bluuebunny/crossref_metadata_2025 huggingface dataset:
Managing Seismic Positioning Uncertainty in HPHT Developments
Authors: Neuhaus Dietmar , Browning Greg , Estensen Odin
Published: December 2007

The accurate quantification and management of seismic positioning uncertainties have been paramount in securing the drilling operations and maximizing well life in two recent High Pressure/High Temperature (HPHT) developments in the UK Central North Sea.

In these HPHT fields, all development wells need to be drilled before onset of production, as drilling into depleted reservoirs is considered as high risk. Identifying the optimal development well locations that balance the needs for a safe drilling margin (downdip) vs maximizing well life (updip) is complicated by the presence of large seismic positioning uncertainties.

Very close cooperation and mutual understanding between the well engineer and the seismologist/geologist is required to develop the optimal drilling strategy. The first well was placed in an intermediate location from which recovery would have been feasible had the worst possible raybending effects materialized. While drilling, a predictive Vertical Seismic Profile (VSP) was acquired above the reservoir to check the relative position of the well and the presence/thickness of the Cromer Knoll, the seat for the production casing. Based on the first wells, a 3D Pre Stack Depth Migration finally resolved the positioning uncertainties. Risky and costly contingency operations have been avoided.
Monitoring Contact Movement during Depressurization of the Brent Field
Authors: Quint Edwin
Published: December 2007

The Brent field is embarking on the largest offshore oilfield depressurization project ever attempted. To allow cost-effective management of this process an extensive surveillance program is being executed; gathering formation fluid type as well as reservoir pressure data. Pressure data acquisition is well established, but for formation fluid type existing technology is pushed to its limits.

Cased-hole formation fluid interpretation has always been difficult in Brent because of the low formation water salinity combined with seawater injection. Now with oil rims moving to the crest into the original gascap and depressurization changing the properties of the gas and light oil, it has become a real challenge.

Initially Brent has used time-lapse capture sigma measurements1,2 to monitor the oil being swept by injection water. This was significantly improved upon, when the inelastic Carbon/Oxygen measurements3,4 were introduced, but the most reliable results were still obtained from simple open-hole logging data.

After the introduction of the monobore completions in Brent wells5, surveillance does not have to be restricted to slim (1 11/16") surveillance tools anymore since tool restrictions are removed in the monobore design. As a result, the larger (3 5/8") neutron and density open-hole tools can be employed in casing.

Calibrated cased-hole Neutron/Density surveys together with the original open-hole data have proven to be very successful in identifying the current formation fluids. They have also proven to be more robust against reservoir pressure decline and borehole content than Carbon/Oxygen methods.
Risk Decision Making in the Offshore Business
Authors: Tope I
Published: December 2007

Risk Management approaches are evolving in different industry sectors, and for different hazard groups. There is an increasing expectation for involvement and openness, with less trust in "expert" judgements. Also generally there is an ongoing change from prescriptive regulations to goal setting and the UK offshore industry is probably in the forefront of implementing a goal setting regulatory approach. This has increased in the demand for greater transparency on how the offshore industry in the UK makes decisions when managing major accident hazards. To meet this challenge, the UK Offshore Operators Association (UKOOA) commissioned the development of a framework to support such decision making.1 The framework focuses on major accidents, but its approach, and the ideas it embodies, are believed suitable for decision making involving environmental hazards.
Novel Hydrophobically Modified Natural Polymers for Non-Damaging Fluids
Authors: Audibert-Hayet Annie , Rousseau Lionel , McGregor William M. , Nicora Luigi F.
Published: December 2007

When drilling in the production zone the control of fluid-loss must be obtained without damaging the formation. The use of non damaging fluids is of great importance for:

the production zone of new wells, re-entry when drilling through damaged well bores, extended wells where large areas need to be protected, reaming to expose new production surfaces.

Formulations of non-damaging fluids are of growing importance especially because of the increasing number of horizontal wells being drilled. In horizontal wells, the drilling fluid is in contact with the reservoir formation for a long period of time and there are generally long, exposed zones of production which are difficult to clean up. Horizontal wells are often completed open hole without perforated casing, with therefore increased susceptibility to formation damage and reduced production.

A novel polymeric additive derived from a natural polymer which has been modified to optimise its performance is proposed. This optimisation is achieved by introducing hydrophobic attachment to the polymer backbone. This increased hydrophobicity improves dramatically the fluid loss control without increasing viscosities, in particular through the formation of a thin and impermeable filter cake which protects the production zone from fluid invasion. This thin filter cake is easily removed at low production pressures and allows excellent productivity. In simulated well conditions, such as long core formation damage test, an extremely low formation damage was shown with high return permeability values.

