwater production and oil and gas developments in Russia. We also demonstrate the applicability of lessons learnt from the deepwater to Russian oil and gas field production.
Data Richness and Reliability in Smart-Field Management – Is There Value?
Authors: Aggrey G. H. , Davies D. R. , Ajayi A. , Konopczynski M.
Published: December 2007

An essential part of the process to determine the value of advanced wells and fields is the explicit inclusion of the reliability of the various measurement sensors, in particular, and the data collection, transmission and analysis in general, when building the "Value Statement" to justify installation of intelligent wells. The desire for increased intelligence in the monitoring and control systems associated with Intelligent Well Technology (IWT) results in the deployment of more sophisticated and potentially accurate, downhole components of greater capabilities. However, these results in a more complex completion, which can be expected to exhibit a lower reliability than that shown by simpler system.

Ultimately, the greater number of more complex components may reduce the equipment reliability to such an extent that the increased chance of failure has reduced the "Value of Information" below that which can be derived from a simpler system. This paper uses a synthetic reservoir to explore and compare the value of extensive, accurate measurements with a higher chance of component or system failure (the "rich data" case) with the deployment of fewer and or lower resolution sensors of greater reliability (the "poor data" case).

The value associated with these two cases will be quantitatively compared in terms of a Risked Opportunity Loss. This comparison will illustrate how this workflow can be used to design cost-effective, well completions capable of Real Time Reservoir Management of an Oil or Gas field. The example chosen will also illustrate some of the drivers behind the choice of the optimum completion equipment.
Isolating Unwanted Water Production: The Through-Tubing Inflatable Solution
Authors: Kelbie G. M. , Garfield G. L. , Mackenzie G. R. J.
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.
Estimating Klinkenberg-Corrected Permeability From Mercury-Injection Capillary Pressure Data: A New Semianalytical Model for Tight Gas Sands
Authors: Huet C. H. , Rushing J. A. , Newsham K. E. , Blasingame T. A.
Published: December 2007

This paper presents the practical applications of a semi-analytical model for estimating the Klinkenberg-corrected permeability from mercury-injection capillary pressure (Hg-pc) data in tight gas sands. The fundamental relationships between rock pore size/geometry and basic rock properties are well-documented in the petroleum literature. Moreover, since rock pore characteristics can be accurately quantified from interpretation of mercury-injection capillary pressure data, the literature is replete with models for estimating permeability from Hg-pc data. However, existing Hg-pc models tend to yield inconsistent results — and few models have been shown to be directly applicable for low-permeability sands.

The basis of our model is the Purcell/Burdine model (bundle of capillary tubes) combined with the Brooks/Corey model (power law relationship of capillary pressure versus wetting phase saturation). We tested our model using more than 100 sets of mercury-injection capillary pressure data. Effective porosity in our data set ranges from 4 to 14 percent, while absolute permeability ranges from 0.005 to 0.5 md.

The primary technical contribution of this paper is a tuned model for estimating Klinkenberg-corrected permeability from mercury-injection capillary pressure (Hg-pc) data in tight gas sands. The final form of our model allows estimation of the absolute (Klinkenberg-corrected) permeability as a function of effective porosity, irreducible wetting phase saturation, displacement pressure, and pore size characteristics. The model is also reversible — we can estimate a capillary pressure profile from routine permeability and porosity data.
Evaluation of Friction Reducers for High-Density Brines and Their Application in Coiled Tubing at High Temperatures
Authors: Ke M. , Qu Q. , Stevens R. F. , Bracksieck N. , Price C. , Copeland D.
Published: December 2007

High density brines can provide increased hydrostatic pressure when used as cleanout fluids in coiled tubing operations. Due to the high viscosities of brines and the small diameter of coiled tubing, friction pressure loss will offset the additional hydrostatic pressure exerted by high density brines and lead to serious limitations in job design. One solution is to apply a friction reducer. Most commercial friction reducers are designed for water or low density fluids; their solubility and dispersion characteristics in high density brines are usually not acceptable. Additionally, high salt content and low free water in brines can diminish the effectiveness of a friction reducer. Many papers have been published on friction reducers in water or low density fluids in straight tubing and coiled tubing, but few have addressed friction reducers in high density brines. Evaluating a friction reducer normally requires full-scale flow loop testing, which requires a large volume of brine and prevents thermal evaluation of friction reducers.

