bluuebunny/crossref_metadata_2025 huggingface dataset:
The Use of Model Predictive Control for Asset Production Optimization: Application to a Thin-Rim Oil Field Case
Authors: Van Der Linden Ruud , Leemhuis Anton
Published: February 2011

Increasingly the upstream oil & gas industry is using active flow control (e.g. feedback loops) or passive flow control (e.g. passive ICD) technologies to optimize asset production. They are used, for example, to commingle production, stabilize production in case of water or gas breakthrough, and to mitigate the effect of slugging in wells. While the merits of such flow control technologies are becoming clear, so do their limitations.

One main limitation of using traditional flow control technologies is that, in the presence of complex and changing process dynamics, it is difficult to come up with a controller design that optimizes asset production. Advanced control, specifically Model Predictive Control (MPC), is widely used in the industry to optimize complex downstream processes. In this paper we will start to explore the merits of MPC for upstream applications by means of a realistic test case of a thin oil rim that suffers from gas breakthrough. In the paper three aspects of MPC will be explored into detail.

Firstly, we take a look at the dynamic process models, which lie at the basis of MPC. In MPC the dynamic model is used to compute control actions that optimize the future behavior of the production process. In order to do this, the model has to be sufficient accurate and needs to have a computational burden that allows for real-time optimization. We will discuss how a mixture of physical modeling and data driven models may be used for this purpose.

Secondly, we give concrete examples of such fast dynamic models for the production process of the thin oil rim case. The models describe the dynamic behavior of the gas cone in the reservoir, as well as the effect that gas breakthrough has on well performance. Using such a model, we will evaluate 2 different thin oil rim production strategies that are based on downhole and topside flow control.

Thirdly, we develop a production strategy using the MPC framework. In this approach the dynamic well-reservoir model is used to determine optimal settings of wellhead and ICD valve positions that optimize production. This advanced production control production strategy is benchmarked in terms Net Present Value (NPV) and barrels produced, and compared to cases that use only conventional feedback wellhead flow control. Production improvement in oil production over the first 1.5 years is 17% in the test case.

Since beginning of the 1990's, starting in refineries and base chemical plants, MPC has become the standard advanced control methodology in downstream industries, putting more process knowledge (models) into production control and giving rise to optimal production. A similar development may be expected in the upstream industry. As the paper shows MPC has the potential for bringing real-time production optimization a step closer.
A New Pressure-Rate Deconvolution Technique Based on Pressure Derivatives for Pressure Transient Test Interpretation
Authors: Onur Mustafa , Kuchuk Fikri J.
Published: February 2011

In this paper, we present a new deconvolution method that removes the dependency of the deconvolved constant-rate drawdown responses to the initial reservoir pressure. As is well known, particularly the late-time portions of the deconvolved responses from the recent pressure-rate (p-r) deconvolution algorithms are dependent on the initial reservoir pressure. A small error in the initial reservoir pressure could make a significant difference in the late-time portions of the deconvolved responses that can easily lead to an incorrect interpretation model, particularly misinterpretation of the boundaries. The new method presented is based on pressure-derivative data rather than pressure data that are used in all published deconvolution algorithms. Using pressure-derivative data in deconvolution leads to a nonlinear least-squares objective function that is different from those used in the earlier deconvolution methods and eliminates the dependency of the deconvolved responses to the initial reservoir pressure. Hence, the new method minimizes incorrect interpretation due to an error or uncertainty in the initial reservoir pressure.

We apply the new method to both simulated and field pressure-transient data sets. The results show that the new method offers a significant advantage over the earlier deconvolution methods for pressure transient test interpretation in cases where the initial reservoir pressure is unknown or uncertain.
Refracs: Why Do They Work, and Why Do They Fail in 100 Published Field Studies?
Authors: Vincent M. C.
Published: February 2011

A database has been compiled and analyzed, summarizing more than 100 field studies in which restimulation treatments (hydraulic refracs) have been performed, along with the production results. Field results demonstrate that refrac success can be attributed to many mechanisms, including:

– Enlarged fracture geometry, enhancing reservoir contact – Improved pay coverage through increased fracture height in vertical wells – More thorough lateral coverage in horizontal wells or initiation of more transverse fractures – Increased fracture conductivity compared to initial frac – Restoration of fracture conductivity lost due to embedment, cyclic stress, proppant degradation, gel damage, scale, asphaltene precipitation, fines plugging, etc. – Increased conductivity in previously unpropped or inadequately propped portions of fracture – Improved production profile in well; preferentially stimulating lower permeability intervals [reservoir management] – Use of more suitable fracturing fluids – Re-energizing or re-inflating natural fissures – Reorientation due to stress field alterations, leading to contact of "new" rock

Although less frequently published, unsuccessful restimulation treatments are also common. Documented concerns illustrated in this paper include:

