bluuebunny/crossref_metadata_2025 huggingface dataset:
Bedding-Related Borehole Instability in High-Angle Wells
Authors: Okland D. , Cook J.M.
Published: December 2007

In the Oseberg field in the Norwegian sector of the North Sea, extended reach drilling (ERD)has been employed to increase oil recovery. Wells up to 9,327 m total depth (TD) have been drilled. Hole stability problems were experienced in the Upper Jurassic Draupne Formation (Kimmeridgian shale) in a number of very highly inclined wells; these problems had not been experienced at lower inclinations. A rock mechanical study was carried out to explain and overcome the stability problems.

A series of thick-walled hollow cylinder (HC) tests were carried out on core material and analogous outcrop samples in order to identify the mechanisms of the hole problems, together with triaxial tests to obtain modelling parameters. Hole deformations were measured during external pressurization of the cylinders, and after testing the samples were sectioned and exiunined for damage. A very strong influence was found of the angle between the HC axis and the bedding plane of the shale. Specifically, if the HC axis lay more than approximately 100 away from the bedding plane, the hole was relatively stable; if the HC axis was parallel to bedding, the hole was highly, and catastrophically, unstable, forming very large regions of cavings. An anisotropic elastic model for the stresses around the hole did not predict such a sudden change in behaviour.

It was finally concluded that the borehole instability related to strength anisotropy associated with the pronounced bedding of the organic-rich Draupne shale. Spallings from the high side and the low side of the hole occurred at a number of different mud densities when the inclination was sufficientiy high. The decision was made to modify the wellpath so that the "angle of attack" between the well trajectory and the bedding planes in the Draupne Formation always exceeded 200. The world record well C-26 (9,327 m; 7,853 m horizontal reach) was sidetracked due to stuck pipe after an unsuccessful high-angle Draupne penetration. The sidetrack was stable at practically the same mud density, but with a lower inclination.

The reported type of hole instability is widely recognized in hard-rock applications of rock mechanics (mining, tunnelling), but is relatively new to petroleum-related rock mechanics.

P. 413
Rock Mechanics Applied to Drilling – An Operational Review
Authors: Svennekjær M. , Bratli R. K.
Published: December 2007

This paper gives effective procedures to drill wells in a depleted reservoir. From the fact that depletion result in decreased horizontal stresses and fracture gradients, the working hypothesis is that a depleted reservoir should be drilled by keeping the Equivalent Circulating Density (ECD) as low as possible. This have been achieved by using a low mudweight and applying the downhole pressure sub actively; which imply focus on the combination of hole cleaning, lower pump rates, avoiding backreaming, and careful breaking of circulation before pumps are started.

The pressure sub and theoretical calculations show that bottom hole pressure give peak values under the following circumstances: Too quick start of pumps/breaking circulation, too high mudweight, too high mud viscosity, too high tripping velocity, poor hole cleaning, too high pump rates, and pressure pulses. Other factors which may have some influence on the bottom hole pressure are: Well stability problems leading to excess fill and loading of the well, and unstable mud. An additional method to reduce the ECD is to increase the fluid column diameter by installing liner instead of casing or by drilling holes with a larger diameter. Also, an exact calculation of the ECD is usefull.

Three cases from three different wells are discussed, and theoretical calculations and observations are compared. We also observed that the fracture gradient of the borehole wall increased with time, which is usefull if it is not possible to go below the minimum fracturation gradient.
Prediction of Rock Parameters from Micro-Indentation Measurements: The Effect of Sample Size
Authors: Ringstad Cathrine , Lofthus Ellen Benedikte , Sonstebo Eyvind F. , Fjaer Erling , Zausa Fabrizio , Fuh Giin-Fa
Published: December 2007

Micro-indentation measurements have been performed in order to investigate the possibility of extracting rock mechanical properties from small rock samples. The tests were performed with a 1 mm flat indenter. Two parameters were determined when analyzing the indentation measurements: The Indentation Modulus (IM) and the Critical Transition Force (CTF). IM is the slope of the force-displacement curve, corrected for deformations in the load frame. CTF is defined as the force level where the material deforms without significant change in the applied force.

The rock samples were casted in a mounting material (Demotec 30), in order to stabilize the sample during testing, and simplify surface preparation. The upper and lower surfaces of the samples were made flat and plane parallel by grinding. 15 materials were tested, including sandstones, limestones and shale/clay materials with different strengths and stiffness.

The micro-indentation measurements showed that both IM and CTF were significantly affected when the experiments were performed on small samples with volumes ranging from 0.04 Cm3 to 0.7 cm3. Correlations combining the Uniaxial Compressive Strength (UCS), Young's Modulus (E) and porosity () with IM and CTF have been made. For measurements performed on small rock samples (embedded in Demotec 30) the following correlation with Uniaxial Compressive Strength was found:

UCS = 0.149 CTFR2=0.90

The correlation is only valid for small samples embedded in a mounting material with the same indentation properties as Demotec 30. It is not recommended to use the micro- indentation measurements to predict porosity and Young's Modulus.