This new polymeric additive is especially advised for use in the preparation of drill-in fluids, in fresh water or brine, in combination with biopolymer and calcium carbonate.
Negative Alkalinity Invert Emulsion Drilling Fluid Extends the Utility of Ester-Based Fluids
Authors: Patel Arvind D.
Published: December 2007

Biodegradability of drilling-fluid chemicals is becoming a requirement for discharge of drilled cuttings on offshore drilling operations, especially in Europe. Due to their ready biodegradability, fatty acid esters are very popular in the North Sea. While esters enjoy advantages over other synthetic-based fluids on the biodegradability issue, their drilling fluid performance has remained substandard. The ester-based fluids undergo hydrolysis in the presence of lime at temperatures exceeding 200°F (93°C).

A new approach to the stability of ester-based fluids is a new, negative-alkalinity ester-based drilling fluid that is stable up to 350°F (177°C). The thermal stability and performance characteristics of the negative alkalinity ester-based drilling fluids are superior to the conventional ester-based mud formulations. The system uses a surfactant package that is designed to perform as an invert emulsifier under negative alkalinity conditions. The negative alkalinity ester-based drilling fluid system is simple and easy to run without any exotic change in the chemistry of esters. The system can be formulated using relativity inexpensive and readily available fatty acid esters. Due to the enhanced stability of fatty acid esters in this system, the selection of the esters utilized in this system can be based on economic considerations and availability rather than hydrolytic stability of the ester base fluid.

The thermal stability and performance characteristics of the negative-alkalinity ester-based drilling fluid are presented in this paper. A comparison of stability of the various types of ester base fluids using negative alkalinity invert emulsion and conventional reserve alkalinity ester-based drilling fluid shows that the negative alkalinity ester-based drilling fluids are stable up to 350°F (177°C). The paper discusses the overall impact of negative alkalinity ester-based drilling fluid in meeting the environmental and functional requirements of drilling operations and the economic advantages derived from this innovative system.
The Alba Field Ocean Bottom Cable Seismic Survey: Impact on Development
Authors: MacLeod M. K , Hanson R. A. , Bell C. R. , McHugo S.
Published: December 2007

In early 1998, Chevron acquired one of the world's first full-field four-component ocean bottom cable (3D/4C OBC) surveys at the Alba field in the central UK North Sea. The primary objective of the survey was to use converted shear waves to provide a better image of the sandstone reservoir and shales within the reservoir. Pre-survey technical studies based on a dipole sonic log and 2D OBC seismic lines gave us confidence that converted waves (PS) could provide a better image of the reservoir relative to conventional P-wave seismic data.

The secondary objective of the new survey was to map water movement in the reservoir after four years of production and water injection by comparing the new P-wave OBC data with the original 1989 streamer data. A strong original oil-water contact reflector seen throughout much of the field and pre-survey technical studies suggested that production-related saturation changes would be observable on the new P-wave OBC seismic data.

The new data shows that both objectives were achieved with dramatic results - the converted-wave images provide the clearest image of the Alba reservoir sands ever seen and production effects are obvious on the new P-wave OBC data near several producing and injector wells. In addition, the converted-wave data has offered new insights into the shape of the reservoir. The previous lens-shaped interpretation based on P-wave data has been replaced with a far more complex shape that is at least in part related to post-depositional structural alteration. This new interpretation is also supported by improved reservoir images seen on far-offset P-wave sections.

To date, two successful wells have been drilled based primarily on the converted-wave seismic data. Both wells prove the existence of ‘wings’ – structurally high sand at the margins of the channel that may represent re-mobilized and injected reservoir sand. Neither of these wings had been previously identified on the conventional P-wave streamer seismic data.
Designing Teams for Safety, Productivity, and Job Satisfaction: Recent Research and Operator Experience
Authors: Everest P. , Lardner R. , Turek M.
Published: December 2007

One of the most cost-effective methods of work organisation for manufacturing industry is self-managing teams (SMTs). SMTs have an established track record of improving productivity, job satisfaction and employee involvement. There has been a recent trend for onshore and offshore petrochemicals and process industry operators to implement SMTs. A fundamental aspect of SMTs is devolving day-to-day responsibility and decision-making to employees, and reducing or eliminating the role of the first-line supervisor. However, the suitability of SMTs for safety-critical operations has been questioned, and anecdotal evidence exists of flawed implementation and lapses in safety.

This paper summarises the results of (a) a joint industry project, funded by the UK Health and Safety Executive (Offshore Safety Division) and BP Oil, which examined the safety implications of self-managed teams and (b) operator experience of SMT implementation on BP's Miller Field from 1995 to date.