– Low pressured, depleted wells (especially gas wells) posing challenges with recovery of fracturing fluids – Low pressured or fault-isolated wells with limited reserves – Wells in which diagnostics indicate effective initial fractures and drainage to reservoir boundaries – Wells with undesirable existing perforations, or uncertain mechanical integrity of tubing, casing, or cement

This paper will explore the common problems that lead to unsatisfactory stimulation, or initial treatments that fail over time. Guidelines for evaluating refrac candidates and improving initial treatments will be reviewed. The paper summarizes restimulation attempts in oil and gas wells in sandstone, carbonate, shale and coal formations. This organized summary of field results and references will provide significant value to readers evaluating or designing restimulation treatments.
Portfolio Management for Strategic Planning and Operational Optimization
Authors: Back Michael J. , Guercio Cesar
Published: February 2011

Portfolio management has become a mainstream discipline to support investment decisions and capital allocation plans for the oil and gas industry. With more than 70% of the top 50 oil and gas producers companies in the world applying it, the scope and reach of the subject is of vital importance.

The aim of this study is to understand how portfolio management is applied in strategic planning and operational optimization, and how the combination of these exercises allows the strategic guidelines to permeate operational decisions.

The first part of the study covers the best practices for the application of portfolio management when tackling strategic planning. Which are the critical business issues the exercise resolves, how to model the corporate long-term direction through measurable KPIs, and what key objectives companies pursue when allocating strategic capital.

The second section provides some specific examples of ways in which portfolio management theory can resolve operational issues such as rig scheduling optimization, key human resources constraints, and facilities management optimization. The third section analyzes how the output of both exercises logically merges into a solid operation aligned with the company's strategy.

The main outcome of this analysis is the definition of a framework that defines the most efficient way to materialize long-term strategic directions as day-to-day operational guidelines, creating an efficiently aligned organization. Efficiency of the planning process will be explored.
Development of a High Boost, High Power, Ultra-deep Twin Screw Multiphase Pump System
Authors: Williams Adrian , Urban Bob , Margulis Jonah
Published: February 2011

Between 2005 and 2010 Shell has been working with Flowserve and other specialty contractors to develop a next generation pumping system requiring a complete review and redesign of all major components. The work has been performed at multiple locations in Europe and the Americas by an integrated team. It has now reached the level of maturity that it can be shared within the industry. In 2004, Shell performed a comprehensive assessment of industry capability for subsea pumping. This study concluded that boost pressures available at the time were insufficient to meet future project needs, particularly for ultra-deep, heavy oil applications with large gas volumes. As a result the high boost, high power, ultra-deep twin screw multiphase pump development was initiated.

The development included building and testing the subsea twin screw pump, a submersible motor, subsea electrical high power connectors, a pressure compensation system and high bandwidth fiber optic health monitoring system in addition to a purpose-built high capacity test loop. The project is now reaching its conclusion with integration of the core components due to take place by the end of 2010. Individual components such as the pump have already been tested up to 4 MW shaft power, 2400 psi differential pressure, flow rates up to 90,000 barrels per day, with viscosities ranging from 2 – 2,000 centipoise, an order of magnitude greater than any similar existing machine.

This paper describes the work performed, the major challenges addressed and the methodology used to overcome them. One particular challenge was the implementation of rigorous HSE requirements for such high energy, heavy equipment.
Gas Well Deliquification Using Microwave Heating
Authors: Kamal Mohamed , Nikhil Ghodke , Patwardhan S. D. , Al-Dogail Fuad
Published: February 2011

One of the challenging problems of gas production is the liquid loading of a gas well. It is the inability of the produced gas to remove the produced liquids from the well bore. This phenomenon has a significantly negative impact on gas well production rate and reservoir pressure due to build up of liquids in the well bore. The accumulated liquid may be in the form of formation water, condensed water or hydrocarbons condensate which acts as a hindrance to the formation gas getting produced. The ultimate recovery of gas is dependent on the economic removal of accumulated liquids, to allow the gas to get produced. This paper discusses a new idea of using dielectric heating using microwaves to heat and vaporize the water and hydrocarbons in the wellbore, if present. As a result of this heating, the fluid density decreases and the gas and vapours flow naturally to the surface. The frequency of microwaves in general is 2450 MHz; depending on the need, the frequency can be varied. Experiments were carried out on the use of this technology and the results are encouraging. This paper discusses this new technique, results obtained from conducted experiments, and provides advantages to the current methods.
Understanding Wormholes in Carbonates: Unprecedented Experimental Scale and 3-D Visualization
Authors: McDuff Darren R. , Shuchart Chris E. , Jackson Shalawn K. , Postl Dieter , Brown James S.
Published: February 2011