P. 487
Production as a Tool to Control the Efficiency of Reservoir Fracturing: The Lacq Case- Study
Authors: Lahaie F. , Boyer E. , Grasso J.R. , Fourmaintraux D.
Published: December 2007

We analyze the feedback loop between production and the fracturing of a reservoir. We focus on a case of hydrocarbon recovery (Lacq, France), well constrained both in terms of production parameters and fracturing pattern, as a result of a 20-year monitoring of induced seismicity. Production, which plays the role of a stressing rate for the rocks surrounding the depleted zones, appears to have profound impact on the fracturing pattern of the reservoir, that ranges from a localized damage with relatively large fractures, to a diffuse damage with relatively small fractures, for high and low values of the production, respectively. As the fracturing pattern has been recently proposed to have far-reaching importance for the permeability and the increase of productivity of the reservoir through time, this study suggests the possibility to use production as a knob, so as to tune the response of the reservoir to a level of most efficient fracturing, in terms of hydrocarbon recovery. A careful monitoring of seismic indexes may help pinpoint the ongoing type of fracturing, and adjust production accordingly. This paper provides new routes for taking into account fracturing impact in production objectives.

P. 501
Frictional Contact On Cutters Wear Flat and Evaluation of Drilling Parameters of a PDC Bit
Authors: Geoffroy H. , Minh D. Nguyen , Bergues J. , Putot C.
Published: December 2007

Wear development during bit life modify the mechanical response of PDC bits and reduce their efficiency. Contrary to cutting mechanism, friction mechanism on wear flats which develops on the cutters, remains badly understood. A new friction law based on numerical and experimental studies has been stated by the authors. It depends on the material behavior, and relates the applied normal pressure to the wear flat to the subsequent dip angle a into the rock surface. Drilling parameters for PDC bits can then be evaluated, provided a reasonable wear law be postulated. Two different experimental benches have been built up, one for determining the parameters of cutting and friction mechanisms on a single worn cutter, and the other one for determining the global parameters on a small scale drill bench. Preliminary data allow to discuss some hypotheses of the model.

P. 87
Sand Production on Water Injectors: Just How Bad Can It Get?
Authors: Santarelli F.J. , Skomedal E. , Markestad P. , Berge H.I. , Nasvig H.
Published: December 2007

This paper presents a field case based upon a reservoir operated by Statoil in the Norwegian Sea. The case concerns a series of water injectors - i.e. both sub-sea and platform - that underwent extreme losses of injectivity over short periods of time. When worked over, the wells showed extreme amounts of sand fill that sometimes were several hundreds of meters above the top perforation. Furthermore, the link between well shut-ins and injectivity losses was clear right from the onset of the study.

The life of the injectors is thoroughly reviewed and the reasons for the injectivity losses are established.

First, it is shown that even under no flow conditions corresponding to shut in periods, the rock around the wells is too weak to sustain the stresses and fails. Second, it is established that because of permeability heterogeneity, the wells are cross flowing during shut in periods hence allowing sand to be produced in front of the perforated interval. Third it is shown that under routine operation conditions, the produced particles in front of the perforated intervals are not able to settle down in the rat-hole before injection restarts and hence plug the perforation tunnel upon injection restart. Finally, it is demonstrated that during a standard shut in, pressure waves as large as 80 bars are generated because of the so-called water hammer effect that hits the formations as would a seismic wave do. As a consequence, the formation already weakened by sand production undergoes liquefaction that triggers large amounts of sand to be released in the well, hence killing totally its injectivity.

Finally, the paper presents how the operating conditions of the wells were successfully changed to avoid the repetition of the problems experienced previously.

P. 107
Onset of Sand Production and Open Hole Stability Near Heated Horizontal Wells
Authors: Wang Yarlong
Published: December 2007

Steam injection through a vertical or horizontal well has been commonly exercised in heavy-oil reservoirs to enhance oil recovery. Thermally-induced effects may enhance the mobility of the formation by increasing the reservoir permeability and reducing the oil viscosity, but it can also crush the sand grain and damage the formation, rupture the casing, and eventually destroyed the well. Sand production and wellbore stability of the heated horizontal well are of great concern in well completion and perforation design. Formation damage due to stress concentrations induced by in- situ stresses and the temperature difference is responsible for sand production and instability. To analyze the formation damage and the induced stresses, a geomechanics model fully coupled to energy transport and fluid diffusion process is employed. Both the sanding risk and stability for open-hole cases subject to a non-isothermal, non-hydrostatic in-situ loading, and underbalanced/balanced drilling conditions are investigated. Critical drawdown is calculated based on the thermo-poroelastic theory. It is concluded that changing bottomhole temperature and injection rate can impose a significant impact on the wellbore stability and sanding potential. Specifically, the risks for sand production and that for wellbore instability can be reduced significantly by controlling wellbore temperature and injection rate.