Planning for the post-plateau years of the Miller platform in the North Sea truly commenced whilst the installation was still in the blocks in Newcastle. However, detailed research for the shape of an offshore organisation that would see the facilities into anticipated post-plateau and other, then unknown, challenges, commenced in 1995. Implementation of a project to install SMTs commenced in 1996 and since that time considerable progress has been made in developing the practical application of self-managing teams in an offshore environment. The platform management team may claim only modest success with SMTs, but in reality the project has delivered considerable revenue savings to the Miller business and above all has made a significant contribution to the HSE programme for the business. Our belief is that through SMTs Miller will be enabled to deliver exemplary business, and especially, exemplary HSE performance.
Balanced Approach to Health and Safety Management
Authors: Bell Eric R. G.
Published: December 2007

Conoco (U.K.) Limited (CUKL) has a proud history of achievement in its approach to Health and Safety management. Our motto, Our work is never so urgent or important that we cannot take time to do it safely, fosters a principled approach to safety management and has served us well for many years.

The continuing challenge is to ensure that the organisation does not become complacent in respect of safety management. Whilst strong leadership and management commitment are critical in the achievement of a safe performance, they represent only one measure of success. Conoco believes that the key to excellence in this area is the enrolment of the entire workforce; the employees and contractor personnel alike who are engaged in the work of the company thus creating a balanced approach to Health and Safety management.

This paper will describe clearly the action taken, primarily since the beginning of 1997, in achieving the balanced approach while considering the consequent effect on safety performance.
Stochastic Inversion for High Resolution Reservoir Characterisation in the Central Sumatra Basin
Authors: Sams M. S. , Atkins D. , Said N. , Parwito E. , van Riel P.
Published: December 2007

High resolution models of complex reservoirs can be obtained through stochastic inversion combined with lithology simulation. The models are constrained by the requirement to honour all seismic, log and geologic input data. Generation of multiple models fulfilling this requirement permits the uncertainties to be quantified. Model realisations at high resolution mean that the properties of individual reservoir units that are not resolved by conventional seismic reflection imaging techniques can be investigated.

Stochastic inversion with lithology simulation is a powerful tool for integrating a wide variety of data - geological, geophysical, petrophysical and statistical - to produce constrained, detailed models of reservoirs. These models can be used for static or dynamic modelling. The technique is well suited to mature fields such as those in the Central Sumatra Basin, where the objectives are to find bypassed reserves and optimise well planning for secondary or tertiary recovery.

A case study from the Libo SE field of the Central Sumatra Basin is presented. Deterministic inversion of the seismic data could not resolve all the sand units of interest in the complex reservoir of this field. Stochastic inversion with lithology simulation resulted in reservoir models from which the distribution and properties of the individual sand units could be predicted. The high quality of these models was confirmed by the results from recent drilling.
Locating Remaining Reserves Using Inside Tubing PNS Logging
Authors: Njoku Chima
Published: December 2007

In the Brunei deltaic environment, prediction of present fluid contacts from simulation models is difficult. Presence of sub-seismic faults as well as cross flows between reservoirs have been established in some cases. It is thus important to explore other cost-effective methods to confirm or locate by-passed/undrained reserves before embarking on any new perforations or in-fill well drilling. One such method is inside tubing pulsed neutron spectrometry (IT-PNS) logging.

IT-PNS logging entails logging slim PNS tools inside the long/single string with the well closed in more than two days before the logging. One pass in the SIGMA mode for gas detection and multiple passes in inelastic mode for oil "saturation" are logged.

The first (trial) IT-PNS well was logged in August 1998 and since then, as many as thirteen Brunei Darussalam wells have been logged using this technique. Results show that: (i) the technique can be successfully used to determine present formation fluid types, even in low porosity/permeability reservoirs. (ii) there is no need to use a rig for fluid contact measurement. (iii) in static conditions, the annular fluid type will have little or no impact on the final interpretation. (iv) three to four inelastic passes are adequate for interpretation of the liquid phase. (v) by-passed reserves have been located using the technique, thus reducing the risk of drilling dry holes.
An Alkaline Bio-Surfactant Polymer Flooding Pilots in Daqing Oil Field
Authors: Demin Wang , Jiecheng Cheng , Qun Li , Lizhong Li , Changjiu Zhao
Published: December 2007

After studying zones, geological sediments, oil and water, etc. of different characteristics, an Alkaline-Surfactant-Polymer flooding formulation mainly with alkylbenzene sulfonate was screened. Pilot investigation with this formulation has been conducted with different alkali and different zones, good results have been achieved both technically and economically.[1,2]

Based on former study results,[3,4] screening of ASP formulations to further reduce the usage of surfactants and get better technical and economical results were performed. The interfacial tension behavior between oil and bio-surfactant ASP systems, emulsion characteristics, adsorption, core flooding, as well as numerical simulation, etc. were studied. After success in the laboratory study, the first Alkaline Bio-Surfactant Polymer Flooding Pilot was conducted in the north of the oil field.

Both laboratory and pilot studies showed that the Alkaline Bio-Surfactant Polymer Flooding system not only can further reduce the usage of surfactant and dynamic adsorption, but also can further reduce the ultra-low interfacial tension, extend the ultra-low interfacial tension area. Its emulsion phenomenon and chromatographic separation was not significant. After the implementation of the Alkaline Bio-Surfactant Polymer Flooding pilot, good results in terms of daily water cut decrease and incremental oil of the central well were obtained, the actual production data was better than the numerical simulation prediction.

