bluuebunny/crossref_metadata_2025 huggingface dataset:
Real-Time Production—A Virtual Dream or Reality? The Case of Remote Surveillance of ESP and Multiphase Flowmeters
Authors: Theuveny B. , Kosmala A. , Maizeret P. -D. , Sagar R. K.
Published: December 2007

A number of real time enablements of production engineering workflows shows various degrees of success and uptake upon implementation. It is possible to extract from the various types of challenges and difficulties a number of guidelines to ensure that the real-time production workflow implementations, deployments and utilizations have the largest chance of successes. A number of real time project have resulted in surprising initial drop of production figures rather than being immediate successes is part of the explanation of the 30% drop of the implementations within a first couple of years of commissioning.

With a larger number of implementations now available worldwide, green field operations are designed from day one with smart/digital capabilities. There is little discussion of the actual value of such massive data gathering capabilities, and its initial cost sunk into the overall project capital expenditure. The case implementation of smart/digital acquisition system in brown fields is much more challenging. The tight operational budgets associated with such operations require clear business and value case. The difference between opportunistic value and guaranteed value is a key element of the decision process and must be clearly identified. The paper offers a number of recommendations based on examples to establish the difference between the various approaches.

The issue of initial cost of implementation is a clear showstopper to many of these implementations. They must be managed well and it is quite important that the total cost of ownership be well defined and funded initially. New web based services such as the remote monitoring of ESP pumps or multiphase flowmeters allows for low initial investments to demonstrate the true value of real time production workflows.

The ability of experts to "see" and "act" on data put in the correct context is becoming more and more essential as equipment and measurements are becoming more and more sophisticated. Finally there starts to be a consensus on a new and essential job description of a breed of technicians and engineers who are willing and capable to attend to unscheduled notifications of events from remote production equipment in due time. These "surveillance" engineers are the basis of the success of the deployments of real time production and interpretation workflows.
Modeling Multiphase Flow in Naturally Fractured Vuggy Petroleum Reservoirs
Authors: Kang Z. , Wu Y. S. , Li J. , Wu Y. , Zhang J. , Wang G.
Published: December 2007

A multicontinuum conceptual model is presented and implemented into a three-dimensional, three-phase reservoir simulator, using a generalized multicontinuum modeling approach. The conceptual model, proposed for investigating multiphase flow and displacement through naturally fractured vuggy carbonate reservoirs, is based on observation and analysis of geological data, as well as on core examples from the carbonate Tahe Oil Field in China. In this conceptual model, naturally fractured vuggy rock is considered to be a triple-continuum medium, consisting of (1) highly permeable and well-connected large-scale fractures; (2) low or impermeable rock matrix; and (3) various-sized vugs or cavities. The base matrix system may contain many small or isolated cavities (of centimeters or millimeters in diameter), and large cavities (or vugs) ranging from centimeters to meters in diameter. Vugs may be (1) directly connected to large fractures, (2) indirectly connected to large fractures through small fractures or microfractures, or (3) isolated from large fractures by rock matrix. Similar to the conventional doubleporosity concept, the fracture continuum is responsible for the occurrence of global flow, whereas vuggy and matrix continua (mainly providing large-storage space of source/sink) are locally connected to each other as well as interacting with globally connected fractures. In the numerical implementation, a control-volume, integral finite-difference method is used for spatial discretization, and the resulting discrete nonlinear equations for the three-phase fluids, coupled with each continuum, are solved fully implicitly by Newton iteration. The numerical scheme, verified by comparing its results against those of available analytical solutions, is used to simulate water-oil flow through the fractured vuggy reservoirs of Tahe.
Formation Testing and Sampling Using an Oval Pad in Al Hamd Field, Egypt
Authors: El Zefzaf T. , El Fattah M. A. , Proett M. A. , Engelman B. , Bassiouny A.
Published: December 2007

Carbonate rocks, thinly bedded sands and naturally fractured reservoirs can exhibit a very challenging logging environment when pressure testing and fluid sampling are required. The challenge is due to, at least, reservoir heterogeneity, the nature of matrix and secondary pore systems, and the difficulty of sealing the probes on testing tools.

An Oval Pad was introduced to help overcome all of these challenges. The Oval Pad covers a vertical section of the well bore, giving it the sealing advantages of a straddle packer but still maintaining the operational flexibility of a probe. In particular, the Oval Pad design ensures an effective seal for the probe during formation testing and fluid sampling in the presence of vuggy and/or fractured carbonate rocks.

In addition to the increased vertical sealing area, the oval shape can reduce the sampling time due to a focusing effect the pad has on near-wellbore flow. A multiphase simulator is used to demonstrate this effect in homogeneous and layered zones. Simulations show that when the complete testing system performance is considered, the Oval Pad reduces pumping times compared to a standard probe.