P. 117
Application of Probabilistic Techniques for Assessing Sand Production and Borehole Instability Risks
Authors: McLellan P.J. , Hawkes C.D.
Published: December 2007

The mechanical stability of a borehole or perforation tunnels can have a critical influence on petroleum drilling and recovery processes. For instance, extensive failure of rock surrounding an open-hole completion may result in massive sand production. Furthermore, it is often necessary to evaluate the risk of borehole instability when drilling through weak shale cap-rocks, or when drilling underbalanced through poorly cemented reservoir rocks. Numerous geomechanical modeling techniques have been developed to address these issues. However, the existing models are limited in that they fail to account for the inherent variability of mechanical and petrophysical properties of rock, as well as uncertain or poorly constrained values for these and other critical input parameters.

This paper describes the adaptation of probabilistic techniques for quantitatively evaluating the risks of borehole instability or sand production. This technique involves the use of a versatile poro-elastoplastic model, implemented within the framework of a spreadsheet-based Monte Carlo simulation tool. The typical results generated by this model indicate that rock strength parameters, bottomhole pressure, reservoir pressure and near-borehole permeability changes have the most significant influence on the extent of yielding for underbalanced drilling or production conditions in weak sandstones.

P. 143
Ekofisk Field Overburden Modelling
Authors: Nagel N.B.
Published: December 2007

In weak formations, significant pressure depletion may lead to compaction. Transmission of compaction through the rock layers overlying the depleted formation may, in turn, cause subsidence. At the Ekofisk field, a large producing oil and gas reservoir located in the Norwegian sector of the North Sea, subsidence of the seabed due to reservoir compaction led to extensive facilities modifications in the mid-1980's and has significantly contributed to the need for the on-going Ekofisk II field redevelopment project.

While reservoir compaction is the source of the volume loss that leads to subsidence, transmission of compaction through the overburden strata often is a critical governing factor on its impact. Theoretical modelling work has shown, for example, the relationship between reservoir depth or width to the transmission of compaction to subsidence. Building upon the theoretical work and utilizing available field data, a numerical study was conducted to evaluate the impact that overburden behavior at Ekofisk field has on compaction and subsidence.

For the study, available field data for validating the modelling of the overburden were reviewed, including reservoir compaction data, platform subsidence data from the center as well as the edges of the subsidence bowl, data from eight bathymetry surveys providing information on the extent and change of the subsidence bowl with time, and overburden core and log data. The results of the study shed light on the impact of overburden stiffness, the extent, nature, and development of reservoir compaction, and the compaction to subsidence transfer ratio (C/S ratio) for the field.

P. 177
Integrating Wellbore Data and Geomechanical Modeling for Effective Characterization of Naturally Fractured Reservoirs
Authors: Olson J.E. , Hennings P.H. , Laubach S.E.
Published: December 2007

The quantification of fracture spacing and length are crucial for determination of effective block sizes to be used in reservoir simulation. Outcrop and modeling studies have shown that average values of these parameters do not adequately describe a fracture pattern, however. Observational work suggests that the cumulative number of fractures larger than a given size (in length or aperture) can be described with power-law relationships, and these empirical models are used to extrapolate from the observational scale to other scales of interest. Fracture spacing distributions are commonly described relative to their "saturation level," a measure of the regularity of the spacing between fractures of a given set that is thought to be related to strain level. As a spacing population approaches a normal distribution it is said to become more saturated or "well-developed," and this progression is assumed to be related to increasing strain imparted to a rock layer. A complication observed in sandstone outcrops from Oil Mountain, a Laramide anticlinal structure in Wyoming, is that fracture sets can reach saturation at different levels of strain even in the same bed. Assuming that average spacing indicates the level of strain accommodated by a given fracture set, the cross-fold fracture set from Oil Mountain requires very high strain to become saturated (spacing on the order of ift for a 30 ft thick bed). In contrast, the fold-parallel set displays a very high saturation at extremely low strain level (30 ft average spacing for a 30 ft thick bed). With a geomechanical model, we investigate the flindamental processes that control fracture propagation to explain spacing variability and suggest how to develop predictive models of fracture spatial arrangement.

