bluuebunny/crossref_metadata_2025_split huggingface dataset:
Open-Hole Gravel Packing with Solid-Free Oil-Based Carrier Fluids – A Case History and World Class Triumph for the Industry
Authors: Jones Tom , Willis Steven , Hill Leo , Charles J. E. , Brown Pat , Frederick Mike 
Published: May 2009

Abstract
In many open-hole completions in unconsolidated reservoirs, the preferred method of sand control is a conventional gravel pack across sand exclusion completion screens. To date the gravel pack options available for horizontal or highly deviated wellbores have been the use of brine-based gravel pack carrier fluids or the use of viscous gel packs using alternative path screen technology. The first option, using brine as the carrier fluid, has limited applicability because many reservoir intervals have brine-sensitive shale that, if not stabilized, can disrupt the gravel deposition during the alpha-beta (α-β) packing process, especially in long intervals. The second option, using alternative-path screens and viscous carrier fluids, overcome the shale destabilization issues but not without a compromise in the quality of the pack or the higher price tag.
A third option is now available that utilizes a new, solids-free, invert emulsion gravel pack carrier fluid. This option overcomes the issue of shale destabilization and interupted gravel deposition often associated with brine packs because it avoids the exposure of water-sensitive shale to aqueous fluids.
This paper provides the design details of a carrier fluid that overcomes the technical hurdles of a conventional brine-pack operation as well as the fiscal limitations associated with alternative path technology. Included are the planning and execution details of a 5-well, back-to-back gravel-packing operation from an offshore platform in the Bualuang Field, Gulf of Thailand whereby successful gravel deposition occurred on each well using a invert emulsion system as a carrier fluid. The results presented of this case history sequence clearly demonstrate a world class break-through and triumph for the oil industry.
Overcoming Near Wellbore Damage Induced Flow Impairment with Improved Perforation Job Design and Execution Methods
Authors: Ibrahim Hanaey , Harrasi Ali , Salsman Alan , Nunez Alvaro Javier , Situmorang Haposan 
Published: May 2009

AbstractOptimal well productivity is achieved by establishing a clean connection to the wellbore through the near wellbore zone of drilling and completion induced permeability impairment commonly referred to as the "near wellbore damaged zone". This connection through the damaged zone is usually achieved by perforating and the effectiveness of this connection is the result of the perforating system selection, the well environment in which the perforating job is executed and what happens to the perforations after shooting and before they are used for production or injection.In the depleted oil field under study a typical completion is perforated using large diameter, high shot density tubing conveyed (TCP) guns with deep penetrating charges shot underbalanced using the classic "shoot and pull" technique. After shooting, before the guns are pulled, the well is killed. Perforation and kill related damage severely impacts these wells leading to high skin and rapid production decline.The challenge in this field is to identify the most effective perforating system and job execution method to achieve good well productivity over an extended period of time. Modeling software is utilized to predict the Productivity Ratio (PR) for different perforating systems considering gun size, charge type, shot density, reservoir characteristics and the well conditions at the time of shooting.The optimal gun system is run with gas lift on to establish underbalance conditions at the time of shooting for immediate perforation clean-up. The under balance just prior to the time of shooting is managed using a permanent down hole gauge installed in the completion string.The first well completed using this new method showed improved production of 4 times what was expected compared to similar wells in the field perforated using the shoot, pull and kill technique. Additional wells perforated using this technique show similar, higher than expected, results.This paper reviews the job design criteria, job execution requirements and an evaluation of the results for several wells in this field. Total job costs will also be evaluated.The result of this novel perforating technique is a new completion strategy for oil fields in Oman improving overall well performance.
Overcoming Poroelastic Behaviour in the Water Injector Wells in the Kikeh Deepwater Development
Authors: Webb Tamara , Omar Jusni , Daungkaew Saifon , Lim Lee Chin , Tibbies Ray , Munoz Ivan , Morales Hugo 
Published: May 2009