Now, the oil recovery of the central area is 21.5% OOIP over that of water flooding, preliminary economic analyses show that the chemical cost per ton of incremental oil is less than 30$. This should be a good bio-chemical flooding method.
The 3-D Architecture of Point Bar and The Forming and Distribution of Remaining oil
Authors: Ma Shizhong , Zhang Jing , Jin Ningde , Wang Zaishan , Wang Yuming
Published: December 2007

It has generally been considered that remaining oil forming in vertical is mainly controlled by permeability succession, the important effects of very thin lateral accretion mudstone (LAM) interbeds and permeability subsuccession have been neglected. By analyzing the sedimentary processes and efficiency of displacement oil (EDO) of point bar in P I 2 time unit, Daqing oilfield, point out that the 3-D architecture of point bar is the key of the forming and distribution of remaining oil (FDRO) and that many lunate-shape, oblique, very thin (<20cm thickness) LAMs in point bar are the most important barrier beds and permeability control-framework, and that lateral accretion sandstone body (LAS) is the basic and important unit of controlling spatial distribution of permeability in point bar, and set up the "3-D architecture of LAM+LAS+fluid density difference" model of FDRO.
A Technology of Soaking and Discharging CO2 to Enhance Production in Binnan Tract
Authors: Zhigang Wang , Shijun Fan , Guilin Zhu , Zenghai Ma , Jinfa Li
Published: December 2007

In Binnan Tract of Shengli Oilfield, there is sufficient CO2 in the reservoirs and there are much reserves suitable to take the measure of soaking and discharging CO2 to enhance production. In this paper, laboratory experiments and field tests have been conducted pertaining to this technology, and the results indicate that under the pressure of 25MPa, CO2 can mix with oil well. Then, the recovery efficiency of residual oil by water drive can increase 10%. The results of numerical simulation show that optimized effect can be reached through regulating the volume of CO2, duration of soaking, injecting and discharging velocity, while the production will decrease in the second stage compared to the first one. The processes of reverse injection, corrosion and expansion prevention, were taken in the field test, which input-output ratio was as high as 1:4.22, proving that this technology is viable in small lower-permeability reservoirs.
Gas Lift Optimization Efforts and Challenges
Authors: Chia Y. C. , Hussain Sies
Published: December 2007

Gas lift plays an important role in Esso Production Malaysia Inc. (EPMI) oil production operation. As oil fields mature, the production facilities need to handle increasing water and gas. Gas lift optimization is crucial to ensure maximum oil production within facility constraints. Nodal analysis, Gas lift Optimization Allocation model (GOAL), gas lift databases and Gas Lift Monitoring System (GLMS) are among the tools applied to meet the objective. Some of the challenges encountered during the gas lift optimization efforts are dual gas lift optimization, tight dummy valve retrieval at one particular platform, production from thin oil column, emulsion and sand production.
Study on Genetic Type and Potential Tapping Measures of the Remaining Oil in Multilayered and Heterogeneous Sandstone Reservoir
Authors: Qinglong Du , Yongsheng Zhao , Yinyin Lu , Liting Zhu
Published: December 2007

The various influential factors for remaining oil space distribution are discussed on geological and productive basis. Genetic types of areal and vertical remaining oil are summarized while corresponding potential tapping measures for remaining oil with different genetic types are put forward by combining production technologies and means. Several examples are presented here for their success in tapping the potential of remaining oil at the late period of high water cut stage in Daqing Oilfield.
Emerged Horizontal Drilling Technology and Its Applications in Saudi Oil Fields in The Last Ten Years
Authors: Al-Blehed M. S. , Hamada G. M.
Published: December 2007

The technology of drilling and production of horizontal wells is probably one of the most significant breakthrough in the oil and gas industry of the eighties. What was considered ten years ago, as an exotic way of drilling has become reality. The continuous improvement of hardware equipment made horizontal drilling cost-effective technique for developing reserves, improving productivity and recovery in oil and gas reservoir.

Horizontal well technology continues to be at the forefront of the oil industry. This paper will highlight the Saudi experience in horizontal drilling. The past ten years have been an exciting period for those who believed in horizontal drilling applicability in Saudi Arabia. At the end of the year 1997 over than 150 horizontal wells have been drilled in Saudi oil fields. There are four major horizontal well applications identified in Saudi Arabia oil fields; 1) Control of coning in relatively thin remaining oil column area, 2) Improving sweep efficiency of water flooding program, 3) Improving productivity rate in thin/tight reservoirs and 4) Saving in total development costs in conjunction with previous three applications.