In addition to discussing the mechanics of fracture network development, we address the sampling problems inherent in reservoir characterization. For subsurface fractures, measuring the saturation, length distribution, or connectivity is highly problematic because boreholes rarely encounter the fractures of interest. This is a serious impediment to acquiring sufficient data to constrain predictive characterization models that feed into reservoir simulations. Using Oil Mountain as an outcrop analog of a sandstone reservoir, we explore the use of microfractures as indicators of the attributes of large fractures. The advantage of microfractures is they are so much more abundant than macrofractures that they can be readily sampled from weilbores (a single thin section can produce thousands of measuments). If microfractures can be used as proxies for large fractures, then the results of predictive characterization modeling can be applied to subsurface cases much more effectively and accurately than has hitherto been possible.

P. 221
Dielectric Permittivity of Shales as a Measure of their Physico-Chemical Sensitivity
Authors: Fam M.A. , Dusseault M.B.
Published: December 2007

The specific surface of particles' and the properties of the pore fluid control the sensitivity of shales to a given change in the host environment. In this study, dielectric permittivity measurements are suggested to assess the reactivity coefficient, which is a measure of the physico-chemical sensitivity of a clay-fluid system. The effects of specific surface and pore fluid properties on permittivity data are discussed using dielectric spectra of ideal systems and real shale cores. Normalized high-frequency real permittivity data and the percentage of free water (estimated using high- frequency imaginary permitivity spectra) are shown to decrease with the increase in the reactivity coefficient. Similarly, high low-frequency permittivity values normal to the bedding plane indicate systems with high reactivity coefficients. Vertical strains measured during osmotic consolidation tests confirm the previous trend. Finally, general guidelines are presented to help in identification of reactive systems using complex permiflivity measurements.

P. 285
Plasticity and Permeability in Carbonates: Dependence on Stress Path and Porosity
Authors: Yale David P. , Crawford Brian
Published: December 2007

Pore collapse and the plastic behavior of high porosity chalks is well known but the extent to which harder, more moderate porosity carbonates are plastic is not as clear. We have experimentally determined the elastic and plastic deformation and effect of that deformation on permeability for a suite of carbonate rocks spanning the porosity range of 14% to 42%. The depositional environment of the carbonates was a shallow marine reef with some secondary porosity development.

Biaxial compression tests were carried out along various stress paths where the ratio of axial to radial effective stress change was kept constant. Yield and failure surfaces and strain hardening response were mapped as a function of porosity. Variation in permeability and compressibility as a function of porosity, lithology, and stress path were determined. The results were modeled with a critical state-cap plasticity model.

The deformation of the carbonates generally followed a critical state cap model. The yield cap and hardening function were strongly dependent on porosity. Even moderate porosity samples (15-22%) showed significant plastic strain under stress conditions attainable in many petroleum reservoirs. The compressibility of the samples in the plastic regime was a strong function of both porosity and stress path.

One aspect of the observed deformation that did not fit critical state theory was the long transition from elastic to fully plastic behavior. We found we could represent this behavior with two cap surfaces: an initial yield surface and final hardening surface.

Permeability reduction was a strong function of stress path. Permeability reduced less for a given increase in mean stress along stress paths with higher differential stress increments. Permeability reduction due to compaction was offset by permeability enhancement due to microcracking depending on stress path and differential stress.

P. 485
Plastic Modelling Of Compressible Porous Chalk and Effect of Water Injection
Authors: Homand S. , Shao J.F. , Schroeder Ch.
Published: December 2007

According to many experimental investigations of porous chalk an elastoplastic model with two yield surfaces is proposed. The physical meaning of the parameters of the model and the method used for their determination are explained. Some laboratory tests are then simulated in order to validate the model. Hydrostatic compression tests are performed using different kinds of saturating fluid. The chalk responses obtained can be classified into two groups corresponding to two groups of fluids : water and oil. The dependency of chalk behaviour with saturating fluid is explained through the capillary effect and "wettability" of the fluid. A new approach for numerical modeling is proposed it is assumed that there are two chalk materials, oil and water saturated, superposed on the same material point. Some validation examples are presented.

P. 495
Investigation of the Poromechanical Behavior of Shales in the Elastic Domain
Authors: Vincke O. , Longuemare P. , Bouteca M. , Deflandre J.P.
Published: December 2007

In order to study the poroelastic behavior of shales, a set of experiments have been performed in an uniaxial strain setup. The shales were cored at a depth about 450m. Assuming Biot's poroelastic theory, the Biot coefficient was determined in a uniaxial strain loading system.

At several steps of the mechanical loading in the plastic domain, the poroelastic properties are determined, A particular attention is paid to the evaluation of the Biot tensor by combining the results of 2 different mechanical unloadings. One consists in decreasing the total stress, the other consists in increasing the pore pressure,

Since the shales are anisotropic rocks, measurements have been performed on samples cored perpendicular to the bedding plane or parallel to the bedding plane. Three different rock samples have been tested and measurements have been performed in both directions,

The Biot coefficient is shown to change while loading is increased, on the other hand no significant difference is observed as a function of the orientation with regard to the bedding plane.

