bluuebunny/crossref_metadata_2025 huggingface dataset:
Improved Experimental Characterisation of Cement/Rubber Zonal Isolation Materials
Authors: Bosma M. G. R. , Cornelissen E. K. , Schwing A.
Published: December 2007

Recently, various companies published sophisticated design methodologies to engineer the ‘cement’ sheath in a oil/gas well completion such that the zonal isolation would remain intact (i.e. pressure tight) during its projected lifetime. Loading within a prescribed design envelope (e.g. pressure and/or thermal cycling or mechanical compaction processes) are the main considerations.

Improved performance of a candidate zonal isolation material is achieved by adjusting its material properties, especially the Young's modulus and the compressibility.

These earlier studies indicated that apart from a proper mechanical characterisation of the ‘cement sheath’ (preferably described by non-linear material models), the in-situ stresses in the ‘cement’ play a prominent role as well. The latter are influenced by the volumetric behaviour of the slurry during setting and the thermal expansion coefficient of the set ‘cement’.

However, often these parameters are not known for ‘real life’ well construction materials.

Therefore, Shell International E & P B.V., the Netherlands, decided to design and construct dedicated laboratory equipment to determine those parameters for commercial ‘cement’ formulations at conditions encountered in typical well completions.

A first feature of this unique system (which can operate at pressures up to 1500 Bar and temperatures up to 300 ° C) is to monitor i) the progress of the ‘setting’ reaction of Oil Well Cements and or thermosetting resins, ii) their reaction behaviour (from the onset of gelling to the ‘final set’) and iii) the softening or swelling phenomena encountered in thermoplastic and thermoset materials.

The apparatus has inter alia the same functionality as conventional API Cement Consistometers or Ultrasonic Cement Analysers. However, it can also be used in combination with self-vulcanising rubbers, that cannot be used in the conventional API devices.

A second aspect of the apparatus is the determination of the volume changes (at constant pressure) or alternatively the pressure changes (at constant volume), during setting of the cement (or resin) system.

All measurements can be performed at either isothermal conditions or for prescribed temperature sweeps over time. Either volumetric properties (shrinkage or expansion) or compressibilities of cements / resin systems can be measured in a time frame ranging from the onset of gelling to far beyond ‘final set’.

In yet another operational mode, the volume change of set materials as a function of temperature (i.e. their volumetric thermal expansion coefficient) can be quantified.

In addition to a review of the principles of this novel apparatus, this paper also presents a typical application of the data in a Plug and Abandonment design (i.e. the Finite Element Engineering design of a thermally pre-stressed ‘rubber’ abandonment plug).
Laboratory Development of a Novel, Synthetic Oil-Based Reservoir Drilling and Gravel-Pack Fluid System That Allows Simultaneous Gravel-Packing and Cake-Cleanup in Open-Hole Completions
Authors: Price-Smith C. , Parlar M. , Kelkar S. , Brady M. , Hoxha B. , Tibbles R. J. , Foxenberg B.
Published: December 2007

In this paper, we present a novel approach for drilling and completing open hole horizontal wells with a fully compatible synthetic/oil-based fluid system utilizing shunt tube technology. The proposed RDF is a synthetic/oil-external emulsion that is reversible through exposure to a fluid of pH less than 7. A surfactant package included in the RDF water- wets the bridging/weighting agents (e.g., CaCO3) upon reversal of the emulsion. The synthetic/oil external emulsion developed for gravel packing typically contains 50-75% by volume aqueous phase as the internal phase and is completely solids-free. The internal phase can either be brine or a pH- reducer as well as a fit for purpose dissolver for the bridging agents. The pH-reducing property of the internal phase provides the required break mechanism for the S/OB-RDF emulsion remaining in the RDF filtercake under leakoff conditions allowing the bridging agents and drill solids to be water-wet, ensuring dissolution of the bridging agents.

Laboratory data are provided for filtercake removal kinetics as a function of temperature, overbalance during gravel packing, gravel mesh size, and drill solids concentration in the RDF. Rheological data are given. Retained permeabilities and flow initiation pressures measured with the combined core and gravel-pack system are presented. Implications of the laboratory results on field practice are discussed.
Gas Shut Off Using Foam: The Solution for Unwanted Gas Production?
Authors: Ligthelm D. J. , van Eijden G. J. M. , Gronsveld J.
Published: December 2007

Gas shut off technology for wells with a high gas/oil ratio is extremely valuable to improve oil production and reduce environmental pollution. Foam treatments have been applied to reduce unwanted gas inflow. However, results have not always been favorable. This paper presents a field case supported by a modeling study of successful foam shut-off treatments carried out in the South Chinese Sea. This study shows that the possibility of success of gas-shut-off treatments can be greatly enhanced by having a good understanding of the process parameters. In the Champion field, Brunei, an increasing number of oil wells are shut in due to high gas/oil ratio. In November 1998, three wells were treated with a surfactant/polymer (foam) solution in water, co-injected with nitrogen. In two wells the gas/oil ratio was substantially reduced but also a significant loss in oil productivity was observed, which partly restored in the course of time. The treatments were based on laboratory core flow experiments under reservoir conditions. The experiments served to design the field trials and as input data for simulations with a numerical radial well model, which was used to interpret the field trials. The reduction in gas mobility by a factor between 2 and 10 as observed in the field is consistent with the results of the laboratory experiments.