This paper presents the major areas of application of horizontal wells and more specifically the objectives of applying horizontal drilling in different Saudi oil fields. In this paper, the world horizontal drilling activities along with the Saudi experience will be covered. This paper surveys different field examples to show the application trends of horizontal well technology in both offshore and onshore oil fields. The main objective of this survey is to demonstrate the performance improvement of these oil fields after the application of horizontal well technology.
Relative Permeability Ideas-Then and Now (Richards to Leverett to Yuster, and Beyond)
Authors: Rose Walter
Published: December 2007

Here in an Appendix are some paraphrases with updated annotations are presented of the Author's changing ideas over the years about relative permeability phenomena. These have been contained in a series of publications from 1948 to date, however not always in a concordant way. In point of fact, some initially were chosen to be consistent merely with empirical information. More recently, however, the papers have tended to be based on the prescripts of non-equilibrium thermodynamics.

In one way or another, and indeed now for almost a Century, the voluminous literature on the subject has substantially been influenced by the evolving understandings about the meanings and applicability of what today still remains to be a perplexing (rather than an ubiquitous) relative permeability concept. Some might say (but others, not) that this very subject already has been sufficiently dealt with by generations of previous authorities. Outstanding ones to be mentioned here are Richards (1931), Leverett (1942), and Yuster (1951), but passing reference also will be made to the remarkable achievements of other gigantic innovators. Any mention a few of them would surely include the works of Edgar Buckingham (1907), Josef Kozeny (1927), M. King Hubbert (1935 and 1956), P. C. Carman (1937), G. L. Hassler (1944), Morris Muskat (1937 and 1949), J. R. Philip (1955) to date, A. E. Scheidegger (1957 as revised in 1974), M. R. J. Wyllie (1962), E. C. Childs (1969), Jacob Bear (1972) to date, Francois Kalaydjian in the 1980s and 1990s, and Steve Whitaker et al (1986 et.seq.). Even so, the simple aim held by the Author of the present paper is to show that further clarifications still are urgently needed. And the focus of major importance now should have to do with how best to measure and to apply relative permeability data whenever simulation studies of reservoir transport processes are to be undertaken.
Effects of Coalbed Reservoir Property Analysis Methods on Gas-In-Place Estimates
Authors: Nelson Charles R.
Published: December 2007

Accurately determining the gas-in-place volume is a crucial element of coalbed gas resource and reservoir evaluation. Different reservoir property analysis methods can yield very different gas resource and gas-in-place values. This paper presents results from evaluations of the accuracy of commonly used reservoir property analysis methods. Many commonly used analysis methods were found to have inherent shortcomings that can result in large (50% or greater) underestimation error in the gas-in-place value. Six major sources of error are: (1) basing the reservoir volume on the assumption that the coalbed reservoir thickness and lateral continuity are invariant, (2) using 1.75 g/cm3 as the maximum log density value for determining the gross reservoir thickness, (3) using 1.32 to 1.36 g/cm3 for the in-situ density of coalbed reservoirs, (4) basing the in-situ gas content on gas desorption data obtained at ambient temperature conditions, (5) basing the in-situ gas content on gas desorption data obtained from drill cuttings, and (6) basing the in-situ gas content on the assumption that the residual gas volume is negligible. Because these six error prone analysis practices have been so widely used in the past there may be significant potential for large gas-in-place and reserve estimate gains in many existing coalbed gas fields.
Case History: Automation System Increases Production and Enhances Well Safety in the Ramos Gas Field In Argentina
Authors: Reyes Alfonso , Plunkett Joe , Teja Ricardo , Zambrano Oscar
Published: December 2007

The automation of the high-production Ramos gas field, located in the northern region of Argentina, has enhanced field production and well safety and also improved operations by centralizing control of the gas production. A field supervisory control and data acquisition (SCADA) computer located in a gas treatment plant automates the gas production throughout the field by means of a radio telemetry link to a well control unit (WCU) that is located at each automated well site. From the plant, operations personnel can change the production rate or monitor production variables at any wellsite, view real-time or historical trends of those variables, or change alarm setpoints in a WCU from graphical screens on a computer console. The computer archives the production data onto a hard disk for further processing and analysis.

A solar-powered WCU located at each site controls well production by means of an electrically activated choke mounted on the wellhead. The WCU, a microprocessor-based controller, monitors operating pressures, temperatures and tank levels, and it ensures well and flow-line safety by controlling the operation of the surface safety valve (SSV) and the sub-surface safety valve (SSSV).

Currently, the automation system involves nine wells. Early in 2000, three additional wells will be automated.
Performance Drivers in Restimulation of Gas Storage Wells
Authors: Mohaghegh Shahab , Mohamad Khalid , Popa Andrei , Ameri Sam , Wood Dan
Published: December 2007

In order to maintain or enhance deliverability of gas storage wells in the Clinton Sand in Northeast Ohio an annual restimulation program has been in place since the late sixties. The program calls for as many as twenty hydraulic fractures and refractures per year. Several wells have been refractured three to four times while there are still wells that have only been fractured once in the past thirty years.