The combination of matrix acidizing experiments with visualization techniques is commonly used to elucidate the details of wormhole networks formed during matrix acidizing of carbonate reservoir rock. Previous experimental studies of wormhole growth have focused mainly on small linear core plugs, with only a limited number of radial flow studies published in the literature. Results from these conventional experiments have provided extensive information on linear wormhole growth in one dimension (1-D) along with some basic insights into radial growth mechanisms in 2-D. However, larger-scale test systems must be considered if 3-D wormhole characteristics are to be understood. Toward that end, a new methodology has been developed which integrates (1) acidizing experiments on carbonate rock samples up to 14 ft3 in volume, (2) high-resolution nondestructive imaging and analysis, and (3) computational modeling to extend the results of experiments to field applications. This article highlights the experimental and imaging components of the methodology.
Managing the Blackstone Swanhills Sour Gas Reservoir Pool, Western Canada
Authors: Chen Andrew , Lamb Derek , Deyell Nicole , Higgins Carl
Published: February 2011

The Blackstone Beaverhill Lake (Swanhills member) "A" Pool is a dry gas reservoir of the sour content up to 22% of H2S+CO2, one of a series of highly dolomitized late Devonian aged reef carbonate structures in the Western Canada. Discovered in 1979, the Blackstone pool is trapped at a depth of 4800 m TVD with a gas column height of 165 m and with an underlying aquifer. The pool size was initially estimated at 1,150 bcf from the early appraisals and the 1985-2000 production data, but revised due to the impact of water influx with two high rate producers watering out at high loading rates. Depleted by only six wells, the pool has produced 770 bcf of gas as of Dec 2009. The final EUR recovery factor could eventually reach 93% under optimized favorable conditions.

Although the pool behaves like a single tank with an average permeability of 50 md, the complexity of dolomitized reef facies, barriers and baffles, porosity and permeability features, made it difficult to forecast the production performance and execute infill drilling plans, on the basis of integrated geoscience & reservoir engineering studies. Additional uncertainties, such as high drilling/workover cost and risks, facilities and gas gathering & processing, gas prices, also confront the pool's depletion plan.

By providing a detailed field case study of the Blackstone pool, this paper demonstrates that reservoir management is a reciprocating business process between fact findings & business options constrained by cost effective measures and commercial matrixes. Timing often emerges as a critical factor. The ultimate goal is to protect and maximize the value of assets. The Blackstone pool proved to be one of a few successful high RF water-drive carbonate reservoirs. Simple water chemistry tracking turned out to be a very effective surveillance practice that altered the reservoir management plans.
Development of a New Completion Fluid Using Polyglycolic Acid Powder
Authors: Nakai Takayuki , Daitoh Masaki , Morita Nobuo
Published: February 2011

Polyglycolic Acid (PGA) has been widely used as a string to stitch scars during medical operations. The string left in human body dissolves with time. It is harmless and biodegradable. Although these properties are attractive, the high cost prevents for oil field applications. However, a technology has been developed to produce tons of PGA with a low cost.

Granular CaCO3 has been used as a fluid loss control material for completion fluids. The mud cake has to be removed after completion instruments are installed, but tends to remain partially undissolved. The PGA powder turns to be a liquid acid with time if it is mixed in water. It is also environmentally harmless if it is disposed in ocean. It is judged that these properties may be suitable to replace the granular CaCO3.

The experiments consist of viscosity, fluid loss, and cake thickness measurements varying temperature and particle size distribution by using PGA powder as a fluid loss control material in a Xanthan Gum polymer completion fluid. Particle size distribution is optimized to minimize fluid loss. Then, the particle size change with time is measured. The mud cake consisting of PGA powder completely disappears after several days.

The results show that the amount of fluid loss tends to decrease when the particle size is finer. Similarly, the thickness of the mud cake is significantly affected by the particle size distribution of PGA powder. It is proved that the PGA completion fluid has better mud properties compared with commercially available low solid polymer fluids. The advantage of the PGA powder as a fluid loss control material is (A) no permeability loss since it disappears with time in pores, (B) a low fluid loss since particle distribution is optimized to minimize fluid loss, (C) no acidizing is required after use since it dissolves itself due to hydrolysis, and (D) it is environmentally harmless.
Estimating Permeability Distributions From Pressure Pulse Testing
Authors: Ahn Sanghui , Horne Roland N.
Published: February 2011

This work investigated how to utilize multiple frequency components of data from pressure pulse tests to estimate the interwell permeability distribution in an equivalent multicomposite reservoir system. When given pressure time series data in the active well and the observation well, the method of attenuation and phase shift characterizes the reservoir properties without having to know the flow rate. Synthetic homogeneous and heterogeneous reservoir cases were examined under periodic steady-state conditions with multiple sinusoidal inputs and multiple frequencies contained in a square pulse signal. By matching attenuation and phase shift at various harmonic frequencies, the results were found to be in good agreement with the actual permeability distribution trend. The analysis of multiple frequencies is useful in describing the heterogeneity of the reservoir parameters quantitatively, when the radius of cyclic influence is consistent with the sourced frequencies.