The study identifies the permeability and temperature window and the type of geological setting and well configuration for which the applied foam system will be successful. This is essential to screen potential candidate wells. It will be shown that in future treatments less damage to the oil productivity and lower costs are possible by omitting nitrogen gas and by reducing the injected volumes.
Wellbore Stability Evaluation for Horizontal Hole Completion - A Case Study
Authors: Finkbeiner T. , Moos D. , DeRose W. , Shiflett D.
Published: December 2007

Understanding borehole stability has become increasingly important in recent years to facilitate design of costly horizontal wells. This paper presents a case study, in which we evaluated the stability of a horizontal well in a major California oil field by first determining rock strength and tectonic stress and then drilling the well to verify the results of the predictions. Given the opportunity to drill numerous horizontal and possibly multilateral wells, it was important to fully evaluate the possibility of a successful open hole completion. An 800-foot horizontal well was planned to be drilled within a poorly consolidated and highly porous Pliocene reservoir that is slightly over pressured.

The analysis revealed that one horizontal principal stress is greater and one is lower than the overburden. Maximum horizontal compression is oriented N60°E. Borehole stability of the horizontal well is predominantly controlled by the extremely weak reservoir rock (uniaxial compressive strength is only 1,175 psi). An open hole completion was predicted to collapse without supporting slotted liner or casing. Even for a cased well, perforations placed at their most stable orientation were predicted to produce considerable amounts of sand. Only 200 feet of open horizontal hole was tested to validate the prediction. The open hole produced briefly and then collapsed. The horizontal well was subsequently completed in 800 feet of interval using a 60 mesh slotted liner and has produced 15,657 bbls of oil, 291 bbls of water, and 41,181 Mcf of gas through 12/31/99 with no sand problems.
Considering The Reservoir in Determining a Perforation Strategy
Authors: Underdown D. R. , Mariotti P. , Venkitaraman A.
Published: December 2007

The choice of how to perforate an interval is considered by many engineers as a straightforward exercise. Typically, an engineer takes API gun performance data from RP-43, uses some nodal analysis program and determines the "optimum" shots per foot, phasing and shaped charge that provides the maximum inflow performance for the completion. This information in combination with operational constraints is then used to design the perforation operation.

As more and more is understood about the perforation process, some operators are becoming aware of the value of approaching the perforation operation as a system instead of a simple engineering exercise. However, one aspect that has not received very much attention is the make-up of the reservoir in the near wellbore area, and how this affects the overall performance of the perforated interval after the perforation event.

This paper presents the results of a program to optimize the perforation strategy for a major gas field in the North Sea. An emphasis is placed on understanding the effect of the perforation operation on the deliverability of the reservoir near the perforation. The discussion in this paper includes petrographic analyses of the near perforation rock before and after the perforation event. In addition, CT (Computer Tomography) scans and core flow tests were done in order to understand observations from whole core tests. Production data from several wells is presented that documents the success of the system approach to developing the perforation strategy for the field.
Re-orientation and Merging of overlapping 3D Seismic Data
Authors: Murty J. V. S. S. N. , Shankar T. , Srinivas D.
Published: December 2007

This deals with a new technique for re-orienting different overlapping 3D seismic data sets from their acquired grid orientation into an integrated 3D volume in a desired orientation. The technique involves effectively predicting the seismic amplitudes using the local amplitude gradients on a time slice along the acquired grid axes. The re-construction of the seismic data in the desired grid orientation and bin size, from four 3D data sets in different grid azimuths and bin sizes, has improved the utility of the 3D data in Cauvery basin, Tamil Nadu, India.

The advantage of this technique is that it a) provides the data in the orientation that suits best for the given geological objective, b) provides uniform quality in spite of the non- uniform distribution of input bins with respect to the chosen output grid, c) it does not smear the dipping events and d) the interactive interpretation tools such as horizon/time slices, cube displays, computing sequence attributes etc. could be effectively used to visualize the entire area instead of seeing separately on the four data sets. The required software was developed and the merging of the four data sets was carried out on interpretation workstations.