As the program continues many wells will be stimulated a second, third or fourth time. This paper summarizes an attempt to carefully study the response of the Clinton sand to hydraulic fractures and identify the performance drivers in each series of frac jobs. Do the performance drivers remain the same for the later fractures (second, third and fourth frac jobs) as they were in the first ones? Or do they change? This paper attempts to answer such questions.

Identification of major performance drivers becomes important when new jobs are to be designed. They not only play an important role in enhancing the response of the wells to new stimulation jobs; but also may prove to be an important economic factor in the design of new stimulation procedures. If for instance it is concluded that an increase in proppant volume does not influence the stimulation outcome after the second refracture, then fewer resources can be used for proppant volume and be directed toward parameters that are more influential.

This study employs a combined neural network and fuzzy logic tool to identify the performance drivers.
Equation for Estimating Mud Minimum Rate for Cuttings Transport in an Inclined-Until-Horizontal Well
Authors: Rubiandini R. S. Rudi
Published: December 2007

There are so many problems associated with cuttings deposited in the well bore when we using rotary drilling methods to drill some vertical wells, directional wells or even horizontal wells. To overcome these cuttings problems we have to determine a mud minimum rate which has a capability to clean the drilled well bore. This mud minimum rate is sum of the slip velocity and the velocity of the fallen cuttings. It is obvious that velocity of the cuttings are depend on the well bore geometry and the magnitude of the ROP. Hence this cuttings velocity will be constant for a specific well bore. This paper develops Moore's slip velocity of vertical well in order to be used in the inclined well until horizontal well with some corrections of rotary speed and the mud weight by Larsen's slip velocity procedure. The corrections of inclination angle, RPM and the mud weight are obtained from Y axis of cartessian dimensionless plotting of slip velocity with the inclination angle at X axis. Dimensionless slip velocity equals Peden's experiment slip velocity data and Larsen's calculation results for inclined well divided by Moore's slip velocity for vertical well. The paper results a new equation to determine the mud minimum rate which would lift the cuttings in the inclined through horizontal well bore. In the case of inclination angle > 45°, the mud minimum rate of Larsen's method, Larsen's experiment data and Peden's experiment data have no significant difference with this new equation in the paper. On the other hand, at inclination angle < 45°, the new equation results a higher mud minimum rate than all of the methods above resulted.
Organic Formation Damage Control and Remediation
Authors: Newberry M. E. , Barker K. M.
Published: December 2007

Organic skin damage in oil producing wells is a major factor in the loss of productivity and revenue. Paraffin and asphaltene deposition in the formation and around the well bore creates a barrier for the transportation of the crude oil to the tubing. Many producing wells have experienced a production decline that can not be explained by reservoir depletion. Organic damage may occur naturally or through various intervention practices used in the oilfield. An increased awareness of the potential for ongoing organic damage has been developing slowly over time. Better methods of problem identification and programs to remediate these problems have been developed in recent years. The potential sources of organic damage, problem identification test techniques, chemical selection and application methods are discussed. Numerous case histories for a variety of problems are also presented.
Interpretation of Pressure Buildup Curve in Layered Reservoirs With Afterflow
Authors: Yakimov A. S. , Diyashev R. N. , Iktissanov V. A.
Published: December 2007

Many authors have investigated the behavior of layered systems under pressure transient test. Determination of filtration parameters by known procedures is conducted either without consideration of wellbore storage effect, or with differentiation or integration of experimental bottomhole pressure values. In either case it leads to errors in interpretation of pressure buildup curve. In this work a new technology on conductance of investigations and interpretation of results is suggested. The investigations consist in determination of flow rate from each formation in producing well, taking pressure-build-up curve and determination of crossflows between formations in shut-in well. Interpretation of pressure buildup curve is connected with numerical solution of differential equation for unsteady filtration with consideration of afterflow into the well. The advantages of suggested technology are simplification of conductance of field investigations and improvement of accuracy of determination of filtration parameters and formation pressures for layered reservoirs.
Improved Frac-Packing Method for Long Heterogeneous Intervals
Authors: White W. S. , Morales R. H. , Riordan H. G.
Published: December 2007

This paper presents an innovative way to uniformly frac-pack long heterogeneous perforated intervals by pumping several independent slurry schedules without shutting down pumping. The purpose is to fracture the least stressed zones first. The other zones are sequentially frac-packed thereafter. Shunt tubes are used to facilitate the slurry diversion. The shunt tubes, which run along the outside of the sand control screen, provide an alternate path for the slurry to travel in the event that proppant bridges block the traditional annular path.
Skin Self-Cleaning in High-Rate Oil Wells Using Sand Management
Authors: Dusseault Maurice B. , Waterloo A. S. , Tronvoll Johan , Santarelli Frédéric J. , Santarelli Frederic J.
Published: December 2007

Mechanical skin develops around high-rate oil wells because of mineral salt precipitation in the near-wellbore region, because of fine-grained minerals accumulation that block the near-wellbore pore throats, because of capillary forces development that impair free flow, and because of asphaltene or other organic substance deposition that reduces effective porosity. The removal of mechanical skin is normally carried out by workover techniques that require wellbore intervention.

