bluuebunny/crossref_metadata_2025 huggingface dataset:
Megacolon and arthritis
Authors: Bazsó Anna , Sevcic Krisztina , Orbán Ilonka , Poór Gyula , Kiss Emese , Balogh Zsolt
Published: May 2009

A szerzők jelen munkában négy juvenilis betegük esetét mutatják be, akiknél a krónikus ízületi gyulladást kísérő megacolont észleltek. A két betegség lefolyását és egymással való (feltehetőleg patogenetikai) kapcsolatát ismertetik, felhívva a figyelmet arra, hogy nem véletlen társulásról lehet szó. A mozgásszervi klinikai kép alapján mind a négy eset a szeronegatív spondylarthritisek csoportjába sorolható. A hasi statust illetően fizikális vizsgálattal minden alkalommal a bal oldali iliacalis régióban masszív rezisztenciát, nagy mennyiségű scibalakkal telített megacolont észleltek. A megacolon egy esetben bizonyult valódi Hirschprung-betegségnek, műtéti megoldására egy esetben került sor, amely egyúttal az arthritis remisszióját is eredményezte. A többi betegnél a krónikus obstipáció, megacolon továbbra is megoldásra vár.
Ki-67 – new faces of an old player
Authors: Bubán Tamás , Tóth László , Tanyi Miklós , Kappelmayer János , Antal-Szalmás Péter
Published: May 2009

Huszonöt évvel ezelőtt izolálták először a Ki-67 fehérjét, ami napjainkra az osztódó sejtek első számú hisztológiai markere lett. Ez a kivételes szerkezetű molekula olyan alapvető biológiai funkciókkal bír, amelyek nélkülözhetetlenek a normális sejtciklushoz. Miután a Ki-67 fehérje minden osztódó sejtben (G1, S, G2/M fázis) jelen van, de a nyugvó sejtekből (G0 fázis) hiányzik, kiválóan alkalmazható az osztódó sejtfrakció kimutatására, ezáltal klinikai jelentőséggel is bír különböző tumoros folyamatok malignitásának megállapításában, a terápiára adott válasz megítélésében. A sejtproliferációban betöltött nélkülözhetetlen funkciói alapján felvetődik a tumorgenezisben is lehetséges szerepe. A szerzők munkájukban áttekintik a fehérje történetét, tulajdonságait, lehetséges szerepeit a sejtciklus szabályozásában és prognosztikai jelentőségét különböző tumoros betegségekben.
Use of Ice-Water and Salt Treatments to Eliminate an Exotic Snail, the Red-Rim Melania, from Small Immersible Fisheries Equipment
Authors: Mitchell Andrew J. , Brandt Thomas M.
Published: May 2009

Ice-water and salt treatments were evaluated for disinfection of small immersible fisheries equipment contaminated with a nonindigenous tropical snail, the red-rim melania Melanoides tuberculatus. This introduced species can displace native snails and transmit trematodes directly to fish and indirectly to other animals, including humans. The red-rim melania has a well-developed operculum that protects it from desiccation and allows it to remain viable for days on dry fisheries equipment. Treatments were produced by adding 10 kg of salt and 33.3 kg of ice to 66.6 L of water (salt–ice-water [SIW]) or by adding 40 kg of ice to 32 L of water (ice-water only [IW]) and were tested for various periods (0.17 min to 24 h) to find exposures that would kill 100% of the treated snails. Temperatures produced in the test containers ranged from −6.3°C to −2.4°C for SIW and from 0°C to 4.9°C for IW. The survival of snails in saltwater-only (SW) treatments (10 kg of NaCl in 100 L of water) was also tested. Three size-groups of snails were tested: 2–4-, 15–20-, and 30–40-mm shell heights. Exposure periods that resulted in an estimated 0% survival for the 15–20-mm snails were 35.8 min for SIW, 179.6 min for IW, and 423.6 min for SW. The calculated amounts of time (regression analysis) required to kill 100% of the three size-groups of snails exposed to the SIW treatment were 17.8 min for 30–40-mm snails, 35.8 min for 15–20-mm snails, and 67.5 min for 2–4-mm snails.
A New Technique to Enhance Cement Resistance to Mud Acids
Authors: Al-Taq Ali A. , Nasr-El-Din Hisham A. , Al-Shafei Tawfiq A.
Published: May 2009