The integrated volume helped in evolving a comprehensive depositional model for Kamalapuram Formation of Eocene/Paleocene age and in predicting areas of reservoir development.
An Overview of Re-Entry and Clamp-on Infill Drilling for Incremental Recovery in Offshore Field
Authors: Tewari R D , Mittal A K , Patra S K
Published: December 2007

Bombay high is a highly heterogeneous, multi-layered carbonate reservoir overlain by gascap and underlain by aquifer in Western continental shelf of India and is in mature stage of its producing life. The field is currently undergoing "Mid-life Crisis", necessitating major re-development and well interventions programs for stemming the decline in oil and gas production and maximization of recovery. Being an offshore field, sidetracking (LDST, MDST and SDST) of existing wells and drilling of infill wells through clamp-on have become sort of immediate preferred cost-effective option in Bombay High; firstly, for sustained oil production and commensurating the water injection and secondly for facilitating the additional recovery of bypassed, un-swept/less- depleted reserves. Failures/limited success of repetitive workover jobs, poor cementation, bad wellbore condition, early water breakthrough have made many wells susceptible to channeling behind casing and cross flow between the layers. Relocation of such wells and utilization of slot have become inevitable. Sidetracking is being practiced, as a measure for reducing the inventory of sick wells where all the conventional remedial measures have not met with desired results and have also limited the further scope of rectification.

This paper deals with the selection criteria, implementation and analysis of techno-economic successes and failures of re- entry/re-engineering of sub-optimal/uneconomical and clamp- on infill wells and also summarizes what has been learnt over the past several years and future scope of such activities.
Whaarangi; Prospect Potential Resolved
Authors: Engbers P. , Adams S. , Farmer R. , Mathers R. , Soek H.
Published: December 2007

This paper describes the rise and fall of a Miocene exploration prospect in the Maui PML offshore New Zealand. Strong positive indications of moveable hydrocarbons were finally proven by a RCI program not to relate to mobile hydrocarbons. Petrophysical evaluation indicated moderate quality sands with medium hydrocarbon saturations (around 50%) in the Moki B3 sand in the Maui B area. Positive oil indications were observed while drilling. The B3 sand showed a rather clear oil pressure gradient. Moreover, a 1.5 l sample containing oil (40° API) had been recovered in an earlier MDT program. In addition, the inferred contact from logs and pressures fitted a DHI on 3D seismic that also coincided with a structural 4-way dip closure. However, given the history of other Moki sands (low productivity) and the small potential oil column (transitional), commercial produceability was considered the main risk. With the development infra-structure already in place for the deeper Eocene reservoirs, and given the potential size of the accumulation, only relatively low oil rates from the Moki sands would be required for commercial development. Consequently a recent infill well targeting the deeper reservoirs provided the opportunity to sample and potentially test the Moki sands. With facilities lifetime reducing, a definitive result on Moki development potential was essential. Several RCI samples at a single reservoir point were recovered with increasing pump-out. The proportion of mud filtrate versus formation water was analysed by using a tracer added to the mud system. At the end of the pump-out, mainly formation water was recovered with only traces of oil. This conclusively demonstrated that the oil was immobile. Consequently, by low cost means, a definite result on the production potential was obtained, thereby avoiding expensive production testing.
Reservoir Characterization Through Well Test Analysis Assists in Reservoir Simulation - A Case Study
Authors: Neog P. K. , Borah N. M.
Published: December 2007

The Upper Assam basin is a major onshore sedimentary basin located in the Assam-Arakan geological province in the north-eastern part of India. This case history of a high permeability, stratified sandstone reservoir of the Lower Eocene formation in Upper Assam basin illustrates how integrated pressure transient analysis coupled with geological, geophysical, petrophysical and production information can be used for construction of dynamic fluid flow models to provide better reservoir description for reservoir simulation study. Chronostratigraphic and litho- stratigraphic layering of reservoir units for this field done earlier through seismic and log interpretation suggested isolated units. Such a model led to the computation of high primary recovery factors. Independent analysis of well tests was found to yield conflicting results, especially with respect to outer boundary configuration. The reservoirs comprising of fine to medium grained sandstones with interbedded shale/carbonaceous shale are located at around 3600 m depth, generally very thin (1-5 m) and exhibit rapid lateral variation making well-to-well log correlation un- reliable in many instances. Consistent modeling of flow barriers through analysis of all available well tests and integration of the same with other geo-scientific data led to a more reliable and consistent interpretation of field obser- vations and facilitated refinement of reservoir description. A 3D-3P reservoir simulation study carried out with this model facilitated in establishing the fact that several sand units/reservoirs in the field under study are in pressure communication with a common aquifer system. This infor- mation allowed more reliable estimates of in-place reserves and provided good data for fine-tuning the reservoir model to arrive at reasonable history match. The new model used in reservoir simulation is much more plausible and brings out the importance of using dynamic information for reser- voir characterization. Performance prediction of the field based on the new model aided in making realistic assess- ment of future production profiles and proper planning for field installation of formation water disposal and artificial lift facilities.
Achieving Low Cost Operation in Mature Oil Fields
Authors: Pasni Imelda , Wibowo Ignatius T.
Published: December 2007

The most challenging problem in mature oil fields is how to continue operating in a low cost fashion as crude production continuously decreases. To survive, companies need to realistically look at ways to rationalize their assets, which include rearranging operation modes or suspending some production facilities to achieve desirable asset value.