A new inverse framework of obtaining the permeability distribution by utilizing frequency contents was developed. Attenuation and phase shift of specific frequencies provide the key to describing the reservoir characteristics, and when conditioned on those parameters, the degree of heterogeneity in the reservoir can be revealed. Attenuation and phase shift provide an ‘indicator characteristic’ which can reveal reservoir heterogeneity – without using history matching of pressure, which can be sensitive to noise.
Estimation of Fracture Effective Permeability by Upscaling Using Ensemble Kalman Filter and Streamline Simulation
Authors: Tanaka M. , Tanaka S. , Arihara N. , Okabe H.
Published: February 2011

As naturally fractured reservoirs (NFRs) present a wide range of geological characteristics and complex flow mechanisms between fracture and matrix, reservoir simulation is highly necessary to properly evaluate reservoir performance. Modeling and simulation of NFRs are conducted commonly with two alternative approaches, the dual-porosity model and the discrete fracture model. The single-continuum approach, where fracture systems are represented by effective permeability, is often more effective and flexible for NFRs simulation.

In this paper, we present an upscaling approach to estimate the effective permeability for NFRs based on flow calculations. We used the local-global upscaling (LGU) method as the first step to calculate effective permeability for the discrete fracture model. As the second step, the ensemble Kalman filter (EnKF) approach was applied to assimilate an ensemble of the upscaled models to the production history from the reference model. Although the EnKF has been successfully applied in recent years to inversion problems for inferring parameters from the core scale to the reservoir scale, it is difficult to estimate channel-like high permeability parts because the EnKF works well under the assumption of the Gaussian distribution. We demonstrate and confirm accomplishments and limitations of the LGU and EnKF applied to the discrete fracture model. In order to overcome the limitation, we refined the effective permeability distribution with the velocity field that is calculated by a streamline model.

We demonstrate two cases describing different types of NFRs for which we could obtain satisfactory upscaling and inversion results. In each case, a reference model was set up initially with a fine grid explicitly including discrete random fractures, and 40 realizations were constructed, upscaled to a coarse grid, and processed by the EnKF. The effective permeability fields updated by the EnKF could match the production history, but the streamline and water saturation distributions did not resemble the those of the reference model. The velocity fields that were obtained from the reference model could refine the upscaled models with and without the EnKF assimilation. For all flow simulation, we used our streamline-based simulation model.
A New Look at Low-Resistivity and Low-Contrast (LRLC) Pay in Clastic Reservoirs
Authors: Claverie Michel , Allen David F. , Heaton Nick , Bordakov Georgiy
Published: February 2011

LRLC reservoirs are increasingly at the forefront of the industry's concern in diverse projects ranging from offshore deep-water exploration of turbidites to the development of brown-field secondary objectives. Although LRLC reservoirs have been under production for many years, their identification and the calculation of their reserves and flow properties remains a difficult challenge. This paper compares different petrophysical workflows for clastic reservoirs where thin conductive laminations and high bound water fraction are the source of low resistivity and contrast, with a view to reducing uncertainty in saturations and improving producibility prediction.

When thinly laminated reservoir layers are intercalated with conductive non-reservoir layers, the apparent formation resistivity is dramatically reduced and the apparent clay volume is increased, and the hydrocarbon volume and the permeability calculated from conventional petrophysics are underestimated. We describe new developments in laminated sand analysis and the practical implementation of resistivity anisotropy, including corrections for clay intrinsic anisotropy and thin non-reservoir resistive layers.

Reservoirs with fine grain material, grain-coating clays, or dispersed clays may display high bound water volumes, yet possess significant quantities of producible hydrocarbon. While conventional petrophysical analysis can provide reliable water saturation, it does not distinguish clay- and capillary- bound water from free water. Also, shaly and silty reservoirs often present a complex mineralogy which makes estimates of clay volume and grain density uncertain. We describe the application of nuclear spectroscopy and NMR logs to calculate clay volume, porosity and bound water volume and illustrate their impact on the quality of the resulting evaluation.

Although the petrophysical methods presented were developed for thinly bedded reservoirs, we show that they can improve the analysis of both LRLC and conventional clastic reservoirs. In particular, we propose fit-for-purpose workflows that reduce the uncertainty of fluid volumes and rock flow properties.
Kashagan Field: Defining Stimulation Methodology, Implementation, and Results Evaluation To Provide a Program Redesigning Criterion
Authors: Foglio G. , Wtorek S.
Published: February 2011

The Kashagan oil field, located in the North Caspian Sea in the Republic of Kazakhstan, is believed to be the largest oil discovery in the past thirty years.