P. 515
The Norne Accident - Safety in North Sea Helicopter Operations
Authors: Heiberg Gunnar
Published: December 2007

The Nome helicopter accident is the worst disaster in Statoils 25 years of operation. This paper gives a resume of the accident, search and rescue operations, investigation and follow-up. Supplementing this is an overview of traffic volumes, historical risk, risk analysis studies and safety initiatives for offshore helicopter operations in Norway.
Prevention of Shallow Gas Migration Through Cement
Authors: Al-Buraik Khalid , Al-Abdulqader Khalid , Bsaibes Riad
Published: December 2007

The problem of surface gas migration is a common and dangerous one. Its presence can prove to be not only a nuisance but more importantly a serious source of well control problems. Various solutions have been tried worldwide with differing rates of success. The problem of surface gas migration was encountered during the development of a field in Saudi Arabia. Detailed analyses of samples showed the gas to be mostly nitrogen coming from depths between 400 ft and 1000 ft. Several techniques were utilized to combat the problem including the use of conventional fluid loss, conventional gas migration slurry as well as changes in the casing design programs. The only successful solution involved the use of a novel low-temperature gas migration product coupled with several modifications in the drilling practices. This paper discusses the nature of the problem and the different techniques applied with a focus on the particulars of the only successful method.
Wellbore Stability Analysis and Guidelines for Efficient Shale Instability Management
Authors: Tan C.P. , Rahman S.S. , Chen X. , Willoughby D.R. , Choi S.K. , Wu B.
Published: December 2007

An efficient approach to wellbore stability analysis and management of shale instability by taking into consideration the dominant instability mechanism(s) has been developed. The mechanism(s) is dependent on the type of shale, in-situ stress environment and drilling fluid system used. These factors determine whether a drilling fluid program can be developed using a mechanical (stress-induced) wellbore stability analysis or complex time-dependent drilling fluid-shale interaction and thermal mechanisms need to be taken into account.

A range of wellbore stability analytical tools for efficient management of shale instability is presented. A pragmatic approach to use drilling fluid design charts together with a shale property database and property correlations for designing optimal drilling fluids to manage shale instability efficiently is described. The utilisation of the tools is demonstrated through a field case study in which strategies are developed to control wellbore instability in horizontal wells. Parametric analyses conducted demonstrate the effects of shale and drilling fluid properties on time-dependent wellbore (in)stability. They highlight the conditions in which the drilling fluid-shale interaction mechanisms are critical and need to be incorporated in the analysis.

P. 165
Lithology Diagnosis Based on the Measurements of Drilling Forces and Moments at the Bit
Authors: Ziaja M.B. , Roegiers J.-C.
Published: December 2007

Most real-time drilling interpretation is performed using some sort of normalized rate of penetration to infer changes in lithology and evaluate the condition of the bit. This frequently leads to ambiguous or confusing results, because it is impossible to separate all bit effects from lithology effects using only one measurement. Also, no method exists to evaluate drill bit performance such as directional responsiveness and steerability. This paper proposes a new model of bit performance evaluation and shows how the force and moment measurements can be used to separate the bit effects from the lithology effects when drilling with PDC bits.

Analytical results of rock/bit interaction modeling are based on the laboratory drilling force measurements during rock comminution with a PDC cutter. It was found that a given rock/PD C system results in the specific relationship between axial and tangential drilling forces. This empirical relationship is used to determine the distribution of drilling forces and moments on a generic conventional PDC bit. Then, it is shown how the measurements of force and moment generated during drilling can be used in bit wear and lithlogy changes evaluations. This model accounts for abrasive wear of the cutters and detects those that are exposed to more severe loads. Thus, it may be also used as a guide in bit selection and bit design modifications.

If verified in the harsh economic environment of today, field application of the method should lead to a better understanding of downhole conditions and a more accurate decision as to what direction a bit is drilling, when to pull out bits, and thus to a reduction of drilling costs.

P. 185
Evaluation of Bit Performance Using An Advanced Drilling-Test-System
Authors: Xu H. , Hatakeyama T. , Yonezawa T. , Suzuki A.
Published: December 2007

Japan National Oil corporation (JNOC) has been in possession of an advanced Drilling-Test-System (DTS). This DTS can be used for full-scale indoor experiments and a series of tests on the rocks of Mudstone, Volcanic tuffs and Sandstone have been conducted by using it. The bit types used for those tests included PDC bit, Insert-tricone bit and Surface set Diamond bit. Bit performance is evaluated based on the values of the Rate of Penetration (ROP) and the impact on ROP of individual drilling variables. As a result, it is found that in comparison, the employed PDC bit appeared to be the most suitable bit for drilling on the rocks used for the tests. Meanwhile, tests using Water as drilling fluid were conducted and the results indicated that ROP and drillability could be significantly enhanced by improving the cleanness of bit and in-situ of bit. An embryonic model for PDC bit has been developed and verified to a certain extent. Further tests and analyses are still ongoing and it is expectable that, the results from the DTS test will significantly benefit to practical drilling optimization including bit selection, optimizing drilling and hydraulic parameters and diagnosing drilling problems.
Riser Lift Pump for Deep Water Drilling
Authors: Sangesland S.
Published: December 2007