Offshore North West Java Production Sharing Contract (ONWJ PSC), is located in the Java Sea, Indonesia. It has been on production for almost 30 years and currently has about 150 production platforms, 700 production wells and more than 1,000 miles of sub-sea pipelines. Peak crude production was approximately 180,000 BOPD but currently it produces less than 70,000 BOPD. This paper describes efforts in the ONWJ PSC to reduce cost by using K-Flowstation, one out of thirteen flowstations in the contract area, as an example. This flowstation has been on production for more than 25 years and consists of three producing platforms, one process platform and one compression platform. A drastic cost reduction was achieved by restructuring the operation mode in Kilo Flowstation. This success depended on the good cooperation among Engineering, Production and Shared Technical Services Group in embracing a new operating philosophy for Kilo Flowstation. In early 1999 the team targeted a direct cost reduction of 75% by end of year 2000. In reality, 60% of the cost reduction target was realized in 1999.
Probabilistic Addition of Reserves - A New Approach
Authors: van Elk Jan F. , Vijayan K. , Gupta Ritu
Published: December 2007

For multi-field projects, the total project ultimate recovery (UR) at a given confidence level is traditionally derived by the arithmetic addition of the UR's of its constituent fields. However, this overstates the uncertainty range at the total project level. The total project UR, at a given confidence level, is more correctly derived by probabilistic addition (PA) of the field UR's. As Probabilistic Addition requires the definition of the dependencies between the added elements, it is important that UR dependencies between fields are correctly estimated and incorporated into the calculation of the total project UR.

This paper introduces a new statistically rigorous method for estimating UR dependencies between fields and for Probabilistic Addition of the field UR's to project level.

The UR dependencies between fields are estimated based on the field UR sensitivity to field parameters, as commonly summarised in the UR Tornado Diagram. This data is routinely generated when the Multiple Realisation Approach is used to derive reserves estimates in a field study.

The method of Probabilistic Addition is based on the assumption of Multivariate Normality. The method is very efficient in capturing field dependencies and eliminates the need for Monte Carlo simulation. Additionally, the method allows for a sensitivity analysis of the generated project UR, to the estimated field UR correlations.

In this paper, the application of the methodology to an actual project case is presented. The Probabilistic Addition of the North West Shelf gas-condensate fields producing into a shared onshore domestic gas and LNG plant is discussed. The North West Shelf project reserves at P90 confidence level, calculated using Probabilistic Addition, are significantly larger than the arithmetic sum of the P90 reserves of the constituent fields.
Novel Technique for Openhole Abandonment Saves Rig Time-A Case History
Authors: Chong King K. , Butterfield Charles A. , Conwell Russell P.
Published: December 2007

This paper presents a method for setting a competent cement plug over a long section of open hole in a deviated development well. The offshore operator saved 12 to 15 hours of rig time and used significantly less cementing material, such as surfactants and spacers for ester-base mud (EBM) removal. The modified procedure saved approximately $200,000 U.S. in rig time and materials.

The plugback job involved setting a competent cement plug over a 600-m interval of 8 ½-in. appraisal section drilled below 9 ⅝-in. production casing. The conventional procedure to plug back this hole section involves setting three or four long cement plugs on top of each other from total depth (TD) into the 9 ⅝ -in. shoe. If used in the case history situation, the conventional method would have exposed the EBM in the hole to a high risk of cement and spacer contamination. In this case history, a modified procedure was designed so that the full openhole section could be cemented with a single cement plug, minimizing the risk of mud contamination and helping ensure a positive top of cement (TOC) inside the 9 ⅝-in. casing shoe.

The new procedure involved running a long stinger of old, 3 ½-in. tubing on a modified bottomhole kickoff assembly (BHKA) tool, which allowed the stinger to be released from the drillpipe after the single cement plug was set. Because the tubing had been written off, it was used at no cost. The main benefits of this modified abandonment method included (1) minimal disturbance of cement (no need to pull the cement stinger through the plug), (2) minimal contamination of the EBM, and (3) reduced rig time and material cost compared to setting multiple plugs.