This study used a newly designed coiled small-diameter tubing (CSDT) flow loop to evaluate the properties of friction reducers in high density brines. The study evaluated two conventional friction reducers in brines including NaCl, CaCl2, NaBr, and CaBr2 with densities from 10.0 to 14.2 ppg. The study presents results from both CSDT and full-scale flow loop tests and demonstrates that the CSDT flow loop is a simplified and effective setup that can qualify friction pressure loss in tubing and evaluate the effectiveness of a friction reducer in high density brines. Heat-aging tests also investigated thermal degradation of friction reducers in brines. The tests can eliminate some commonly used friction reducers for high temperature applications due to thermal degradation. A case history is presented which successfully applied a friction reducer in an 11.0 ppg CaCl2 brine for a coiled tubing cleanout at 400°F.
Intelligent Electronic Firing Heads: Advancements in Efficiency, Flexibility, and Safety
Authors: Goodman K. R. , Bertoja M. J. , Staats R. J.
Published: December 2007

Firing heads are widely used for initiation of perforating guns and other pyrotechnic devices in non-wireline deployments. For the last 25 years, these devices have been overwhelmingly based on hydraulic and mechanical designs; typically they require the shearing of pins through pressure activation or drop bar release. Features such as firing delays or multiple pressure cycle operation have been developed with additional complexity. These mechanical systems are less precise in operation due to tolerances and are also influenced by variations in downhole conditions such as temperature, pressure, and duration. Contrarily, electronic firing heads can be immune to these variations, while offering improved accuracy and control. No longer are high pressures needed to activate a firing head, instead low pressure coded command sequence of pulses can be used for communication. Delays can be extremely precise and simply programmed into the operation. The option to abort firing is also available, as well as the ability to measure and record dynamic pressures during the perforating event. Electronic firing heads have become the preferred solution due to the benefits they provide in safety, reliability and flexibility across numerous applications and deployments around the globe.

The ability to use a low pressure coded command for initiation has many advantages in operational logistics and safety. For slickline applications the firing process is controlled using line tension pulses; this combination provides a reliable solution with simplified deployment while still giving the operator control of the initiation process.

This paper describes the operation of an advanced electronic firing system and provides a number of case studies demonstrating the benefits for TCP, coiled tubing, and slickline perforating operations.
Successful Flow Profiling of Gas Wells Using Distributed Temperature Sensing Data
Authors: Johnson D. , Sierra J. , Kaura J. , Gualtieri D.
Published: December 2007

Distributed temperature sensing (DTS) coupled with a temperature-pressure simulator has been used successfully to determine flow profiles from multilayered commingled reservoirs in production gas wells. This technology has enabled quantitative individual-layer contributions to gas flow rates and main water entries to be determined, which in turn, has helped engineers to evaluate production conditions, track individual layer recovery, identify problem zones, and plan remedial actions.

DTS technology uses fiber-optic cables to measure continuous temperature profiles along the entire wellbore without any cable movement.

The real cases presented here include producing gas wells ranging from very low-permeability, hydraulically fractured tight reservoirs to high permeability sands with production rates from one (1) to tens of MMscf/d and over 50 layers per well at depths between 7,000 to 15,000 ft.

The analyses have shown that some of the key parameters required to obtain representative flow profiles using DTS can be extracted from the flowing and shut-in DTS transient profiles.

Those parameters, which are generally not available in conventional temperature logs, include: (i) geothermal profile; (ii) wellbore and near-wellbore Joule-Thomson effects, and (iii), thermal properties of fluids and formation. Non-producing, thick zones are particularly useful when calibrating partial flow rates and verifying fluid and formation properties.

The flow-profiling model was built around an analytical-numerical, pressure-temperature simulator that predicts wellbore temperature profiles as a response to individual layer flow rates and sandface fluid-entry temperatures. An interactive error-minimizing technique was used to match the simulated temperatures with the actual DTS profiles.

This paper also presents comparisons between the DTS-derived flow profiles and the traditional production logging tool (PLT) profiles as well as the value DTS can provide for multilayered gas-reservoir monitoring.