Cement attack by acids during acid stimulation is a serious problem as indicated by both field experience and lab tests. A new cost effective technique was developed to enhance cement resistance to full strength mud acid. This technique will not only protect cement from acid attack, but will also prevent side problems, such as released iron (III) that may damage the formation around the wellbore area

The new technique includes preflushing the cement in the wellbore area (bridge plugs and cement behind casing) with 10 wt% acetic acid + 1.5 wt% HF prior to mud acid stimulation. This preflush will provide a protective layer on the surface of set cement that will minimize acid/cement interactions.

Lab results showed that the new technique significantly reduced the weigh loss experienced by neat cement exposed to a full strength mud acid by 16-fold. Moreover, it was more effective in reducing acid attack on cement than acid resistant cements (latex and latex-expanding).
Induced Sulfur Deposition During Carbon Dioxide Miscible Flooding in Carbonate Reservoirs
Authors: Shedid Shedid A. , Zekri Abdulrazag Y. , Almehaideb Reyadh
Published: May 2009

The existence of sulfur compounds in crude oils decreases their economical value and creates many problems of sulfur deposition in the vicinity of a wellbore hole, in well completion and/or production equipment, and in producing reservoir rocks. Laboratory testing of carbonate reservoirs containing sulfur and asphaltene shows that carbon dioxide flooding is likely to be more efficient if these reservoirs have permeabilities near 10 md than higher levels. Furthermore, faster production rates are likely to reduce displacement efficiency as the contaminants deposit in porous medium and increase damage. Likewise, crude oil viscosity increases with increase of sulfur and asphaltene contents for different temperatures.

Eight core flooding experiments were conducted using multiple flow rates, and reservoir rock permeabilities. All runs were conducted at secondary mode (no water flooding) using carbon dioxide slug size of 15 % hydrocarbon pore volume (HCPV). Three other runs using different initial oil saturations were also performed to study the effect of mobile oil saturation. Our results suggest that application of CO2 flooding to these reservoirs could exacerbate damage to the reservoir porous rocks.
Unlocking Hidden Reservoir Potential Through Integrated Formation Damage Evaluation
Authors: McPhee C. A. , Byrne M.
Published: May 2009

Formation damage during drilling and completion has often led to poor well test results and, in many cases, the wrong conclusions have been drawn. Poor productivity has been mistaken for poor permeability and connectivity. Reservoir potential has been hidden and assets abandoned.

However, the recognition of formation damage in unwanted assets has led to the re-evaluation of legacy drilling and production data. Two examples are presented which demonstrate the methodologies and techniques employed in an integrated solution for the recognition, diagnosis and mitigation of formation damage. In particular, return permeability tests on core in the laboratory are essential but must be coupled with a more rigorous validation of well test interpretations before reaching any decision on relinquishment or abandonment.

An integrated petrophysical, geomechanical and formation evaluation strategy can open up significant development opportunities in what were regarded as uneconomic oil and gas fields. In one case, the methodology resulted in a ten-fold increase in absolute well flow potential and the commercial development of the field.

The methodologies and workflows developed in these field examples mean that it is possible to drill and develop low permeability reservoirs economically without causing damage and avoiding the need for expensive stimulation through careful planning and design.
Evaluation of Reservoir Performance under Water Injection Considering the Effect of Inorganic Scale Deposition in an Iranian Carbonate Oil Reservoir
Authors: Taheri A. , Zahedzadeh M. , Masoudi Rahim , Alikhani F. , Roayaei E. , Ghanavati M.
Published: May 2009

Water injection is one of the main oil recovery techniques, which usually associated with problematic and challenging formation damage concerns including mineral scale deposition, organic scale, clay swelling, particle invasion, fine migration and microbial damage. These concerns usually significantly affect the performance of water injection scenarios by reduction of production rate and therefore ultimate recovery.