Techniques presented in this paper may be used in most instances that require placement of long, openhole cement plugs for hole abandonment.
Impact of Multi-Disciplinary Team Approach to Design Stimulation Treatment for Bombay Offshore Basin
Authors: Haldar Surajit , Nainwal S. P. , Bhatnagar S.B. L. , Bhatta M. K.
Published: December 2007

Many studies have been done on stimulation of carbonate reservoirs. Various techniques are also applied to stimulate the carbonate reservoirs of Bombay offshore basin. Though, use of conventional acidizing techniques are predominant in these fields, application of new stimulation techniques are also done but none have an effective impact on the productivity.

Well stimulation by and large involves knowledge and participation of many departments. This paper describes how the multidisciplinary team approach has made a significant change to overcome the challenges together with the resulting technology development.

Comprehensive studies were done to evaluate the formation in association with geophysicists, geologists, reservoir engineers, chemists and production engineers. Detail formation and core study confirmed that not only long fracture length but also the formation needs effectively etched longer fracture length to improve the conductivity. Multi-layered heterogeneous formation pattern also restricts the acid from deep penetration into less permeable area.

The proposed stimulation technique has two important components: acid placement technique and improved acid system. In this technique the formation is fracture acidized in multiple stages for longer fracture length. Followed by that a closed fracture acidizing enhances the permeability. An improved acid system maintains the acid concentration at different part of the fracture by varying the acid retardation resulting in effective etching and deep penetration. Field results verify this technique. This paper compares this stimulation technique with other stimulation treatments done in the Bombay offshore basin, where this new technique is applied. Lab results are included.

The focus of this paper is the process of candidate well selection for suitable stimulation treatments, to achieve more etched fracture length, and finally innovation and creation of value through team approach.
Mobility Control by Polymers Under Bottom-Water Conditions, Experimental Approach
Authors: Shirif Ezeddin
Published: December 2007

In many light or moderately viscous oil reservoirs in Saskatchewan and Alberta, a high water saturation zone ovarying thickness and extent ("bottom-water zone") occurs in communication with the oil zone above. As a result, the primary production period is short, and water coning occurs very early in the life of the reservoir. Later, during the secondary recovery stage, such a zone can have an adverse effect on the waterflood efficiency. This research addresses the problem of waterflooding such reservoirs.

This study was directed towards reducing water mobility in the bottom-water zone for more efficient oil displacement. Polymer in various concentrations was used as a blocking agent in the bottom-water zone and as a mobility control agent in the oil zone. Different strategies were investigated to reduce the water mobility in the bottom-water zone and improve the vertical sweep efficiency. The variables examined were: relative water-oil layer thickness, oil viscosity, polymer concentration, injection rate and injection point, as well as the effect of vertical and horizontal injection and production wells.

The results showed that oil recovery could be increased by minimizing crossflow between layers by blocking the bottom- water zone completely. It was also found that for an unfavourable mobility ratio, as the injection rate increases the ultimate oil recovery increases. The injection of a polymer solution had a favourable impact on waterflood performance. Moreover, the worse the conventional waterflood performance was, the more effective the polymer was as a mobility and blocking control agent. The use of horizontal wells showed slightly better oil recovery over vertical wells in a conventional waterflood of reservoirs under bottom-water conditions. In addition, some certain well combinations (horizontal production and vertical injection) gave better oil recovery due to the increase in the swept area.
Improved Oil Recovery of Edge and Bottom Water Reservoir by Drilling Horizontal Sidetracks
Authors: Hongyin Zheng , Peimao Zhang
Published: December 2007

This paper presents the important effects of slowing down the oil production decline, increasing the sweep efficiency and improving the oil recovery by drilling horizontal sidetracks for the Huizhou 21-1, Huizhou 26-1 and Weizhou 11-4 oilfields in the South China Sea. And also analyzes the production performance of the eight horizontal sidetracks and the development effects in detail.

According to the practical production experience, it is economically and technologically feasible to produce the remaining oil and to improve the oil recovery by the sidetrack drilling technology during the middle and later production periods for the mature oilfield. The oil production rate of these eight horizontal sidetracks for single well is more than 2-3 times that of the average oil production rate of conventional well in the same reservoir. It indicates that this method has great potential and wide applying prospect to improve the development effect for sandstone reservoirs with strong edge and bottom water drive, especially during the middle and high water-cut periods. And also it is recognized that the accurate reservoir characterization and the detailed study of remaining oil in place are the basement for geological design of the horizontal sidetracks and can ensure success of the drilling.
Remote Controlled (Tether-Less) High Pressure Isolation System
Authors: Tveit Edd , Aleksandersen Jostein
Published: December 2007

The PSI SmartPlug is designed to isolate high pressure inside pipelines and risers, thus permitting pipeline maintenance and repair without losing the contents and without the need to flare, depressurise or decommission the pipeline. Use of this tool to isolate pressure also allows dry laying and tie-in during construction of new pipelines.