A new riser system consisting of a lift pump located a distance down in a conventional marine drilling riser with a separate mud return line from the lift pump and up is used to reduce the hydrostatic head of the drilling fluid in the bore hole. The upper section of the riser above the pump outlet is vented to the atmosphere. A lower mud level allows a higher mud weight to be used. However, determined by the position of the fluid level it will result in a lower pressure at the casing shoe. The hydrostatic head of the drilling fluid and the seawater will be sufficient to control the bottom hole pressure after an emergency disconnection of the marine-drilling riser at the seabed. The riser joint which houses the pump can be located anywhere in the riser section depending on water depth, formation pore pressure etc., typically 200 - 300 m below the sea level. The system also allows the bottom hole pressure to be quickly adjusted by simply adjusting the air/mud level above the pump outlet in the marine-drilling riser.

P. 299
Applications of a Near Surface Disconnectable Drilling Riser in Deepwater
Authors: Kogure E. , Ohashi M. , Urabe S. , Tanabe A.
Published: December 2007

For deepwater offshore drilling operations, planning and operations must take into account the necessary time required to pull the drilling riser in case of an emergency. Operational limitations prevent the complete recovery of the riser prior to location evacuation, and physical limitations may cause a riser to stress fail catastrophically if hung off. Uncertainties in predicting the size and course of storms combined with the above limitations severely restrict the operational envelope of deepwater riser drilling. Both operators and contractors would benefit from a system that would allow a riser to be abandoned and later re-entered easily in deepwater.

P. 331
Evaluation of Viscous Oil-Bearing, Water Flooded Reservoirs
Authors: Olesen Jean-Rémy , Liu Chengbing , Zeng Wenchong , Mao Keyu , Zhang Zongjian
Published: December 2007

In this North China Basin field, the evaluation of newly drilled in-fill wells oil saturation, capillary-bound water volume and permeability is difficult. Conventional saturation evaluation is hampered by constantly varying water salinities due to the fresh water flooding EOR program. NMR-derived effective porosity, capillary-bound water volume and permeability are adversely affected by the extreme viscosity of the crude oil.

This paper presents a synergistic evaluation approach, combining conventional open hole data with NMR data corrected for viscous oil effects and cased hole gamma-ray spectroscopy data for complete evaluation of Phie, Sw, Sxo, Swirr and Kint. A new technique is developed to derive Sxo exclusively from NMR data and clay volume.

This synergistic approach overcomes salinity and crude oil viscosity problems, it also allows more accurate lithology and reservoir producibility estimation, but, the Sxo derivation from NMR data is only valid if crude viscosity is very high.
Fluid Placement Model for Horizontal Well Stimulation
Authors: Eckerfield L. D. , Zhu D. , Hill A. D. , Robert J. , Bartko K.
Published: December 2007

Acidizing is a common method of stimulating horizontal wells. The acidizing process is fundamentally different when applied in a horizontal well compared with application in a vertical well. The fluid distribution in a horizontal well is affected by a longer wellbore length, a broader variation in the reservoir properties along the wellbore, and possibly different mechanical means to place the fluids in the wellbore. A comprehensive fluid placement model linked with a reservoir acidizing simulator is essential to precisely design acidizing treatments for horizontal wells.

This paper presents a model of fluid placement in a horizontal well. The model predicts the placement of injected fluids by tracking the interfaces between different fluids in the wellbore. It is capable of tracking multiple interfaces for multiple injection stages in horizontal wells. For injection with coiled tubing, the model allows tubing tail movement during injection. It also handles simultaneous injection from the annulus and from a tubing string. The fluid distribution generated from the model can be used as input information in a reservoir acidizing model for sandstone acidizing design. Both analytical and discretized solutions of the model are presented in the paper. Examples in the paper illustrate the effects of such factors as velocity of tubing movement, annular injection, and a non-uniform distribution of flow into the reservoir on fluid placement in an acidizing treatment.

The fluid placement model can help to determine optimum tubing tail locations and optimal injection volumes of acids, to select the most appropriate diverting methods, and, hence, to maximize the benefits of an acidizing treatment.
Flexible 3.5in. O.D. MWD System Enhances Short Radius, Horizontal Drilling Applications in Shengli Oilfield, China
Authors: Hongwei Li , Page S. C. , Zhenghu Wang , Knight J. H.
Published: December 2007

A 3.5in. O.D. MWD system has been developed which is capable of providing Directional and Gamma Ray services in short radius wells at build rates up to 3.3°/meter, a build rate that had not previously been available through conventional MWD technology. Specially selected materials, innovative tool joint design and an integral MWD Transmitter/Drilling sub-assembly have been utilised in order to withstand the stresses associated with high build rates while maintaining full functionality in small diameter drill collars. Innovative testing methods were required to qualify the system for short radius applications, resulting in the implementation of significant design improvements.