Abstract
Kikeh Field is a deepwater project located in Malaysia. The development plan for this field requires fifteen water injectors, eighteen producers, and one gas injector to be completed in more than 4,300 ft of water depth. In order to maintain the oil production target for this field, the water injection rate should double the target oil rate. To achieve this, water must be injected into the formation at fracturing pressures.
The completion campaign started with three water injector wells. The initial results were not as expected, i.e. after pumping 1000 bbls of treated seawater at rates from 7 to 14.5 bpm, surface pressures were still within the pressure limit of 3000 psi, given by the Floating Production Storage and Offloading (FPSO) facilities. However, the injection rate was decreased with increase in pressure, and skin factor was found to be increased. Another observation was that the formation was not fractured at pressures exceeding the expected closure stress.
Possible explanations for such behaviour were: (1) the development of a "temperature" sensitive emulsion in the reservoir matrix, (2) the effect of temperature in viscosity of our seawater crude, (3) near wellbore damage caused by fines from the injected water blocking the near wellbore region.
When a second injectivity test on the second well was conducted, again the injected rate was not able to create fracture even though the injected pressure was above the breakdown pressure. After analyzing the injectivity data, another mechanism related to poroelastic stress was postulated. Poroelastic stress is a transient localized stress increase caused by fluid injection into porous media.
Possible explanations have been looked in details using pressure transient data and it supports the theory of poroelastic effect. Then the remedial action was selected to overcome poroelastic behaviour in the Kikeh field. The operation procedure and the result obtained after injecting Viscoelastic fluids at fracturing rates are discussed in this paper. This paper also describes the evaluation of skin after each injectivity test from pressure transient analysis.
The Mitigation of Formation Damage and the Application of a New Scale Squeeze Inhibitor
Authors: Guan Hua , Rohde Hans Christian 
Published: May 2009

Abstract
In certain North Sea fields, barium levels of 250 ppm in formation water can lead to downhole sulphate scale deposition. Conventional treatment involved a squeeze inhibitor deployed through an aqueous phase. However, a squeeze treatment of low water-cut wells in water-sensitive formations and/or those with poor well lifting ability may result in negative wettability effects, formation damage by water blocking, and temporary process upsets.
This paper describes the development of a new chemistry designed into an optimized squeeze package that has successfully mitigated formation damage and provided extended squeeze life time in the field. Significant permeability reductions were observed for both the Clashach formation and the reservoir during core flood tests when this new chemistry was applied in an aqueous package. The authors will discuss and identify the mechanisms of formation damage and its mitigation. Reformulation of the squeeze package focuses on the most cost-effective solution. A final reservoir core flood was conducted using a partially non-aqueous package consisting of a mutual solvent pre-flush stage prior to the injection of the main pill and aqueous overflush. The outcome of this treatment was very promising, as no permeability reduction was observed following the treatment and modeling of the squeeze life time yielded impressive predictions.
A squeeze treatment using this optimized package was deployed successfully in the field, where no process upset was observed and no emulsion breaker was required during start up. Increased oil production was noted after the treatment and extended squeeze life time (&gt;180 days) was obtained with in excess of 650,000 m3 of water protected. The inhibitor return was still over the MIC (Minimum Inhibitor Concentration) when the well was re-squeezed using the same package. The authors discuss performance of the field trial and compare it with previous treatments.
Reducing Water Rates to Increase Hydrocarbon Rates in Australia
Authors: McGowen Mary A. Hardy , Barrett Emile , Dedigama Thivanka , Squire Andrew , Vasquez Julio 
Published: May 2009