Field examples from a Miocene Nullipore carbonate reservoir in the Al Hamd field in the Gulf of Suez are used to demonstrate the applications of the Oval Pad. The wireline micro-resistivity imager was also used to help characterize the zone and to facilitate test point identification. This field data is compared to numerical simulations to show the advantages of the Oval Pad design over both standard probes and straddle packer options. Examples included demonstrate the value of integrating both imaging and pressure sampling data into the overall petrophysical understanding of reservoir characteristics.
Modeling Dependence Among Geologic Risks in Sequential Exploration Decisions
Authors: Bickel J. E. , Smith J. E. , Meyer J. L.
Published: December 2007

Prospects in a common basin are likely to share geologic features. For example, if hydrocarbons are found at one location, they may be more likely to be found at other nearby locations. When making drilling decisions, we should be able to exploit this dependence and use drilling results from one location to make more informed decisions about other nearby prospects. Moreover, we should consider these informational synergies when evaluating multi-prospect exploration opportunities. In this paper, we present a practical approach for modeling the dependence among prospects and determining an optimal drilling strategy that takes this dependence into account. We demonstrate this approach using an example involving five prospects. This example illustrates the value of modeling dependence among prospects and the value of learning about individual geologic risk factors when choosing a drilling strategy.
Understanding Hydraulic Fracture Growth in Tight Oil Reservoirs by Integrating Microseismic Mapping and Fracture Modeling
Authors: Liu X. , Zhou Z. Q. , Li X. W. , Li Z. X. , Xu Y. G. , Chen B. C.
Published: December 2007

In this case study, fracture treatments in three tight-oil reservoirs in the giant Ordos basin of northern China were investigated using microseismic mapping and fracture modeling techniques to understand hydraulic fracture growth behavior and post-frac performance. Reservoirs of interests consist of stacked fluvial sand/shale deposits, and the target pay zones occur at depths between 1,820 and 2,186 meters. All wells in these tight reservoirs require fracture stimulation to improve productivity. This paper provides a brief summary of reservoir characteristics, but focuses on microseismic mapping results and fracture modeling analysis. This paper demonstrates that integrated studies can help engineers understand fracture behavior.
Enhancement of Gas Productivity Using Alcoholic Acids: Laboratory and Field Studies
Authors: Al-Anazi H. A. , Al-Otaibi M. , Al-Faifi M. G. , Hilab V. V.
Published: December 2007

The objectives of this study were to: investigate effectiveness of alcoholic acids to stimulate Devonian sandstone gas reservoirs, determine the optimum acid formulation, and recommend the best practices to enhance stimulation treatments in gas wells. In this study, extensive coreflood experiments were conducted on sandstone cores recovered from gas reservoirs to assess the effectiveness of various acid formulations (HCl, HCOOH, HCl/HF, and HCOOH/HF, with and without alcohols) in enhancing gas relative permeability. Several solvents and chemical additives were evaluated to remove or reduce trapped liquids. Experimental results showed commonly used completion fluids caused a severe reduction in gas relative permeability. This study indicated that alcohols can be mixed with stimulation fluid to expedite the cleanup of spent acid and help to attain maximum gas well potential directly after stimulation treatment.

Experimental results showed that alcoholic acids have a slower reaction rate with rocks compared to conventional acids having the same acidity. Alcoholic acids can be injected deeper into the formation and their corrosivity can be reduced in hot deep wells with a proper use of corrosion inhibitor type and concentration. Because of low IFT of alcoholic acids, they can be easily injected into tight formation when there are limitations in injection pressure and resulted in deeper stimulation than with conventional acids. This paper discusses a case study on damage diagnosis for a gas well which was recently completed and showed unexpected low productivity. This study proposed an effective stimulation formulation for gas wells and better practices for stimulation design to reduce flowback time needed to lift spent acid and help to achieve maximum production.
Preemptive Downtime Machinery Monitoring on Drilling Platforms
Authors: Wolter N. , Kaci V. , Pitard G. , Andersen P.
Published: December 2007

When Drilling Platforms experience unplanned down time resulting from rotating machinery failure, it is not only costly and time consuming, but impact safety, efficiency and ROI. This paper describes a new total assets value management strategy, based on predictive machinery failure monitoring, in combination with planned maintenance.

Applying condition monitoring concepts to rig rotating machinery, structure born noise and vibrations are monitored, evaluated and transformed into recognizable wear characteristics, enabling early warning of machinery fatigue, avoiding unscheduled down time and loss of production.

Time based signals and frequency spectra graphs will identify machinery condition and correlate the individual components (gears, shafts, bearings) frequency band. With a condition monitoring index, the individual machinery component "real time" condition is identified in relationship to predetermined performance values.

In the Rig Control Center, machinery frequency intensity is identified and monitored in relationship to trending and threshold values, raising alarms in accordance to the CMI index, identifying the need for time based preventive maintenance, avoiding unscheduled down time, increased maintenance expenditures while exploiting machine reserves, without consequential damages with the application of improved logistic maintenance scheduling.