To unlock the field's full potential, in particular of the inner non-karstified region, most of the wells have been stimulated with 15% hydrochloric acid, pumped through-tubing in the earlier jobs while coiled tubing units have been later introduced as part of an optimization process.

Almost all initial stimulations have been assessed by well tests accompanied with production logging enabling to carry out a comprehensive analysis of the treatments.

It is known that, significantly larger portion of recoverable oil lies in the tighter non-karstified inner region and therefore an optimized and a successful stimulation practice is essential to an economic project success.

Furthermore, to achieve reservoir engineering stimulation objective of an average -3 skin along the selected perforated Unit 1 intervals, Fig1, it was recognized necessary to review all possible stimulation techniques and acid conveyance methods to maximize the chances to achieve such a challenging an objective.

This paper outlines, in a task and result step format process, an approach that was utilized to select the best stimulation methodology for all Kashagan geological facies and recommendations to formulate a stimulation technique which overcomes technical problem encountered during field operations. Examples are also included to show the results of base original and redesigning criteria.
A 5-Year Survey of Applications and Results of Placing Solid Chemical Inhibitors in the Formation via Hydraulic Fracturing
Authors: Gupta D. V. , Brown J. Mike , Szymczak Steve
Published: February 2011

Solid chemical inhibitors placed in the formation during hydraulic fracturing have provided inhibition protection for up to five years. Deepwater operators, especially, desire longer inhibition periods. This paper provides a summary on treatment results over five years and over 1500 wells. It covers inhibition for scale, paraffin and asphaltene either as a single application or as a multiple product application. These applications have been in various formations including deepwater, tight gas and coal bed methane formations. The longest documented treatment has been in the ground for over five years.

Placing a solid chemical inhibitor into the formation via the fracturing process requires a product that is compatible with the fracturing fluid, does not adversely affect conductivity and provides long term inhibition through the controlled release of the inhibitor into the produced fluid. The solid inhibitor is added to the fracturing proppant. Primarily this is a mass-balance process by which a finite amount of inhibitor desorbs over time. The goal is to maximize the inhibitor loading, minimize the chemical release rate without negatively impacting the stimulation.

In the treated wells inorganic and organic deposition has been arrested for extended periods when compared to alternative liquid addition applications. Solid scale inhibitors have been the most common treatment and are monitored through residual analysis. The paraffin and asphaltene inhibitors are monitored through comparative testing. The paper details both the time and the cumulative production that has flowed through the respective proppant packs.

Wells that are scheduled for hydraulic fracturing and that display tendencies for organic and/or inorganic deposition are candidates for solid chemical placement during the fracture. The results from over 1500 wells indicate that this method for deposition inhibition reduces intervention costs and lowers lifting costs.
Resolving a Water Shortcut Between Old Wells with Multiple Completion Zones: Example in the Dan Field
Authors: Eriksen Katrine , Hansen Ove Egstrøm , Van Der Post Niko
Published: February 2011

In mature fields an important challenge is shutting off injection water breakthroughs. In the Dan field offshore Denmark developed with multi-zone completed long horizontal wells, the primary method now is closing Sliding Side Doors (SSDs) in the horizontal completions. A shortcoming of this method is that it does not work if there is communication between individual zones or holes in the tubing. This is the case in many of the up to 20-year-old wells.

The primary goal of a recent coil tubing conveyed well intervention was to remove a shortcut between two horizontal wells: a producer with 16 sand fracced zones and an injector with 5 water fracced zones. This was planned to be done by closing one or two PSI zones in the injector. The connection could not be removed by shifting zones in the producer due to a restriction in the vertical section, making the horizontal completion of the well inaccessible.

Production logging results of the shut in injector showed a substantial cross-flow from zones 1 and 4 into zone 3 via both the sliding side door and a hole in the zone. Due to the presence of cross-flow, the injection well was effectively injecting an estimated 4,000 bbl/d into the culprit zone, when closed in at surface. Due to the tubing leak in zone 3 it was not possible to stop the flow out of the zone by shutting the door, so all zones (1-5) in the well were closed, and injection was stopped. The closure of all zones in the injection well resulted in an immediate response in the production well, reducing water production with 6,000 stb/d while increasing the oil production with 1,200 stb/d.

The intervention and responses in nearby wells indicated that the injection well was connected to up to three other water injection wells and up to two other production wells. In this paper the reasons for these short cuts and the impact it has on water flooding are analysed.