The PSI SmartPlug comprises two Plug Modules, each of which is currently designed to withstand the full MAOP (Maximum Allowed Operating Pressure) differential pressure. Two bi-directional Pigging and Control Modules at each end of the SmartPlug ensure suitable pigging characteristics. The tool is designed to traverse minimum bend radii of 1.5D. The Control Module contains a hydraulic system with valves, battery pack, computer hardware and software, as well as an antenna that enables through-pipe wall communication.

An Extremely Low Frequency (ELF) Subsea Communication Link sitting on the seabed outside the pipeline ensures through-wall communication with the SmartPlug inside the pipeline. An acoustic link ensures command and information transfer between the topside computer and the SmartPlug. The topside operator sends instructions to set and unset the SmartPlug, in addition to monitoring various parameters such as pipeline pressure, annulus pressure and status of the tool. The system is based on reliable off the shelf standard components and designed to ensure redundancy as required.
The Prediction of Cloud Point Temperature: In Wax Deposition
Authors: Sadeghazad Ayoub , Christiansen Richard L. , Sobhi G. Ali , Edalat M.
Published: December 2007

The main object of this paper is to evaluate and discuss the cloud point temperature dependence on the solution nature in the crude (oil). Also, a correlation was developed for predicting the cloud point temperature in wax deposition.

The cloud point temperature is an important parameter to see weather there will be precipitation or not. So, we interested on the parameters that affect the cloud point temperature of hydrocarbons. Therefore, besides literature survey, some experiments on wax/paraffin deposition have been performed and evaluated.

Based on our experimental observations, the most important parameters that affect the hydrocarbon cloud point temperature are the apparent molecular weights of solution and solute, and solute weight fraction. These are the basic parameters of our developed correlation. Through the regression process different equation types have been used and a complex nonlinear poxlynomial type was selected to obtain a correlation which predicts the cloud point temperature with less than 1.0- percent error.

Our developed correlation is the only analytical solution for the prediction of cloud point temperature in wax precipitation. It also works for pure alkanes. This modeled correlation is ver simple to use and less time consuming. In addition, its results are very precise and more accurate than the previous models.
Oil and Gas Separation Theory, Application and Design
Authors: Katapodis Leon
Published: December 2007

Introduction

The physical separation of fluids is the most basic and necessary segregation in oil and gas processing. An oil and gas separator is one of the most fundamental pieces of production equipment used. Because of its production equipment used. Because of its front end position in on-stream processing, its performance is vital to the operation of a production facility. Oil and gas separators were one of the first pieces of production equipment introduced in the oil industry. But regardless of this longevity, the separator has not lost any of its original and vital importance in the separation of liquids and gases. This paper will discuss on a limited basis some, but not all, of separator design considerations.

DESIGN REQUIREMENTS

at the pressure and temperature within the vessel.

Assume proper control, by devices which will provide for the removal of this separated liquid phase from the vessel without allowing an opportunity for re-entrainment of one phase into the other.

All separators, whether vertical or horizontal, to achieve the functions listed above, consist primarily of four (4) basic sections.
The Development of Emulsion-Based Production Chemical Deployment Systems
Authors: Collins I. R. , Jordan M. M. , Feasey N. , Williams G. D.
Published: December 2007

In this paper we describe the development of a novel water-in-oil emulsion system for the deployment of aqueous-based production chemicals. The non-aqueous nature of the emulsion system potentially allows ingress of the chemical into parts of the reservoir normally denied access to an aqueous-based formulation and so can improve contact between the chemical and the reservoir fluids on production. Furthermore, the whole treatment can be deployed as a non-aqueous package allowing oil continuity to be maintained during the treatment. This can (i) prevent changes in the near well-bore relative permeability arising from the influence of the injected fluids; (ii) prevent water becoming trapped in oil-bearing zones reducing permeability to oil; and (iii) improve production chemical penetration depths (the water-wet nature of sandstone reservoirs means that the penetration depth of, for example, scale inhibitor solutions can be low). Moreover, for poor pressure support reservoirs, the reduced density of a non-aqueous treatment can obviate the need for artificial lift to restart the well. Originally developed for scale inhibitor deployment, this technology has been advanced by developing slowly degrading emulsion systems, which provide a means of trapping the aqueous production chemical within the porous media and allowing subsequent controlled release of the chemical. This advanced scale control technology has been proven in the laboratory for the encapsulation of corrosion inhibitors, biocides, hydrogen sulphide scavengers, and chemicals for the control of reservoir souring. Encapsulated scale inhibitors have been field deployed in two locations (in the UK sector of the North Sea and in the demanding environment of onshore Alaska under both high water cut and very low water cut conditions). This paper describes laboratory testing, including coretests, and describes the planning, the execution, and the results of the field treatments.
Use Of Water Base Spacer With Thixotropic Cement Solves Varied Cementing Problems
Authors: Griffin T.J. , Calvert D.G. , Parker D.L.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Thixotropic cements are cement slurries which are thin when mixed and pumped, gel rapidly when pumping stops, and become fluid if pumping is resumed within a short time. They have pumping is resumed within a short time. They have found wide application in the solution of many difficult cementing problems since they are self-supporting and have expansion properties. Until recently it had not been possible to control water loss of these systems due to their incompatibility with commonly used water loss control additives. A new approach to this problem has resulted in reduced water loss from the thixotropic cement slurry by means of a water base spacer being run ahead. The water loss of the water base spacer is designed to allow use of the thixotropic cement slurry in these conditions where water loss control is needed or desired.