This newly installed preemptive down time condition monitoring system, on top drives, mud pumps, generators and charging pumps, is expected to realize significant reduction in maintenance budgets, while reducing unscheduled down time substantialy on monitored rotating machinery, equal to current standards in power plants, refineries, mining and steel mills.

Total assets management is a significant potential, with real time machinery condition monitoring, in addition to machinery data acquisition points for temperature, pressure, op limits, emissions etc., incorporating time based rig fleet monitoring in a total data acquisition system of multiple rigs, controlled efficiently by experts in a smart room environment.

This paper concludes that all rotating machinery can be integrated into an assets management concept, including preemptive down time condition monitoring in combination with operating data acquisition and logistics, controlled through intranet at company head offices, enhancing operations management and reporting standards, improving over all HSE and ROI.
Special Cement System and Cementing Techniques Improve Zonal Isolation in South Oman Fields
Authors: Laws M. , Riyami A. , Soek H. , Edwards J. , Elmarsafawi Y. , Abdenour S. , Valstar D. , Misran M. , Hassan A.
Published: December 2007

A cluster of fields in the South of Oman consists of heterogeneous platform carbonates at ~4500m depth embedded in salt. These salt-sealed reservoirs have no aquifer support so ultimate recovery will be maximized by injecting miscible gas. During drilling operations, the drilling fluid density has to be high enough to balance the high-pressure carbonate stringers whose pore pressure can be almost lithostatic.

When circulating to a lighter completion brine however a huge drawdown is applied to the wellbore causing a micro-annulus to form between the liner and cement sheath. It is important to close this gap to avoid the miscible gas flowing behind the casing and hence impairing reservoir management. This gas is expected to break through in the higher permeability zones and gas shutoff remedies will be impossible if the casing to formation annulus is not sealed. The increase in ultimate recovery from miscible gas injection will be significantly reduced if gas shutoff in the higher permeability layers is impossible.

A special cement was trialed which expands over time to close this micro-annulus. Other cementation challenges include the narrow margin between formation pore and fracture pressures, the wide range of formation permeability, the extremely sour nature of the reservoir fluids and the salt-saturated heavy mud. Multiple cement logging runs were made to evaluate this cement at various times and with various fluid densities in the borehole. The first three logs were made within twenty-one days of pumping the cement; all before the slow cement expansion occurred. The well bore fluid during the first log was mud with a slightly lower density than that used to displace the cement. The log was repeated with a surface pressure applied, and repeated again with a much lighter completion brine giving a 61000 kPa differential to the liner. The micro annulus expected from this pressure change is over 180 micron. This third log showed all the bond apparent in the second log had disappeared. The fourth cement evaluation during a workover was made twenty-one months later, again in the much lighter brine. This final log showed the cement had expanded and the bond was restored.
Improving Structural and Stratigraphic Analysis Using Subsurface Residual Anomaly Maps: Case Study From Arabian Platform
Authors: Al-Qahtani AbdulMotaleb , Al-Muzaiyen Emad
Published: December 2007

In Arabian Platform, tracing the sequential development of geological structures is often a challenging task due to the activity of multiple tectonic events throughout its geologic history. Originalstructures have not yet been reconfigured during the Paleozoic and Mesozoic, leaving long and complex growth histories. To unravel the development of these structures, analysis of isopach maps at specific structural events must be considered.

The following study was undertaken in an effort to reconstruct the development history of the Arabian Peninsula. Several different residual growth analyses were performed to answer questions regarding the timing of the growth of the structure, and the mechanisms responsible for the location and shape of the structure. General interpretations of several seismic lines provided information about the location and trend of a basement level fault that exists directly underneath Arabian Platform sedimentary section. Detailed interpretation of residual growth maps reveals regional NW-SE and N-S major faults, characteristic of compression and strike-slip geometry associated with Hercynian Orogeny. In addition to gravity and magnetic data, structure and isopach maps constructed from several hundred wells and thousands of 2D seismic data throughout Arabian platform help to constrain the aerial extent of basement structure and sedimentary facies distributions overlying basement structures.

Residual growth maps were computed to identify growth related thinning and subsidence thickening which will be correlated with features seen in the seismic data. Results of the above analyses demonstrate that the Arabian Platform has a long growth history, beginning as early as Pre-Cambrian time, and continuing through the Middle to Early Tertiary
Innovative Well-Testing System for High-Rate Sour-Gas Khuff Well in the North Field, Qatar
Authors: Al Hajri M. , Macdonald B. , Marcellin P. , Segui E.
Published: December 2007

This paper presents the innovative system designed by Dolphin Energy to production test the Khuff intervals of the North Field data well NFD1-1. The design comprised the use of a single run of a 4 ½" tubing test string with a Down Hole Safety Valve (DHSV), production packer, acoustic surface read out gauges, and 10K Xmas-tree to achieve the test objectives.