Utilising the new MWD system with short radius drilling technology has opened up the possibility of horizontal re-entry of existing wells completed with small diameter casing. Three case histories in the Shengli Oilfield are presented. The three re-entry wells, Y-CP1, X-CP1 and L-CP1 had originally been completed in 139.7mm casing. Two of the re-entry wells were kicked off through 2.1meter casing windows using oriented whipstocks with 118mm and 121mm bits at 3235 and 2109 meters respectively. Well L-CP1 section milled 18 meters of casing then side-tracked and built angle, reaching a TD of 2906 meters measured depth. Build rates for the wells averaged 2.0°/meter with a maximum of 3.3°/meter. Maximum horizontal reach was 151 meters from landing point.

Performance of the drilling and MWD systems was excellent during the drilling phase of the wells. Using the knowledge and experience gained it will be possible to utilise the equipment to re-complete and extend the life of the numerous wells that have been completed in small diameter tubing in the Shengli area. Well designs can be planned that could not have been considered using conventional technology. Significant production gains will be made as a result.
Casing Shear: Causes, Cases, Cures
Authors: Dusseault Maurice B. , Bruno Michael S. , Barrera John
Published: December 2007

Casing impairment leads to loss of pressure integrity, pinching of production tubing, or an inability to lower workover tools. Usually, impairment arises through shear because of displacement of the rock strata along bedding planes or more steeply inclined fault planes. These displacements are shear failures triggered by stress concentrations generated by volume changes because of production or injection activity. Volume changes arise from pressure changes, temperature changes, or solids movement (solids injection or production).

Dominant casing deformation mechanisms are localized horizontal shear at weak lithology interfaces within the overburden; localized horizontal shear at the top of production and injection intervals; and, casing buckling within the producing interval, primarily located near perforations.

Mitigating casing damage usually means reducing the amount of shear slip or finding a method of allowing slip or distortion to occur without immediately affecting the casing. It is seldom that strengthening the casing-cement system will eliminate shear, although in some circumstances it may retard it. Proper well location or inclination, under-reaming, special completions approaches, reservoir management and other methods exist to reduce the frequency or rate of casing shear.
Multilaterals Convert 5 Spot to Line Drive Waterflood in SE Utah
Authors: Hall Scott D.
Published: December 2007

Horizontal technology has increased rapidly since the late 1980's. Most horizontal wells drilled in the U.S.A. have been in primary recovery applications. However, horizontal technology can be modified and applied to secondary recovery operations to improve sweep efficiency and recovery over vertical wells.

This case history reviews four years of a multilateral horizontal drilling program at the Aneth Unit and updates Ref 1 and 2. Multilateral drilling has converted parts of the Aneth Unit from 5-spot to line drive waterflood patterns. Drilling horizontal in both producing and injection wells with laterals parallel to each other may improve oil recovery by 15% of the OOIP in the zones horizontally drilled at the Aneth Unit. However, not all zones and not all parts of the field are economic for horizontal drilling. From late 1994 through early 1998, 143 laterals were drilled and completed as re-entries from 43 vertical wells (23 producing and 20 injection). Those 43 wells were drilled 214,000 feet from kick-off to total depth. Of the 214,000 feet drilled, 180,000 feet was pay. All 379 previous vertical wells drilled only 26,000 feet of pay. Horizontal drilling exposes magnitudes more of the pay zone to the wellbore.
3-D Geopressure Analysis
Authors: Kan T. K. , Kilsdonk B.
Published: December 2007

In clastic sedimentary basins, geopressure is controlled by depositional and diagenetic history as well as structural geometry. The shapes and sizes of pressure compartments depend on the 3-D structure and distribution of lithologies and faults. We developed 3-D geopressure analysis algorithms and methodology which enable interpreters to estimate, analyze, and visualize geopressure in 3-D. Potential benefits include: (1) more accurate pre-drill pore pressure prediction; (2) 3-D definition of pressure compartments; (3) enhanced interpretation of fault seal or leak from pore pressure distribution; (4) enhanced interpretation of fluid migration pathways. Careful velocity analysis after pre-processing of the 3-D pre-stack seismic data produces 3-D RMS velocities at every in-line and cross-line position through a volume. Further lateral smoothing removes velocity errors caused by near surface and acquisition noises. An interval velocity volume is generated from the smoothed RMS velocity volume. Calibration using offset wells is used to transform 3D seismic velocity into 3D pore pressure gradients. In addition, we have also developed an algorithm to generate minimum horizontal stress. Using difference of the minimum horizontal stress and pore pressure, we can calculate an effective stress volume. This is extremely important for casing design and evaluating seal integrity of the prospect.