As early as 1994–95, it was found that for wells in poorly consolidated sandstones many of the problems of mechanical skin could be mitigated by producing the wells at a rate that allowed periodic sand bursts, yet without initiating massive sand influx. Also, deliberate sand clean-up activities during well testing could be used to generate skin-removing bursts. The sand bursts are triggered by stress and by the increased hydrodynamic drag associated with steep exit gradients arising from skin, and they have a remarkable clean-up effect on the near-wellbore, bringing flow skin into the range of consistently negative values. Wells that are amenable to this production methodology, called Sand Management, benefit from reduced completion costs, increased production rates, lowered intervention frequency, and the development and maintenance of a negative skin.

Sand Management, in contrast to sand exclusion, requires coping with higher risks because episodic sand influx events carry with them some danger to integrity of the well and surface facilities. Risk management implies three actions: high-quality evaluation and analysis before implementation, a commitment to monitoring during production, and a process of continuous re-evaluation of the well during its production life.

These risk management activities and protocols form the basis of the Sand Management approach.
Borehole Failure: Safe Drawdown Pressures and Wellbore Damage Radius
Authors: Morales R. H. , Webb T. R. , Hollier R.
Published: December 2007

This paper addresses the problem of onset of failure and the subsequent development and propagation of the failed (or plastic) zone during production. It uses an elasto/plastic formulation1 to find the distance of the damaged radius for cased and uncased wells. Numerical examples and laboratory tests are used to show the onset of failure and the growth of the plastic zone.
Multiphase Flow and Drilling Fluid Filtrate Effects on the Onset of Production
Authors: Ladva H. K. J. , Tardy Ph. , Howard P. R. , Dussan V. E. B.
Published: December 2007

Formation damage from the drilling process must be overcome to initiate production in wells that are neither cased nor perforated. The drawdown to initiate production can be limited by low reservoir pressure, sanding potential and water coning concerns. In these cases the required drawdown to initiate flow becomes important. Published results of laboratory experiments indicate that the flow initiation pressure (FIP) increases significantly when the permeability of the producing formation is below 50mD and that it is lower for oil based drilling fluids than water based fluids1. This study presents possible explanations.

The dependence of FIP on formation permeability and drilling fluid type was evaluated both experimentally (using small cores) and theoretically. The results suggest that the relatively large FIP in low permeability cores could be a consequence of conditions influencing multiphase fluid in the experiment, e.g., core length, or whether or not the experiments were run under constant flow or constant pressure-drop conditions. Under such circumstance, the onset of production in a well may not have the same dependence on formation permeability as does the laboratory measured FIP. In addition, at least some of the drilling fluid filtrate must be removed before any of the oil can be produced. When the filtrate is aqueous, capillary forces are present. The importance of these forces could explain why the FIP is higher for water- than oil-based drilling fluids. Both experimental and theoretical results are presented consistent with this explanation.
A New Drill-In Fluid Used for Successful Underbalanced Drilling
Authors: Luo Shiying , Meng Yingfeng , Tang Hongmin , Zhou Yongxin
Published: December 2007

Underbalanced drilling(UBD) operations are being utilized with increasing frequency as a means of reducing invasive formation damage, minimizing problems with differential sticking and lost circulation, and increasing rates of penetration in many drilling operations, etc. However, experience has indicated that during many operations, a wide range of factors may contribute to the loss of a continuous underbalance pressure, such as pipe connection in conventional jointed pipe drilling operations, mud pulsed MWD program, tripping operations, etc. So, it is difficult to maintain a condition of continuous underbalance pressure throughout the complete operation, resulting in fluid losses to the formation and possible significant damage.

In this paper, a new UBD drill-in fluid is present. The fluid was made by adding an elastic fiber-shaped additive, calcium carbonate particles into the past UBD drilling fluid (base mud). The sizes of the fibers and particles are determined by the distribution of the pore diameters and/or fracture widths of the target formation. When overbalanced situation is happening, the fibers and particles can bridge and form a thin plugging layer in the pores or fractures in the borehole wall in 0.5 to 2.0 min, which is not more than 1 cm. This plugging layer can stop further fluid invasion into the formation. If the underbalanced situation is resumed, almost all fibers and particles can be pushed back into well from the pores or fractures by the underbalance pressure. So, this new type of fluid can minimize the possible formation damage. Besides, the results in the laboratory showed its property is similar to its base mud. Finally, a case of its application verified this type of drill-in fluid is practicable.
Thermal Performance of an Insulated Multiple Flowline Bundle Using Active Heating
Authors: Chin Y. D. , Perera R. , Prescott C. N. , Brown R. J , Cain R. E.
Published: December 2007