The through tubing zonal isolation technique allowed the sequential testing of the Khuff reservoir intervals without the use of a kill fluid and removal of the test string between tests. Thus reservoir damage was minimized, and recovery of initial productivity more likely for future development.

The test string design enabled the optimization of the flow and shut in periods to ensure full and quality data gathering. The flexibility of the design also allowed additional intervals to be perforated and tested.

All components operated continuously during the seven separate tests of the four Khuff zones over a period of 64 days.
NMR Petrophysics in Thin Sand-Shale Laminations
Authors: Minh Chanh Cao , Sundararaman Padmanadhan
Published: December 2007

We use nuclear magnetic resonance (NMR) logging to help with the petrophysical evaluation of thin sand-shale laminations. NMR helps to 1) detect thin beds, 2) determine fluid type, and if hydrocarbon is present, 3) establish the hydrocarbon type and volume, and finally 4) determine the permeability of the sands (as opposed to that of the sand-shale system).

Formation evaluation in thin sand-shale laminations starts with their detection. NMR vertical resolution is mainly controlled by the antenna aperture, that is, in the case of a high-resolution antenna, 6 in. or 15 cm. Within that distance NMR tools will cumulatively measure all layers of shales and all layers of sands regardless of their individual thicknesses. Because NMR relaxation time in shales is much faster than in the productive sands, thin sand-shale laminations appear on NMR logs with the characteristic bimodal relaxation distribution.

The thin laminations are often below the resolution of conventional logs that have a typical vertical resolution of 6 to 12 in. or 15 to 30 cm. This makes fluid typing in the centimeter-thick sands problematic from conventional logs. Also, formation pressure or sampling tools could hit-and-miss the thin sands. In contrast, since gas, oil, and water have different properties, fluid typing techniques that exploit all NMR relaxation times (T1 and T2) and diffusion (D) offer new ways to determine the fluid type in thin layer sands.

From the bimodal relaxation distribution of the laminated sand-shale system, it is often possible to determine a cutoff to separate the two components. Porosity in the sand component can then be estimated separately and with it the hydrocarbon pore volume.

Conventional high-resolution permeability from NMR is limited to one antenna aperture. If the sand layer thickness is less than that distance, the determined permeability of the sand-shale system will underestimate the true permeability of the sands. Using a fluid flow model, we show that the permeability of the sand component can be estimated separately.

Experiments were conducted to verify the characteristic NMR bimodal relaxation distribution in thin beds, and to investigate whether the fraction of sand/shale and the sand porosity could be determined from NMR logs. The results confirmed observations on logs, of which we show case examples of thin sand-shale laminations that are water-bearing, oil-bearing, and gas-bearing respectively. In each case the NMR detection was verified against imaging logs, and the fluid type in the sands was determined from multi-dimensional NMR analysis. The derived hydrocarbon volume was then compared with the results estimated from a full triaxial (3D) induction tool. Permeability of the sand layers was also computed and compared to that of nearby thick sands. Core data in one well was used to validate NMR detection, porosity, permeability and net sand thickness.
PI-Mode Production Over Bottomwater
Authors: Wang Y. , Laine E. , Ehlig-Economides C. A.
Published: December 2007

Over bottom water, a horizontal well will usually perform better than a vertical well because the oil-water contact rises in the shape of a crest instead of a cone. Analytical models have predicted greater critical rates for horizontal wells and greater recovery at water breakthrough when the horizontal well is produced at higher than the critical rate. However, as with vertical wells, horizontal wells may water out before getting an economically sufficient recovery factor. The objective of this paper is to evaluate the strategy of waterflooding over bottom water using the π-mode production strategy.

The objective of π-mode production is to accelerate recovery and achieve 50% recovery efficiency in less than 5 years through waterflooding. This is accomplished by production at a constant oil rate and full voidage replacement through reinjection of produced water. As in previous work, this paper employs the horizontal well couplet with one injector and one producer. Simulations reported in previous studies have demonstrated the feasibility of this waterflood strategy, first for homogeneous and then for heterogeneous reservoirs. This paper determines when the π-mode production strategy is effective over bottom water. In addition, the π-mode production strategy is compared to an array of horizontal well production wells without injection.

Simulations performed for a variety of well spacing, different reservoir thicknesses, different mobility ratios, and different aquifer sizes are compared for recovery and net present value versus time for both the π-mode production strategy and production well strategies. Results quantify optimal well spacing and show that the π-mode production strategy is effective over small aquifers while production wells without injection work better for large aquifers.
Subsurface Integrated Production Systems
Authors: Rivas Olegario
Published: December 2007

When considering the potential for developing marginal fields, the high cost associated with conventional production facilities becomes a major consideration for financial viability.