The lack of water injection in the area has resulted in declined production in other wells, hence the future challenge for the area is finding a new way of shutting the connections either by means of chemical conformance treatment in cases of connected zones or straddles in wells with tubing holes.
How to Decide Between Horizontal Transverse, Horizontal Longitudinal and Vertical Fractured Completion
Authors: Economides M. J. , Martin A. N.
Published: February 2011

Augmented by the recent activities in shale gas, hydraulic fracturing of horizontal wells has become increasingly popular, although the technology has existed for over 20 years. The success in shale gas activities and advances in completion technology may have generated the false impression that fractured horizontal wells may be successfully applied to almost any formation.

Although the very low-permeability shale gas formations in the cost-controlled environment of North America may have justifiably made multiple-fractured horizontal wells the completion of choice, many do not realize that there are circumstances where a simple vertical fractured well may significantly outperform a fractured horizontal well. Because it is usually too late to change completion type once the wellbore has been drilled, it is vital that the selection of type of fractured completion to be used is considered during initial well and field development planning.

This paper will discuss the production mechanisms from horizontal transverse, horizontal longitudinal and vertical fractured wellbores. Calculations of the incremental performance of each configuration are done for both oil and gas wells. There are physical and economic limits and criteria. For example, for gas wells in reservoirs above 0.5 md, there is an unacceptable reduction in the performance of each transverse fracture because of enhanced turbulence effects. There are also economic criteria for selecting which type of completion is the optimum choice. We look at a range of reservoir and proppant pack permeabilities and discuss the optimization of fracture geometry. The paper not only delineates areas of indicated application of each well completion but it highlights the importance of considering the hydraulic fracturing process from the very start of wellbore planning. The processes involved in planning a wellbore for efficient decision making and maximum flexibility of choice are also described.
Comparative Well-Test Behaviours in Low-Permeability Lean, Medium-Rich, and Rich Gas-Condensate Reservoirs
Authors: Kgogo Thabo C. , Gringarten Alain C.
Published: February 2011

Large condensate banks develop around producing wells in gas-condensate reservoirs when pressure drops below the dew point pressure, inducing severe losses of productivity. Actual well test behaviours depend on fluid composition, formation permeability and production rates.

Several publications have presented well test behaviours in high permeability lean and rich gas-condensate reservoirs. This paper investigates well test behaviours below the dew point pressure in low permeability lean, medium-rich and rich gascondensate reservoirs using 3-D compositional simulation. It is shown that during a drawdown below the dew point pressure, medium-rich to rich gas-condensate fluids in the condensate bank change to near critical fluid near the wellbore. If such a drawdown is followed by a shut-in where the pressure builds up above the saturation pressure, the oil revaporizes completely and the fluid in the wellbore vicinity becomes single-phase gas again. This does not occur in lean gas reservoirs, where the condensate saturations at the end of a drawdown and in the subsequent build up are very similar. Another difference is that lean and medium-rich gas-condensate fluids yield three mobility zones on a derivative plot corresponding to: (1) the original gas in place away from the well where the pressure is above the dew point pressure; (2) the condensate bank closer to the well; and (3) capillary number effects in the immediate vicinity of the well. By contrast, only two mobility zones are created in the case of rich gas-condensate fluids (capillary number effects are not seen in practice).

The understanding of pressure behaviour in low permeability, gas-condensate reservoirs developed in this paper was applied to actual well test data from a South Coast Gas field located offshore South Africa and helped optimize well performance and reservoir management strategies in that field.
A Discussion of the Low Salinity EOR Potential for a North Sea Sandstone Field
Authors: RezaeiDoust Alireza , Puntervold Tina , Austad Tor
Published: February 2011

Due to the lack of an exact chemical understanding of the mechanism for enhanced oil recovery by low salinity water flooding in sandstones, predictable EOR effects based on actual reservoir parameters have not been possible to obtain.

Recently, we published a new chemical mechanism for the low salinity effect, which is in line with experimental documentation so far. In this paper, the results for low salinity lab experiments related to an offshore field in the North Sea are discussed in relation to the new chemical knowledge. The important reservoir parameters for the actual field are: total clay content 8-16 wt%, crude oil acid and base numbers 0.13 and 0.85 mgKOH/g, respectively, formation water salinity 201 000 ppm, and reservoir temperature 130 °C. The reservoir has been flooded with seawater, and the question is: "Is it possible to increase the oil recovery by injection of diluted seawater as the low saline fluid?" In most cases, the cores were first flooded with formation water in a secondary process followed by diluted seawater, 1600ppm, in a tertiary process. The extra oil recovery varied between 0–6% of OOIP. In light of the newly published mechanism, the results are discussed in terms of: Clay content: type and amountpH: initial and change in pHConcentration gradient in the most active cation, Ca2+Initial water saturation and composition.Effects of aging and flooding temperature.

