bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.
A Case History: The Installation of a Damaged Control Line Replacement Safety Valve System in a North Sea Well
Authors: Barratt T. , Goldsworthy B. , Hamilton S. , Lacy R. , Taylor M. , Ross A. , Mackie S. , Calzoncinth E. , Dennistoun S. , Jacob J.-L. 
Published: February 2011

Abstract
The GA-03 well on the Gannet platform in the UK sector of the North Sea developed a blockage in the safety valve control line that rendered the existing tubing retrievable safety inoperable. In addition, the seal bores inside the valve were scarred and damaged badly enough that a conventional wireline safety valve would not seal. These were the problems confronting the operator as they planned remediation work to return the well to production. Initially a major rig workover had been anticipated to pull the tubing and replace the safety valve and control line. This operation required the use of a Hydraulic Workover Unit (HWU) to perform the work which would carry a multimillion dollar cost.
An alternative method was examined that would allow replacement of the safety valve and control line without pulling the production tubing or making changes to the wellhead configuration. This alternative method was a new concept not previously attempted by any operator in the North Sea. This innovative approach would involve the installation four elements:
A new safety valve landing nipple in the production tubing using a specially modified seal bore production packer. A new wireline safety valve that would be landed in the new landing nipple A new control line and special control line connector installed inside the production tubing. A modified lower master valve to allow wellhead penetration for the injection of hydraulic power fluid to the new control line.
This particular combination of tools had never been run together and their installation would have to be accomplished under a severe deadline, as the HWU job had been planned for execution in September 2009. To accomplish this, the entire operation had to be planned, designed, manufactured, tested, qualified and installed in the GA-03 well before the end of the year. It is a great credit to the project team that from initial proposal for use of the new system in July, they were able to achieve the target date of returning the well to production by the end of 2009. This showed the high level of cooperation and collaboration between the operator and the completion tool and wellhead providers.
This paper will describe in detail the system components and the decision processes and evaluations that led to the selection of this alternative repair method. The collaborative efforts between the operator and two major service providers will be examined and discussed and the installation procedure described in detail. The paper will describe why the successful completion of this project marks a significant milestone in the remediation of older producing wells.
Designing, Implementing, and Sustaining a Business-Driven Competency and Employee Development Program
Authors: Demski Dave , Leuro Jorge 
Published: February 2011

Abstract
Employees, through their competence and commitment, are responsible for a large measure of business success in the oil and gas industry. This paper describes how Halliburton designed, implemented, and is continuing to sustain a global program to develop more than 40,000 of its workforce of 54,000. The company has created a unique employee development program that links work processes, business performance, employee training, competency development, and employee engagement. This case history demonstrates the effect that developing employees can have on business results.
The program has been implemented globally for 10 product service lines and eight support groups in eight regions; it provides a standard and a business-focused means of developing employees. A structured implementation process was used to ensure that the program was business-driven and that there was clear accountability for its implementation.
Effective development and engagement of employees improves business performance in the areas of service quality; health, safety, and environment; employee retention; and financial results.
Since the inception of the program, it has provided the following:
Reliable and business focused employee development framework Proven implementation process and accountability of all parties involved Improved business results by developing and engaging employees "Win-win" outcome for the company and for its employees
Treating Produced Water on Deepwater Platforms: Developing Effective Practices Based Upon Lessons Learned
Authors: Walsh John M. , Frankiewicz Ted C. 
Published: February 2011

Abstract
Deepwater platforms in the Gulf of Mexico and elsewhere are transitioning from dry oil or low water cut production to higher water cut production. These platforms face unique challenges resulting from water and crude incompatibilities, high salinity, no advance characterization of the water treatment issues, and a lack of space for water treatment equipment. The lessons learned by deepwater operators can provide an experience base upon which future operators can draw to assist them with projects to debottleneck and/or improve produced water treatment on their deepwater platforms and FPSOs.
Equipment and practices which have worked well and not worked well for treating produced water on floating platforms are described and the issues pertinent to the deepwater operation of this equipment are identified. The impact of the deepwater operating environment on produced water treatment systems is discussed. Platform motion, high shear across control valves or pumps, production from multiple reservoirs, process recycle streams, and the use of hydrate inhibitors or other chemicals all impact the design of a water treatment process and the operation of water treating equipment. The experiences detailed in this paper are intended to help engineers avoid the process design and equipment selection issues which were problematic for earlier deepwater operations.
Pore-Scale Simulation of Hysteresis Effects During Repressurisation of Gas-Oil Systems
Authors: Bondino I. , McDougall S. R. , Ezeuko C. C. , Hamon G. 
Published: February 2011

Abstract
Repressurisation of a hydrocarbon reservoir may occur either as a natural response to subsurface phenomena (for example, aquifer encroachment or fault re-activation) or as a consequence of a particular production strategy. In this paper we examine, for the first time to our knowledge, the pore scale mechanisms underlying the repressurisation of a gas-oil reservoir that has previously been exploited by solution gas drive. Our investigation, triggered by experimental observations in both glass micromodels and cores, utilizes a pore-scale network model: a modelling approach that is nowadays sufficiently mature to facilitate virtual experiments that are rapid, cheap and physically realistic.
The new physics implemented here captures a wide range of phenomena related to multiphase repressurisation, including gas re-dissolution in oil by diffusion, bubble retraction, fragmentation and re-stabilisation under gravitational forces, and oil reimbibition.
It is found that repressurisation is not simply the reverse of primary depletion, as the previously developed gas phase does not simply retract from the latest pores invaded during depressurization: rather, the process exhibits a large degree of hysteresis in both local supersaturation and gas phase distribution. We have studied the effects of several combinations of depressurization and repressurisation rates upon phase distribution and recovery, as the system is first depleted below bubble point and subsequently repressurised back to the starting pressure. Crucially, we find that a highly dispersed gas phase can persist once the original bubble point of the oil has been reached at the end of repressurisation. It is clearly shown that the repressurisation of an unequilibrated system essentially generates a high bubble density: this could theoretically be exploited by a secondary depletion to obtain improved recovery, as it is well known that the generation of large numbers of bubbles (generated by nucleation or, as we suggest here, induced by repressurisation) is highly beneficial for solution gas drive performance.