Conventional oil and gas production facilities are very costly and time consuming to fabricate. Since oil production cannot begin without permanent production facilities in place, production revenue is often delayed while waiting for these facilities to be completed.

Basically, conventional oil and gas production facilities involve a production/test manifold, gas/oil separation system, storage tank, pumping system, and auxiliary systems (e.g., chemical injection, dehydration system, etc.).

This paper presents an alternative to conventional oil and gas production facilities. The alternative integrates these functions into one system. Based on fluid capacity requirements, the subsurface integrated production system (SIPS) concept can be configured for single (SIPS-S) or multiple (SIPS-M) installations. The dimensions of SIPS applications take into account sufficient volume for the storage of produced fluids and offer extended residence time for natural separation of wellbore fluids.

According to the required separation capacity, the wellbore fluids may be separated in the SIPS units by gravity or separation may be enhanced by the use of mechanical separating devices.

This concept includes the use of at least one electrical submersible pump (ESP) for moving the stored liquid from the collection well to a remote location, completing a basic SIPS. The separated gas is conveyed from the SIPS to the required end user.
Induced Fracturing in Reservoir Simulations: Application of a New Coupled Simulator to Waterflooding Field Examples
Authors: Hustedt B. , Zwarts D. , Bjoerndal H.-P. , Masfry R. , van den Hoek P. J.
Published: December 2007

Water-injection induced fractures are key factors influencing successful waterflooding projects. Controlling dynamic fracture growth can lead to largely improved water management strategies and potentially to increased oil recovery and reduced operational costs (well count and water treatment facilities reduction), thereby enhancing the project economics.

The primary tool that reservoir engineers require to guarantee an optimal waterflood field implementation is an appropriate modeling tool that is capable of handling the dynamic fracturing process in complex reservoir grids.

We have developed a new modeling strategy that combines fluid-flow and fracture-growth in one reservoir simulation. Dynamic fractures are free to propagate in length- and height-direction with respect to poro- and thermo-elastic stresses acting on the fracture. A prototype simulator for contained fractures was successfully tested.

We have extended the coupled simulator to incorporate non-contained fractures. The new simulator handles fracture length and height growth by evaluating a fracture propagation criterion that is based on a Barenblatt condition. The solution of the five-dimensional problem is computed using a tuned Broyden approach.

We demonstrate the capabilities of the coupled simulator by showing its application to a complex reservoir simulation model. The fracture modeling is used to history match an injectivity test in a five-spot injection pattern using produced water. The coupled simulation results and the field data interpretation show a very good match. The outcome of the injection test led to an appropriate waterflood management strategy adapted to the specific reservoir conditions and, in terms of production, in a net oil production increase of 50-100%. The field example shows how the coupled simulator technology can be used to achieve optimized waterflood management strategies and increased oil recovery.
A Multistage Sampling Method for Rapid Quantification of Uncertainty in History Matching Geological Models
Authors: Ma X. , Al-Harbi M. , Datta-Gupta A. , Efendiev Y.
Published: December 2007

The paper presents a novel method for rapid quantification of uncertainty in history matching reservoir models using a two-stage Markov Chain Monte Carlo (MCMC) method. Our approach is based on a combination of fast linearized approximation to the dynamic data and the MCMC algorithm. In the first stage, we use streamline-derived sensitivities to obtain an analytical approximation in a small neighborhood of the previously computed dynamic data. The sensitivities can be conveniently obtained using either a finite-difference or streamline simulator. The approximation of the dynamic data is then used to modify the instrumental proposal distribution during MCMC. In the second stage, those proposals that pass the first stage are assessed by running full flow simulations to assure rigorousness in sampling. The uncertainty analysis is carried out by analyzing multiple models sampled from the posterior distribution in the Bayesian formulation for history matching. We demonstrate that the two-stage approach increases the acceptance rate, and significantly reduces the computational cost compared to conventional MCMC sampling without sacrificing accuracy. Finally, both two-dimensional synthetic and three-dimensional field examples demonstrate the power and utility of the two-stage MCMC method for history matching and uncertainty analysis.
Optimal Waterflood Management Using Rate Control
Authors: Alhuthali A. H. , Oyerinde D. , Datta-Gupta A.
Published: December 2007

Field scale rate optimization problems often involve highly complex reservoir models, production and facilities related constraints and a large number of unknowns. All these make optimal reservoir management via rate and flood front control difficult without efficient optimization tools. Some aspects of the optimization problem have been studied before using mainly optimal control theory. However, the applications to-date have been limited to rather small problems because of the computation time and the complexities associated with the formulation and solution of adjoint equations. Field-scale rate optimization for maximizing waterflood sweep efficiency under realistic field conditions has still remained largely unexplored.