For a given system, the low salinity EOR effect appeared to be strongly linked to the change in pH. Low initial pH, created by the presence of CO2, increased the adsorption of polar components onto clays, which normally will lead to enhanced oil recovery due to the low salinity water flooding effect.
CO2-Induced Changes in Oilwell Cements Under Downhole Conditions: First Experimental Results
Authors: Garnier André , Laudet Jean-Benoît , Neuville Nadine , Le Guen Yvi , Fourmaintraux Dominique , Rafai Noureddine , Burlion Nicolas , Shao Jian-Fu
Published: February 2011

One of the major technological issues for CO2 injection (for EOR, CCS, etc.) is the long-term behavior of cement-based materials used to ensure the overall sealing performance of the storage wells. When water is present, the CO2 after injection can react chemically with the cement (i.e. carbonation).

How do the CO2-enriched formation fluids changes the cement's chemistry and properties? Could the sealing efficiency of the wells be affected by these changes?

The objectives of our experimental program are to assess the kinetics and phenomenology of the changes that occur in different class-G Portland cements exposed to CO2-enriched aqueous fluids at 8 MPa and two different temperatures.

The experimental program presented in this paper consists of: a first carbonation test (Test # 1) using neat G cement, at a temperature of 90°C (194° F) and a pressure (supercritical CO2 above water) of 8 MPa (1160 psi); a second carbonation test (Test # 2) using G cement with silica flour (to prevent strength retrogression), at a temperature of 140°C (284°F) and at the same CO2 pressure of 8Mpa. Finally, coupled chemo-mechanical tests (dynamic tests) are underway on similar class-G cement and similar CO2-rich water.

All the samples were prepared according to ISO/API specifications. The experimental set-up simulates downhole "static" conditions: the samples were immersed in water in a cell thermally regulated and pressurized by CO2. Cement samples were exposed to CO2-saturated water for various lengths of time (from one week to 3 months) and were characterized using advanced methods for chemical and mineralogical analysis (X-ray tomography, SEM, XRD, TGA-TDA…) and mechanical testing.

The main preliminary results show a reactive front (characterized by carbonation) progressing from the fluid-sample interface towards the sample centre. The carbonation front moves faster during Test 2 (at higher temperature) than during Test 1 (at lower temperature). SEM images of Test 2 also show a thin layer of dissolved carbonate at the sample's surface. The carbonated cement areas exhibit increased density and greater compressive strength.

The results of coupled chemo-mechanical tests with injection of CO2-enriched water in samples under deviatoric stress show that the CO2 flow rate in the cement rapidly decreases, finally resulting in carbonation clogging of the cement sample. These results seem consistent with reported field observations.
Maximising Production And Extending Economic Life Of The Woollybutt Oil Field, Carnarvon Basin, Australia, "From Little Things, Big Things Grow"
Authors: Wheller Dave , Selvaggi Doani , Kostas Kon , Loro Richard , Hearty Dave
Published: February 2011

The Woollybutt Oil Field was discovered in 1997 and further appraisal drilling delineated two separate oil accumulations in the Early Cretaceous Barrow Group Sandstone; the Woollybutt North and South Fields. The Woollybutt North Field came on production in April 2003 with an expected field life of three years. Subsequent review and development drilling in 2005 extended the Woollybutt North Field life to 2008. The tie back of the Woollybutt South Field in 2008, previously thought to be an uneconomic area, has again increased total field life expectancy and consequently increased the expected ultimate recovery for the field.

Issues with the unknown level of productivity of the poorer quality basal Mardie Greensand reservoir and the seismic velocity gradients across the field, generated a large uncertainty in both well productivity and structural closure of the field.

A review was undertaken which integrated geophysical, geological and reservoir engineering expertise. This review resulted in the revision of the Woollybutt geological model and the development of the Woollybutt South Field. An additional benefit was to also extend the production life of the Woollybutt North Field.

This paper describes the original geophysical and geological model and demonstrates how simulation history match feedback can influence the mapping of the structural closure of the field. This result was integrated with a wireline mini drill-stem test within the poorer quality reservoir sandstone and led to the development of a new geological model. Subsequently the decision was made to develop the Woollybutt South Field, which is dominated by this poorer reservoir; the basal Mardie Greensand.

Woollybutt is operated by Eni Australia (65%) with partners Exxon Mobil (20%) and Tap Oil (15%).
Drilling Highly Fractured Limestone Reservoirs: Is It a Particle Bridge Too Far?
Authors: Vickers Stephen , Hutton Alistair , Main Ryan , Twynam Alan , Jackson Greg
Published: February 2011

Historically, wells drilled on the Machar Field in the North Sea have experienced huge downhole losses and remedial techniques to stem losses have been marginally successful. One well experienced oil-based mud (OBM) losses exceeding 26,000 bbl. Furthermore, the massive losses of oil-based mud had threatened the future of this project.