We have generated and analyzed several 3-D geopressure cases in deep water Gulf of Mexico and South China Sea. Relationship between fluid pressure, faults and geometry can be visualized and interpreted inseveral ways: (1) a pressure volume may be combined with amplitude slices - this is best for understanding and visualizing the influence of subtle structures; (2) a pressure volume may be combined with interpreted fault surfaces to visualize the effects of major faults; (3) Interpreted fault slices may be combined with seismic geopressure lines. Pressure volumes are best viewed as part transparent, part translucent, and part opaque.
Breaking of a Paradigm: The Simultaneous Production of the Gascap and Oil Column
Authors: Billiter Travis C. , Dandona Anil K.
Published: December 2007

The conventional way to produce an oil reservoir that has a gascap is to produce only from the oil column while keeping the gascap in place so that it can expand to provide pressure support. Depending upon the geometry, reservoir dip angle, and oil production rates, gas can either cone down to the oil producers or breakthrough as a front, leading to substantial increases in the gas-oil ratios of the oil producers. This paper presents a unique production methodology of simultaneously producing the gascap and oil column while injecting water at the gas-oil contact to create a water barrier to separate the gascap and oil column. This methodology has application in reservoirs with a low-dip angle, relatively large gascap, and a low residual gas saturation to water. It is demonstrated that the net present value of the project is improved if there is an immediate market for gas. The work also demonstrates that the recovery from the gascap is minimally affected by heterogeneities in the reservoir. This is shown using geostatistical reservoir models. The effect of heterogeneities on oil recovery is also documented.
Integrated Approach to Drilling Fluid Optimisation for Efficient Shale Instability Management
Authors: Tan C. P. , Rahman S. S. , Richards B. G. , Mody F. K.
Published: December 2007

An integrated approach to drilling fluid design and optimisation, in terms of mud weight and chemistry, for efficient shale instability management has been developed in a collaborative project. The key drilling fluid-shale interaction mechanisms included in the state-of-the-art design criteria are mud pressure penetration, chemical potential and swelling-hydrational stress.

Fundamental concepts, processes, models and a range of novel test equipment and procedures for laboratory simulation of the mechanisms were developed. Shale and drilling fluid properties required for the models were determined using a range of analytical and laboratory techniques. The laboratory simulation results for various mud types were used in the refinement and verification of the models. The verified models, which have been integrated in a wellbore stability analysis software, were used to conduct analyses to demonstrate the effects of shale and drilling fluid properties on time-dependent wellbore (in)stability. They highlight the conditions in which the mechanisms are critical and need to be incorporated in the analysis. In addition, the test equipment also provide effective methods of screening drilling fluids (type and formulation) for their capacity to provide the required effective mud support with time for a given shale.

The understanding of the mechanisms of drilling fluid-shale interaction and the development of the capacity to model them enabled the development of drilling fluid design charts. These charts, together with a shale property database and property correlations, provide a pragmatic and effective approach for designing optimal drilling fluids to manage shale instability efficiently. The wellbore stability analysis software and drilling fluid design charts have been used in both drilling fluid program recommendation and back-analysis of field experience. A full-scale field trial of the technology is currently being undertaken in collaboration with an operating company.
A Case Study Using a Reservoir Simulation Model to Determine Fracture Azimuth
Authors: Yao Fei , Zhu Ding
Published: December 2007

The fracture azimuth is an important parameter for well performance after fracturing, especially in pattern water flooding in anisotropic reservoirs. There have been several methods developed to determine the fracture azimuth, but most of them are expensive, and/or have limitations in their applications.

This paper presents a case study of using a reservoir simulation model to determine the fracture azimuth by history-matching the production data from a fractured well. The method is practical and convenient. In this study, a 3D, 3-phase reservoir simulator was used to simulate the performances of hydraulically fractured producing wells in Toskoro field in China. Water flooding had been applied to the field before fracturing. Some producing wells then were fractured to improve their productivities. After fracturing, the water cut increased dramatically in some wells, which was suspected to have been caused by the communication between the fractures and the nearby water injection wells. The fracture azimuth of the wells was determined by matching the production history curves, and the simulation result showed that for the well having extremely high water cuts, the fracture was oriented towards the injection well.

The fracture azimuth was also detected by monitoring microseisms during the fracturing stimulation in four subsequent fracture treatments in the same area. The results confirmed the fracture azimuth obtained from the reservoir simulation model. The fracture azimuth was then used in well pattern design in water flooding and fracturing design in the same area to obtain the maximum benefit from hydraulic fracturing.