Abstract
Conformance efforts in the Cooper Basin, Australia have been focused on treatments that have the potential to increase hydrocarbon rates. This paper describes the candidate selection process and field application of two different types of conformance treatments that were designed to increase hydrocarbon rates by reducing water rates. In all cases, production of reserves was thought to be impaired by excessive water production. In the cases where water production was decreased as a result of the conformance treatment, the wells produced at significantly higher hydrocarbon rates. Descriptions of both conformance systems (a minimally-penetrating porosity-fill sealant and a hydrophobically-modified relative permeability modifier, RPM) are provided.
The process of identifying wells that have a potential for increased oil-production rates if the water rates are reduced required modification of the traditional candidate-selection criteria. This ultimately changed how the water-production mechanisms were defined. For instance, when supported by production data, channeling was still considered as a plausible water-production mechanism even if the CBL appeared to show good cement bonding to the formation and casing. In addition, RPM technology was considered viable for upwards fining reservoir sections, even if water was coning up into the well. However, special conditions also needed to apply.
In this paper, the details of how treatment candidates were selected, treatment designs, placement techniques, and results are presented. The wells and reservoirs for each case are discussed, illustrating how water production compromised the oil or gas production. The way that these details and the conformance-fluids’ capabilities and characteristics were used to design the conformance treatments is also discussed.
Analysis of the Effect of Residual Oil on Particle Trapping During Produced Water Reinjection Using X-ray Tomography
Authors: Saraf A. , de Zwart A. H. , Currie Peter K. , Ali Mohammad A. J. 
Published: May 2009

Abstract
Recently it has been shown that the presence of residual oil in a formation can have a considerable influence on the trapping mechanisms for particles present in re-injected produced water (Ali 2007, Ali et al 2005, 2007, 2009). This article reports on a further set of extensive coreflow experiments which confirm and extend these results. The tests were conducted in a CT-scanner, allowing direct observation of the build-up of particle deposition along the core.
These experiments are relevant to operational issues associated with PWRI (Produced Water Re-Injection). In many cases, produced water is injected into formations containing oil, so reduced oil saturation is achieved rapidly in the area around the well. Even if the well is outside the oil zone, trapped oil droplets are always present in produced water, and a residual oil zone will gradually build-up around the well.
Major differences are found between the deposition profiles for fully water saturated cores and the cores having residual oil saturation. In particular, particles penetrate deeper into the core with residual oil saturation and considerably more particles pass completely through the core without being trapped. The X-ray technique allows direct observation during the experiment of the deposition process inside the core, eliminating the complicating effect of any external filter cake. As a result, an analysis can be performed of the deposition parameters relevant inside the core, using Deep-bed Filtration Theory, and the results of this analysis are presented. In particular, it is shown that the values of the filtration function determined from the CT-scan (X-ray) data are consistent with those obtained from analysis of the effluent concentration. Moreover, both methods of analysis find quite clearly that the filtration coefficient increases with decreasing flowrate.
The results indicate that formation damage near a wellbore during water injection will be reduced by the presence of residual oil, and that particles will penetrate deeper into the formation. The result is also relevant to injection under fracturing conditions, since particle deposition in the wall of the fracture (where residual oil may be present) is one of the mechanisms governing fracture growth.
Salt Precipitation in Gas Reservoirs
Authors: van Dorp Q. T. , Slijkhuis M. , Zitha P. L. J. 
Published: May 2009

Abstract
This paper reports a study of halite precipitation in gas reservoirs and the ensuing formation damage. The examination of productivity decline in several wells revealed that halite precipitation is most likely due to water evaporation with pressure drop in the vicinity of the well-bore. Hence the model was developed in an attempt to capture the main features of this phenomenon. In addition to the classical mass and momentum conservation equations the model includes equations describing: (a) the evaporation and salt precipitation kinetics and (b) the modification of porosity and permeability due to restriction of the pores by the halite precipitate. The equations were solved numerically for the one dimensional case, using standard reservoir simulation methods.
Laboratory experiments were performed using a sand pack containing highly saline water at ‘irreducible’ water saturation. The sand pack was conical in shape to simulate radial inflow effects. CT scans of the sand pack were used during the experiments, in conjunction with pressure drops monitored over several sand pack segments, to reveal the details of salt precipitation. This enabled us also to quantify the water saturation and to check the integrity of the sand pack, as pressured gas flow might cause viscous fingering. Simulator results clearly show increased pressure drop over the length of the sand pack; especially so at the narrow outlet section of the sand pack, indicating that salt precipitation occurs predominantly in what would be the near wellbore region. CT scans and conductivity measurements of individual sand pack segments have confirmed these results in the lab.
Effect of Oil Saturation on Foam for Acid Diversion
Authors: Simjoo M. , Nick M. Mahmoodi , Zitha P. L. J. 
Published: May 2009