We propose a practical and efficient approach for computing optimal injection and production rates and thereby manage the waterflood front to maximize sweep efficiency and delay the arrival time to minimize water cycling. Our work relies on equalizing the arrival times of the waterfront at all producers within selected sub-regions of a water flood project. The arrival time optimization has favorable quasi-linear properties and the optimization proceeds smoothly even if our initial conditions are far from the solution. Furthermore, the sensitivity of the arrival time with respect to injection and production rates can be calculated analytically using a single flow simulation. This makes our approach computationally efficient and suitable for large-scale field applications. The arrival time optimization ensures appropriate rate allocation and flood front management by delaying the water breakthrough at the producing wells.

Multiple examples are presented to support the robustness and efficiency of the proposed optimization scheme. These include several 2D synthetic examples for validation purposes and a 3D field application. In addition, we demonstrate the potential of the approach to optimize the flow profile along injection/production segments of horizontal-smart wells
Using Microseismic Monitoring and Advanced Stimulation Technology to Understand Fracture Geometry and Eliminate Screenout Problems in the Bossier Sand of East Texas
Authors: Baihly J. , Laursen P. , Ogrin J. , Le Calvez J. H. , Villarreal R. , Tanner K. , Bennett L.
Published: December 2007

A major factor to determine the effectiveness of any tight gas stimulation program is to understand the hydraulic fracture geometry. Technology has progressed to the point that microseismic monitoring of hydraulic fracture treatments can provide key information to characterize fracture development.

At the onset of this stimulation project, in-depth knowledge of reservoir, completion, production, geophysical, and geological engineering were integrated to determine the solution. The integration of these domains of expertise led to project success.

The results presented within are from a series of hydraulic fracture stimulations in the Bossier Sand formation where field-wide screen-out problems were historically observed. This paper documents the integrated process utilized to solve the screenout problem as well as to establish a way forward to achieve optimized completions in the target sand.

Within the course of this project, microseismic monitoring coupled with sound fracture engineering technology led to several observations. a) The original design was not contained in the target sand. b) Microseismic monitoring and computer model simulation using calibrated stresses confirmed undesired fracture development uphole. c) Microseismic monitoring confirmed formation micro-imager log based fracture azimuth determination.

This integrated study led to improved completion designs which resulted in hydraulic fractures contained within the target sand and a plan for an infill drilling pattern to optimize field drainage.
Water Injection Optimization Using Historical Production and Seismic Data
Authors: Huang Xuri , Ling Yun
Published: December 2007

This work proposes a method to optimize waterflooding by using production and time-lapse seismic data. Using time-lapse seismic difference as an indication of inter-well influence, inter-well connectivities or influence functions are determined using a combinatorial algorithm (stochastic hillclimbing) by constraining the computation with time-lapse seismic. The water-cut is estimated using a fitting function. By perturbing the injection rate in the injectors, the oil production is optimized. The field in this study is mature with 15 years of production history and with 70% water-cut at the present time. Two legacy repeated seismic surveys, of in 1991 and 2001 vintages respectively, are reprocessed to enhance the repeatability from the original data. The reprocessing is done to eliminate the survey, source and noise differences. The connectivity or influence function is estimated using a window of balanced flooding. It is found that seismic constraining for the connectivity calculation increases the consistency of the inter-well relationship with the spatial data. In order to have an operational waterflooding scheme, a multiple realization approach is used. That is, the optimized injection is randomly perturbed under specified upper and lower bounds. The production rate is computed using the inter-well influence function. It is found that the optimal injection configuration can increase oil production. With a pilot implementation, it is shown that the new injection scheme can delay the oil production decline.

Introduction

Optimization of water-flooding is a critical process for reservoir management. Generally, the optimization can be conducted through an adjustment of the injection pattern or injection scheduling by reservoir simulation or by intuitive analysis. However, to perform this process, the injector-producer relationship or inter-well relation needs to be understood. To understand this relationship, the production history data are normally used either through a correlation or material balance-type analysis. For example Soeriawinata et al. used a correlation approach to build the injector-producer relationship.1 Jansen used a wavelet transform to analyze the inter-well relationship using producer-injector data.2 Albertoni et. al. proposed an approach of linear regression using injector-producer production history data.3,4 For quantitative analysis, reservoir simulation can be used with even seismic data in the process of history matching.5 However, reservoir simulation is quite time-consuming. On the other hand, using the production history sometimes has difficulties to fully account for the spatial heterogeneity. It would be critical to incorporate the production history data and other data such as seismic to analyze the producer-injector relationship. In this work, we propose using the time-lapse seismic attributes to constrain the estimation of the injector-producer relationship.
Scale Inhibitor Squeeze Treatments Deployed From an FPSO in Deepwater Subsea Fields in the Campos Basin
Authors: Bogaert P. , Berredo M. C. , Toschi C. , Jordan M. M. , Frigo D. M. , Morgenthaler L. , Afonso M.
Published: December 2007

This paper describes field experience and lessons learned from scale-control operations in a deepwater subsea development in the Campos Basin, Brazil; specifically, from bullheading scale-inhibitor squeezes from the FPSO host, along the production flowlines, into four low-watercut, horizontal subsea wells, completed with sand control.