A new phase in the development of the field was planned that entailed drilling two producers and one injector well that would be tied to an existing subsea manifold, which in turn would connect to the production platform. A drilling fluid formulation was requested that would bridge off the wide range fracture widths and stop the massive ingress of well fluids, especially in the reservoir where back-flow would be hindered and remediation difficult.

The design and successful application of a fit-for-purpose drilling fluid system to deal with highly fissured limestone of varying fracture widths was a key planning element for the new Machar Field drilling campaign. The knowledge gained from drilling fractured formations in the Middle East and the experience using stress cage principles in depleted reservoirs of the Southern North Sea have been adapted to successfully drill and seal limestone formations and prevent damaging losses.

This paper will discuss the drilling fluids design process and the laboratory testing used to predict the bridging and sealing efficiencies needed to seal fractures ranging from 50 to 1000 microns. Testing was conducted using formulations with different materials of varying size, shape and resilience. The basis of design and knowledge gained in the laboratory was transferred to the field where losses were dramatically reduced to only six bbl in the 6-in. section. The first well was successfully flowed at the production target level and the second well surpassed the expected production index by a factor of three.
Sand on Demand for Horizontal Wells: Tracking Behaviour with the CT Scanner
Authors: Meza Diaz Brigida , Ron Sawatzky , Kuru Ergun
Published: February 2011

The cold production recovery process is successful in vertical wells in western Canada. In this process, large amounts of sand are produced on a continuing basis along with heavy oil. Attempts at cold production in horizontal wells have not been particularly successful. When sand production has been generated in horizontal wells, these wells have tended to become plugged with sand.

This paper presents the results of experiments performed to assess the feasibility of applying cold heavy oil production with horizontal wells using less aggressive (i.e., managed) sand production strategies. Specifically it describes the impact of relatively small changes in flow rate on sand production behaviour. The effects on the porosity distribution within the sand pack due to sand production were monitored during one experiment through computed tomography (CT) imaging. The experimental results indicated that the effects of sand production were confined to localized regions (channels) within the sand pack where there was a large permeability and porosity increase. Outside these regions no changes in permeability and or porosity were observed. Channel growth could be controlled successfully (i.e. stopped/started) through flow rate changes. Another experiment demonstrated that continuing sand production at low sand cuts could be achieved if the initial flow rates were low and later increased in small increments.

This suggests that if the latter operating strategy is implemented in the field, sand production may be sufficiently high to generate regions (wormholes) with high permeability but sufficiently low to allow produced sand to be transported along a horizontal well.
Challenging Global Capillary Applications for Enhanced Production
Authors: Pate Brad , Stanley Rick
Published: February 2011

Over the past decade the oil and gas industry has seen the applications for capillary tubing expand from basic onshore chemical injection applications to complex and innovative offshore applications that continue to challenge and redefine the boundaries of conventional well intervention methodology. Well interventions in today’s economically challenging environment can sometimes be difficult to justify. Capillary tubing systems have recently been deployed on challenging new projects in Asia Pacific, Europe and the USA to provide operators with an alternative cost effective method to maintain well bore integrity and enhance production.

Typical capillary tubing sizes are 1/4, 3/8, 5/8 and 3/4-inch OD. Capillary tubing systems have three primary applications and functions. The first being semi-permanent installations for the continuous injection of chemicals down hole for production enhancement. Capillary enables effective and cost-efficient delivery of production or stimulation chemicals at precise downhole depths while maintaining full ESD (emergency shut down) and SCSSV functionality. Secondly for reactivating wells that have been shut in due to the loss of SSSV control line integrity. The third being a wide range of work string activities similar to those performed by conventional “Big Coil” units such as: -Scale Removal with Acids-Solids Removal-Gas Lifting-Paraffin Removal with Chemicals-Hydrate Removal-Logging Tool Deployment-Cementing

A typical capillary equipment package (Figure: 1 and 2) is comparable to but much smaller than a standard coiled tubing spread with a substantially reduced cost, environmental impact and risk exposure. The small light weight foot print is especially beneficial in conditions with crane or deck space limitations. Capillary equipment can be custom designed to suit most land or offshore applications. Capillary tubing can be installed on a semi-permanent basis or deployed as a work-string for well intervention programs. A specially designed sub-surface safety valve (SSSV) system can enable capillary installation in wells with existing SSSV systems. Installations or well interventions can be performed in a matter of hours in most situations.

New and innovative capillary technologies allow the equipment to be applied to a broader spectrum of well servicing applications. This has the potential for substantial reductions in operating cost, logistical support and risk exposure that can be applied to operating environments worldwide both onshore and offshore. Wells that were once considered plug and abandon candidates due to cost, technical challenges or accessibility may now be candidates for capillary technology solutions.