Abstract
Foam is widely used in oil and gas recovery operations as a mobility control and profile correction agent. A brief list of foam applications includes acid diversion during matrix stimulation, gas blocking, hydraulic fracturing and clean-up of contaminated subsoil. In order to meet the growing demand of more difficult foam applications a deep insight on the dynamic of foam flow in a porous media is crucial to design a successful treatment. This paper is concerned with the foam flow behavior for acid diversion application taking into account the oil presence in the treated zone.
We report an experimental study based on core-flood experiments performed with the aid of X-ray computed tomography (CT) imaging technique, using Bentheimer sandstone and N2 foam. During the experiment, the residual oil condition was first established by performing drainage process followed with gravity stable water flooding to mimic the initial fluid distribution of the treated zone. Then, N2 was injected at a constant flow rate into the porous media saturated with surfactant solution. A series of longitudinal CT images were taken at different time intervals and pressure drop over the core was also monitored. The experiments were analyzed in terms of qualitative description of CT images, in situ liquid saturation profiles and pressure drop evolution along the core.
The experimental results indicate although foam breakthrough in the presence of oil occurs earlier than in absence of oil; however, foam generation continues, so that the liquid phase is displaced by foam flow in the treated region.
Identifying Point of Failure and Repairing Damaged Sand Screens in Gravel Packed wells. A Case History From the Heidrun Field
Authors: Svela Per Einar , Gustavsen Øyvind , Solli Hilde Songstad , Brandal Øystein 
Published: May 2009

Abstract
Due to low sand strength the preferred completion method for the Heidrun field is gravel packed screens. This has proven to be a well suited sand control method. However, some failures have been encountered with the subsequent loss of the well or a reduced production rate due to sand production. Some of these failures are related to water break through which can induce the production of fines and result in plugging and erosion of the sand screens. When these type of failures result in the onset of massive sand production, it is a challenge to handle the well properly. How do we best produce the well to avoid it being filled with sand, and how do we best identify the point of failure? Identifying a failed sand screen is not straight forward since it is situated on the outside of a perforated base pipe, and no direct measurements can be achieved.
This paper describes a method used on several wells in the Heidrun field to mitigate failures in gravel packed screens. The method described, includes; how to identify sand production, the preferred way to run the well after sand production has been identified and how to perform data acquisition to determine the point of failure. The data acquisition described includes gravel pack logging, injection logging and saturation logging.
This method has been used with success on several wells in the Heidrun field, wells which would have been considered lost otherwise.
Efficient Intelligent Well Cleanup using Downhole Monitoring
Authors: Olowoleru D. K. , Muradov K. M. , Al-Khelaiwi F. T. , Davies D. R. 
Published: May 2009