This paper describes thixotropic cements, their uses, and techniques of application. Development of the water base spacer and its effect on thixotropic systems is also described. Comparative results show how improved well production can be achieved with use of the spacer and production can be achieved with use of the spacer and thixotropic cements.

Introduction

During the Past few years, a number of factors have been studied both in the laboratory and field application to improve the primary cement job. Some of the factors: pipe movement, position of pipe, use of a water loss controlled cement slurry, use of a spacer to separate mud and cement, and use of a cement slurry that exhibits expansive characteristics after setting. The use of a thixotropic cement has found use in most all areas because of its unique properties. properties. The application of all the aforementioned factors have not been possible because the commonly used water loss control additives destroy the thixotropic properties of the desired cement slurry. Research efforts to date have not allowed the development of an adequate water loss control additive, therefore the possibility of using a spacer with excellent water loss control ahead of cement slurry was studied. The filter cake laid down must not only be adequate to control water loss of cement slurry, it must have properties that are applicable to a well designed properties that are applicable to a well designed spacer system. Some of these are:Compatible with both the drilling fluid and the cement system.Low water loss.
Discussion on Integrating Monitoring Data into the Reservoir Management Process
Authors: Rossi D. J. , Gurpinar O. , Nelson R. , Jacobsen S.
Published: December 2007

Optimum management of oil and gas reservoirs is a continuous, iterative process which encompasses monitoring the reservoir, interpreting the monitoring data, and deciding from the results how best to continue reservoir development and executing those decisions. Monitoring data vary widely in time and space scales. Temporally, they range from continuous to infrequent, episodic measurements; spatially, they range from local well-centric to global reservoir measurements.

The reservoir management workflow similarly operates at multiple, parallel time-space scales. A "fast" workflow loop handles continuous well and surface network data (e.g. pressure, temperature, and rate), using fast data handling and fast decision-making to optimize hydrocarbon delivery. A "slow" workflow loop assimilates episodic reservoir data (e.g. time-lapse seismic and borehole reservoir measurements) to optimize reservoir drainage.

Reservoir monitoring data are assimilated at the most appropriate time into the reservoir shared earth model, which feeds both the "fast" and "slow" workflow loops. A continuing industry challenge is to determine the best way to do this, since the types of monitoring data are diverse and the volume of data to assimilate is often vast.

This paper begins with a review of reservoir monitoring data that are available today, with a focus on the range of time-space scales. A reservoir management workflow is introduced which has multiple time scales appropriate for these data. The paper concludes with a review of key challenges: (1) to develop improved interpretation technologies to unify and integrate the fast well-network centric and slow reservoir-centric workflow loops for faster conversion of measurement signals into information, and (2) to provide fuller support for uncertainties, including determining how the level of uncertainty in the reservoir model changes when assimilating monitoring data.
Integrated Downhole Monitoring of Hydraulically Fractured Production Wells
Authors: Bell Matt , Kraaijevanger Hans , Maisons Christophe
Published: December 2007

The first phase development of the Athel formation in South Oman relies on massive hydraulic fracture stimulation to realise economic production rates from micro-Darcy rock. It has been recognised that the size, shape and direction of the hydraulic fractures are key parameters in the prediction of well performance, optimum well placement and optimisation of fracture design.

In view of the highly laminated, intensely structurated geology, an early assessment of flow barriers and dynamic reservoir behaviour will also be crucial to managing long-term recovery of the significant Athel reserves.

In order to acquire substantial data addressing each of these issues, an integrated permanent downhole data acquisition system (PDDA) is being installed in the Phase I production wells. The system utilises a unique combination of tubing conveyed gauges and triaxial geophones to deliver real-time bottom hole pressure/temperature and microseismic data throughout both stimulation and production.