The relatively small number of high-cost, highly productive wells, coupled with a very high barium-sulfate scaling tendency upon breakthrough of injection water, meant not only was effective scale management critical to achieve high hydrocarbon recovery, but even wells at low water cuts were deemed to be at sufficient risk to require squeeze application.

Use of conventional, water-based squeezes have been known to cause significant damage to productivity in low-watercut wells, including those showing a fines-migration tendency, as was the case here. Hence, based upon risk mitigation, supported by an extensive programme of laboratory testing, it was decided that for the initial treatments only the mainflush would be water-based, with a mutual-solvent preflush and marine-diesel overflush.

Other key challenges associated with treating from the host included the remote location of the wells, the potential to form hydrates, the cleanliness of the lines along which the treatment would pass, the achievement of effective placement over a long producing interval, as well as the need to deploy the chemical package via a support vessel adjacent to the FPSO. All had to be managed due to the high cost and low availability of a deepwater rig that could deploy the treatments directly to the subsea wellheads.

The paper will explore in detail the issues associated with inhibitor-squeeze deployment in deepwater, subsea fields, many of which are currently being developed in the Campos basin, Gulf of Mexico and West Africa, and is a good example of best-practice sharing from another oil basin.
Structuring Surface Production Networks To Reduce Development Cost
Authors: Xiao J. J. , Al-Muraikhi A. J. , Shammasi M.
Published: December 2007

In the development of a new field, after the surface well locations are determined, the next question that needs to be addressed then is how to structure the surface production network in a cost effective manner. In an offshore field development, a similar question is how to link productions from several satellite platforms and bring production onshore.

In this paper, we present a production network layout tool which allows the determination of 1) a centrally located manifold or separation facility site, and 2) an optimal network structure that minimizes material (pipeline length) usage. The manifold or processing facility location is chosen to minimize load-distance from all the wells. This ensures less pressure loss and shorter pipe usage. The production network is structured to reduce total pipeline length and at the same time meet wellhead flowing pressure requirements and flowline erosional velocity constraints. An example case is used to illustrate the value of the tool.
Risk Management/Functional Safety: A Practical Approach for End Users and System Integrators
Authors: Capelle Valentino Vande , Houtermans Michel
Published: December 2007

The objective of this paper is to demonstrate through a practical example how an end-user should deal with functional safety while designing a safety instrumented function and implementing it in a safety instrumented system. The paper starts with explaining the problems that exist inherently in safety systems. After understanding the problems the paper takes the reader from the verbal description of a safety function through the design of the architecture, the process for the selection of safety components, and the role of reliability analysis. After reading this paper the end-users understands the practical process for implementing the design of safety instrumented systems without going into detail of the requirements of the standard.
Drillable Tailpipe Disconnect: Used Successfully in More Than 120 Wells Worldwide
Authors: Rogers H. , Thornton P. , Fairchild M. , Austin D.
Published: December 2007

There are a number of challenges associated with setting cement plugs in an openhole well. Most importantly, drillpipe can become differentially stuck across a lost-circulation zone, and the plug may become contaminated with the intermixing of the mud resulting in inadequate isolation or insufficient strength.

Cement plugs are used for various reasons including healing losses, abandonment, and directional drilling. It is essential to these operations that a competent cement plug is placed the first time. The value of placing the designed cement plug properly is measured by nonproductive rig time, wasted material, and additional cementing services.

An innovative tool and a special process1 were designed to meet the challenges associated with setting cement plugs. The tool connects sacrificial/drillable tubing to the drillpipe and allows an operator to trip into the well and spot the cement plug across the problematic zone. Once cement is placed, the tool is disengaged and the operator trips the drillpipe out of the hole, leaving the cement plug and tubing undisturbed. The sacrificial tubing can be drillable; therefore, the operator can drill through the plug or commence other operations as required.

This paper discusses the challenges operators face when setting cement plugs and how the risk and nonproductive time are reduced with this innovative plug-setting process and tool. Well examples are documented from case histories to illustrate the success and lessons learned.
A Three-Phase Compressible Dual-Porosity Model for Streamline Simulation
Authors: Kozlova A. , Bratvedt F. , Bratvedt K. , Myasnikov A.
Published: December 2007

Streamline methods as a reservoir simulation tool have generated a great deal of interest in petroleum engineering because of the capability to calculate fluid flow in multi-million cell geological models with reasonable CPU times. Recently, streamline simulation has been applied to fractured reservoirs at the geo-scale. However, these simulations have been limited to two-phase incompressible systems. Commercial application of streamline methods to fractured reservoirs often requires the modeling of at least three compressible fluid phases.