Abstract
Effective well cleanup during well start-up ensures efficient formation damage removal and maximises the resulting well production potential. Horizontal wells are more susceptible than vertical wells to formation damage due to the longer completion length, the longer drilling time, the potentially increased overbalance and the reduced cleanup efficiency caused by the heal-toe effect.
Extensive modelling and simulation work has been previously performed analysing the impact of formation damage and well cleanup in horizontal wells. This paper extends that work to advanced completions employing Interval Control Valves (ICVs) and Inflow Control Devices (ICDs). It reports a comparative study that illustrates the greater cleanup efficiency of advanced, long horizontal well completions over that achieved by the equivalent, conventional, openhole completion.
The highest cleanup efficiency is predicted to be achieved by an intelligent completion employing both sensors and ICVs. The well's full production potential will only be realised if a proper, real-time, cleanup monitoring and control procedure is implemented to optimise the choking strategy. Only then will the near wellbore cleanup efficiency be maximised. A dynamic well simulator has been used to illustrate the advantages of employing such a proper, real-time, cleanup monitoring and choke control strategy. This only becomes possible if an intelligent completion is employed. Sensitivity analysis is used to illustrate how an ICV completion gave the highest cleanup efficiency for almost all the parameters studied.
The single zone cleanup strategy employed by an intelligent completion requires that extra time be spent on the initial stages of the cleanup process. Guidelines are required to ensure economic as well as technical optimisation of the cleanup process. This can be achieved by use of the presented, practical downhole monitoring procedures for efficient well cleanup together with a novel procedure for identifying the time when the near wellbore region is sufficiently clean.
Advanced Well Flow Control Technologies can Improve Well Cleanup
Authors: Al-Khelaiwi F. T. , Muradov K. M. , Davies D. R. , Olowoleru D. K. 
Published: May 2009

Abstract
Formation damage created during drilling or workover operations significantly reduces the performance of many wells. Long, horizontal and multilateral wells crossing heterogeneous, possibly multiple, reservoirs often show greater formation damage than conventional wells. This is partly due to the longer exposure of the formation to the drilling and completion fluid due to the well geometry as well as to the greater overbalance pressure often applied during drilling such wells and poorer cleanup.
The typical well clean up process involves flowing the well naturally or aided by artificial lift to remove the external and internal mudcake and flow-back the mud filtrate. This process can be effective in conventional wells but is not adequate in long horizontal and multilateral wells suffering from increased frictional pressure drop along the wellbore and heterogeneity. The cleanup efficiency is improved by employing Advanced Well completions. Inflow Control Valves (ICVs) control the contribution from individual laterals or a specific zone along the extended horizontal wellbore. Inflow Control Devices (ICDs) equalise the contribution along the (long) completion length. In addition, Autonomous ICDs can manage the influx of unwanted fluids.
This paper studies the cleanup performance of such wells completed with these advanced, downhole flow control technologies. It provides valuable insights into how these completions improve the well cleanup process and compares the ability of (A)ICD and ICV technologies to provide the optimum: Drawdown to lift off the filter cake formed by different mud systems (without causing sand production).Recovery rate of the invaded mud filtrate.
Guidelines for Advanced Well Completion cleanup along with simulated results of synthetic and real field cases are included.
Water Shut-Off in a Fractured System Using a Robust Polymer Gel
Authors: Simjoo M. , Koohi A. Dadvand , Vafaie-Sefti M. , Zitha P. L. J. 
Published: May 2009

Abstract
A common problem during the lifetime of oil and gas producing wells is the surge of the water-cut. High water-cut leads to poor economics due to oil productivity losse and increased water handling and operational cost. A widely used chemical water shut-off method relies on gelling systems consisting of a water soluble polymer and a crosslinking agent. This paper reports an experimental study of the shut-off water flow in fractured carbonate system using a polymer gel consisting of a copolymer of acrylamide-sodium acrylate crosslinked with chromium acetate. The experimental study consists of two parts: (a) the rheological characterization of the gel in presence of high salinity formation water (total dissolved solid of 172,000 ppm) and (b) core flood experiments using a length-wise artificially fractured limestone core (fracture width of 1 mm). From the rheological experiments, it was found that the gel system made with high saline formation water is stable at high temperatures (at 85 °C) for 4 days. More crssolinking of polymer chains occurred in presence of formation water. The core flow experiments revealed that gel is strongly blocking agent reducing the fracture conductivity by four orders of magnitude.