Effectively engineered flowline bundles are attractive configurations for deepwater field development, because of their thermal performance and cost effectiveness. Bundled-insulated subsea flowlines provide economic alternatives for chemical injection to eliminate or reduce the risk of hydrate, wax or paraffin formation. The purpose of this study is to investigate the thermal interaction among the flowlines and its effects on the overall thermal performance of the bundle, and on the product arrival temperature. Multiphase flow and thermal analysis procedures were conducted for the Garden Banks 216 field pipeline bundle located in the Gulf of Mexico. The investigated bundle has three flowlines that carry multiphase product fluid and heating fluid.

The flowlines are enclosed with insulation and encased in a steel casing pipe. During normal operation, the product can flow in one or two flowlines while the third is for service. When active heating is applied, hot oil will be injected into one of the flowlines at the platform. The heating oil will be circulated through the flowline and the service line, and the third line will be for produced fluid. The pigging loop will be used as the turnover loop.

This study is to determine the steady state performances of each flowline in the bundle, including the multiphase product line and two-single phase heating lines. The temperature profiles are presented for different product flowrates. The effects of product flowrate, injection flowrate and injection temperature on the pipeline temperature profiles and product arrival temperature are discussed.
Data Reinterpretation by Multidisciplinary Team Increases Gas and Condensate Reserves in Eastern Venezuela
Authors: Vega G. , Cellamare V. , Riart F.
Published: December 2007

During many years the produced gas from Eastern Venezuela reservoirs has been one of the most important energy sources for the Venezuela internal domestic market. To support the new gas business vision, this region has in only three fields (San Joaquin / El Roble / Guario) potential gas reserve in the order of 13 MMMMSCF in 670 reservoirs. Surely, it will provide essential support and play an important role for investment to supply the necessary gas volumes for the market.

This paper, is a case study of the results obtained in the integrated study elaboration which was initiated in the RPN-24 reservoir, Merecure G sand, Roble field. The field is located geologically in the northwestern block of the Anaco thrust. Using available technologies, the revision of the data (seismic, geological and production behavior) detected the existence of a hydraulic unit with both areal and vertical comunication with other three Oligocene reservoirs.

The multidisciplinary integrated study of these mature gascondensate reservoirs revised, the existent structural model of the three cited fields, with good results. These results, through both static and dynamic model integration, identified the coalescence of four reservoirs into an unique hydraulic unit.

This integrated team process increased the GCOES to 232 MMMSCF with an average yield of 46 barrels of liquid per each MMSCF gas. Additionally, it will improve the operational process and the effective control of reservoirs by increasing the recoverable reserves.

The appropiate use of 2D seismic and the use of conventional reservoir analysis methods are always a great tool to work out studies in mature reservoirs through the application of team sinergy.
Well Test Pressure Derivatives and the Nature of Fracture Networks
Authors: Wei Lingli
Published: December 2007

The use of pressure derivatives in well test interpretation by reservoir engineers is commonplace since the publication on this subject by D. Bourdet et al.1 in 1989. This paper examines the relationships between well test pressure derivatives and the nature of the fracture networks within the testing region through numerous well test simulations in synthetic fracture networks.

The main parameters studied are fracture intensity and fracture size distributions. Other factors such as anisotropy, existence of faults, and matrix fracture permeability contrasts are also discussed. Numerical simulations demonstrated that where fractures are the major conduits in a reservoir, the derivatives of a pressure transient well test are a good indication of the nature of the underlying fracture networks.

For a realistic prediction of the behavior of a naturally fractured reservoir, the geologists are usually charged with characterising the fracture network based on information available from geology, geophysics, petrophysics and other measurements performed in drilled wells. This study has shown that well test and production data, normally under reservoir engineer's possession, may provide further clues about the nature of the fracture network within a reservoir, and help in extrapolating fracture data from individual wells to between wells, and ultimately within the whole reservoir.

A case study is also briefly described in this paper.
The Top 10 Mud-Related Concerns in Deepwater Drilling Operations
Authors: Zamora M. , Broussard P. N. , Stephens M. P.
Published: December 2007

The deepwater environment can place serious demands and constraints on the drilling fluid during well construction. Failure to adequately address these concerns can lead to excessive well costs, unscheduled trouble time, unnecessary high-risk activities, and poor performance. In this paper, we identify and succinctly discuss the top 10 mud-related concerns based on field experience in the Gulf of Mexico, off-shore West Africa, Southeast Asia, and Brazil.

Mud-related concerns selected for this top-10 list are (1) lost circulation, (2) mud properties, (3) solids transport, (4) stuck pipe, (5) wellbore stability, (6) shallow hazards, (7) gas hydrates, (8) reservoir productivity, (9) environmental issues, and (10) fluid-related logistics.