The first well equipped with the PDDA system was fracture stimulated in May 2000. This paper presents initial results, including interpretation of the microseismic data to determine fracture azimuth and dimensions.

The ongoing PDDA project, leading to integration of microseismic data recorded in offset wells and the acquisition of long-term flowing bottom hole pressure and build-up data is also discussed and comments made on the general oilfield applicability of such systems.
Material Balance Analysis of Faulted and Stratified, Tight Gas Reservoirs
Authors: Hagoort Jacques , Sinke Jaap , Dros Barry , Nieuwland Ferry
Published: December 2007

P/Z plots of tight gas reservoirs based on non-extrapolated pressures are generally curved and can deviate strongly from the theoretical straight line. Interpretation of these plots by the conventional straight-line method may significantly underestimate GIIP. The paper presents and explains the p/z behavior of tight gas reservoirs for a number of simple prototype reservoirs. It is shown that in many cases the curved p/z plots can still be interpreted quantitatively. The key to the interpretation is the concept of semi-steady-state time. Even if no quantitative interpretation is possible, a p/z plot is still a powerful diagnostic tool. When p/z plots can not be analyzed quantitatively, one has to resort to history matching of shut-in bottomhole pressures and of continuously measured wellhead pressures by using a numerical reservoir simulator.
The Reliability of Core Data as Input to Seismic Reservoir Monitoring Studies
Authors: Nes O. -M. , Holt R. M. , Fjær E.
Published: December 2007

There is a potential for improving the reliability of standard core tests for seismic monitoring studies. A primary concern is to quantify and correct for core damage effects, which significantly enhance the stress dependency of wave velocities. Careful laboratory procedures and modeling efforts may reduce such effects. However, no simple procedure is currently available to eliminate this problem. The use of simplified laboratory test procedures, in particular application of an inappropriate effective stress principle, may lead to erroneous interpretations.
Towards a Mono-Diameter Well – Advances in Expanding Tubing Technology
Authors: Benzie Scott , Burge Phil , Dobson Andrew
Published: December 2007

Solid steel tube can be readily expanded using forces, either mechanical or hydraulic available on most drilling and workover rigs. The process of drawing or pumping a mandrel through a length of tube can be used to expand the tube in situ. This process can be used to repair casing and tubing, shut off unwanted fluid entry into, and egress from the wellbore, repair sand screens, and act as a contingency liner in drilling applications. The ultimate use of expanded tubulars will be in the mono-diameter well, whereby the entire well is drilled and cased using effectively one hole size. The impact on drilling costs and performance will be dramatic.

Expandable tubing technology has been applied in the three market segments of remediation, wellbore construction and sand control. A broad range of products is currently available for implementation in all three segments. A review of the principles of expandable tubing technology leads to a discussion of the likely evolution of the technology towards the monodiameter well. The implementation of expandable tubing will follow a pattern of replacement of conventional technologies, use through necessity, maintenance of diametric efficiency which will lead to the use of the technology within the basis of design of well construction. From this is but a small step to the monodiameter well.

The principles of expandable tubing technology are well understood. The complexity arises from the system interactions between the materials, expansion process and the wellbore environment. These are explained and discussed.
Economics And Design Of Offshore Safety Systems
Authors: Stokley Charles O.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Introduction

Safety systems for offshore producing facilities are presently installed as required by government regulations. A less frequently considered aspect is that of safety systems as justifiable investments. A logical economic analysis may be performed to demonstrate that these systems are in fact valid economic decisions. The analysis compares with an accidental-death type of life insurance policy, whereas the system is a low-dollar investment for protection of a potentially larger expense in case of a catastrophe.

Several design considerations to enhance the economics through a reduction of maintenance costs and improved reliability are discussed also.

ECONOMICS

The following simplified formula provides a logical method for estimating the risk weighted cost of a catastrophe. This method could be related to a single piece of equipment as well as the entire facility, as will be shown in the two examples.

Using this general formula, two cases will be examined.

Case I

Area: Offshore California, 1,000-ft water depth, 20 producing wells to a total depth of 6,000 ft, at a total platform cost of $100 million.

Production: 20,000 BOPD at $8.00 per bbl and 20 MMcf/D at $1.00 per Mcf with a straight line decline for 20 years.

Problem: Major fire catastrophe, one well uncontrolled flow and fire.

C Estimate:

F = 0.006 three accidents per 500facilities each 5 years PV = $145,000 fifth-year rate of 16,000 PV = $145,000 fifth-year rate of 16,000 BOPD and 17 MMcf/DT = 40 days rig on location in 10 days;30 days to drill and control T = 210 days 60 days to secure; 150 days to repair and test PV = $15.2 M 40 days open flow one well PV = $15.2 M 40 days open flow one well plus 2 percent reserve losses