Flow simulation of fractured reservoirs is commonly performed using a dual porosity model. The dual porosity system is modeled by using two coupled grids: one for matrix and one for fracture. The interaction between the two continua is modeled using matrix-fracture transfer functions. Until now, there were no mathematical models of dual porosity three-phase compressible flow for streamline simulators. To realize this model it was necessary to reformulate the matrix and fracture pressure equations. Conventional transfer function has been incorporated as a source/sink term, not only in the streamline saturation equations (as it was in incompressible case), but also in the pressure equation.

The dual porosity model has been implemented into a streamline simulator. This tool has its main application in the high resolution reservoir modeling domain for analyzing geological uncertainty, model ranking and screening, and dynamic model calibration using production data.

This paper describes the mathematical model for three-phase compressible dual porosity model for a streamline simulator and compares the results and run times of the streamline-based approach with a conventional dual porosity grid-based commercial simulator. The results from the streamline simulator for dual porosity show good agreement with those produced by a commercial finite difference simulator with order of magnitude improvement in simulation time.
The Effect of Wettability on Oil Recovery of Alkaline/Surfactant/Polymer Flooding
Authors: Dong Han , Hong Yuan , Rui Weng , Fan Dong
Published: December 2007

The present paper summarizes the laboratory studies of the effect of wettability on oil recovery of Alkaline/Surfactant/Polymer flooding. The wettability of water-wet Berea sandstone was altered into neutral-wet and oil-wet conditions by using organic reactants. The wettability index of each core sample was determined using a modified Amott imbibition method. The displacement efficiency of Alkaline/Surfactant/Polymer flooding and Polymer flooding at the different wetting conditions was evaluated by laboratory coreflood experiments. The experiment results indicate that the displacement efficiency of water flooding and ASP flooding is markedly affected by the wettability of the core. The wettability is one of the important factors to determine the oil recovery of water and ASP flooding. Water-wet and oil-wet conditions are favorable to obtain high enhanced oil recovery for ASP flooding. Contrast to ASP flooding, the influence of wetttability on oil recovery of polymer flooding was found to be minor for the three different wetting conditions. These results provide a guide to applying the ASP flooding and polymer flooding to the reservoirs with different wettability.
Case Study of New Slender Well Construction Technology
Authors: Howlett P. D. , Wardley M. T. , Black C. , Reed D.
Published: December 2007

This paper will describe the development, prototype testing, full well system test and field trial of an evolutionary slender well construction system. The system is a method of constructing oil and gas wells from close-clearance flush-jointed cemented liners from top to bottom to form the entire well.

Significant technical hurdles were overcome in the development of a system that is safe and practical to deploy whilst at the same time allowing drilling and completions engineers to plan the wells using accepted oil and gas well engineering methods. The paper will describe the technical hurdles to overcome to enable this method of well construction to become accepted.

This evolutionary method of constructing oil and gas wells has the potential to compete favorably with conventional techniques and other new technology methods already being deployed and could be used in a wide variety of well types.

In its full well construction format of four or more close-clearance liners, the cost of constructing the well can be reduced significantly, perhaps by more than 50%, whilst at the same time enhancing safety and reducing environmental impact. In its partial format of one to three close-clearance liners during a sidetrack or well extension, the available flow area across the zone of interest can be increased by 100% as a result of an increased tubular size deployed at total depth compared with convention. Figure 1 shows a comparison of the system to conventional techniques for full wells and Figure 2 shows the flow area increase of the system in its partial format.
3D Managed-Pressure Drilling Around a Salt Dome Using Coiled Tubing: A Case Study—Challenges and Solutions
Authors: Shaikh Abdul Mujeer Abdul Rehman
Published: December 2007

In last several years, the advantages and limitations of drilling with Coiled Tubing has been a subject of research and presentations. Coiled Tubing technology may not be the choice for drilling large diameter vertical holes, but may be the best technology for managing drilling condition within the reservoir. There has been an increasing use of Coiled Tubing technology for ‘side tracking' and ‘hole extension' would tend to support this belief.

Along with the evolution in Coiled Tubing drilling (CTD), there has been a growing acceptance of Managed Pressure Drilling (MPD). Hence the process of using this technology at a commercial level has begun.

The purpose of this paper is to discuss the efficiency of implementing Coiled Tubing technology with MPD conditions while drilling around a salt dome.

The paper proposes an example case study of drilling a 3-Dimensional well around a salt dome tracing two oil pockets at two different depths on flanks of the salt dome. It includes a detailed well plan and the challenges faced like fluid selection, BHP maintenance, complications in steering, and stress considerations around the salt dome and the solutions for the same. The paper also discusses the application of CTD and MPD in combating loss circulation, hole instability problems. It gives the comparison of drilling through a salt dome and drilling around it and the advantages of the latter.