In this work, mineral scale deposition phenomenon due to sea water injection and its influence on productivity loss and the reservoir performance of an Iranian offshore carbonate oil reservoir have been investigated. This filed has been producing by water injection since 1985. During these years the field has facing several formation damages mechanisms especially mineral scale deposition. For this purpose, a simulation study using solid deposition module of Eclipse 100 (v. 2006) has been conducted to simulate various phenomena occurring in the reservoir due to water injection, which undermines the oil production rate. As input of the simulation, the actual amount and concentrations of scale formed due to mixing of various portions of formation and injected sea waters and the productivity index reduction due to injection of different water mixtures are needed. These data must be experimentally measured in an actual bulk and core media for the studied reservoir. Comprehensive laboratory studies have been, therefore, conducted to obtain the simulation required information. These data have been incorporated into the simulation model to evaluate the scale deposition effects.

The simulator enables to model the mixing zone, mineral scales precipitation, reservoir performance and productivity index reduction due to sea water injection process. The results show that the production loss due to scale deposition can be predicted/simulated reliably by using the applied methodology and appropriate required experimental works.
Underbalanced Drilling in a Highly Depleted Reservoir, Onshore South Australia: Technical and Operational Challenges
Authors: Vonthethoff M. L. , Schoemaker S. , Telesford A. L.
Published: May 2009

The Moomba field was first discovered in 1966 in the Cooper Basin, South Australia with first production commencing in 1969. From inception, the gas wells were drilled conventionally overbalanced with the majority of wells fracture stimulated to optimise production from the tight inter-bedded gas sands. Today the reservoir is highly depleted and conventional methods of accessing reserves are no longer viable over most areas of the field. Santos Ltd. investigated the application of new technology to accelerate the remaining reserves while avoiding formation damage and optimising potential production rates. Coiled Tubing Underbalanced Drilling was identified as a potential enabling technology for this application and 3 sidetracks from existing depleted wells and 2 new wells were drilled in the field in early 2007.

This paper will discuss the planning, implementation and post drilling analysis of the campaign. The paper will also discuss the technical challenges encountered due to the high pressure depletion, complex geology of the reservoir, hostile drilling environment and remote location.

Of the five wells drilled, four produced with increased rates when compared to modelling with a physically recorded zero skin on all wells. One of the two new wells achieved production rates not seen in the field for over 20 years. Overall, the campaign showed it was technically viable to drill wells in a geologically complex, depleted, tight gas field without damaging the reservoir. The paper concludes with a detailed discussion of how the degree of success achieved is reliant upon the selection of the right technology with a comprehensive understanding of the reservoir and its physical properties. In addition candidate selection is illustrated to be a critical element in achieving projects goals.
Modeling Formation Damage for Flow Simulations at Reservoir Scale
Authors: Ding D. Y.
Published: May 2009

Formation damage is generally limited in the immediate near-wellbore region and needs a particular near-well flow modeling using fine gridblocks. However, near-well models are usually developed standalone and are decoupled from reservoir models. Using a standalone near-well model, which does not take into account production scenarios, cannot correctly predict well injectivity or productivity.

In this paper, we propose a new technique for the coupled modeling of the near-well flow model and the reservoir model in a simple and consistent way. In this new approach, data are exchanged and updated through boundary conditions for the near-well model and numerical productivity index (PI) (or skin factors) for the reservoir model. Examples show that this coupled modeling gives quite satisfying results.
How to Apply the Flow Velocity as a Design Criteria in RPM Treatments
Authors: Stavland Arne
Published: May 2009

The effect of water control using Relative Permeability Modification (RPM) depends strongly on the well's flow rate. This is because the permeability reduction decreases as the flow velocity increases. This will affect the amount of volume as well as the properties of the injected RPM fluid. This paper discusses how the velocity dependent permeability reduction can be accounted for in the job design. The approach is to introduce a velocity dependent permeability reduction and to solve the Darcy law for Non-Newtonian flow.

Core flood experiments report permeability reduction as residual resistance factors (RRFw and RRFo). In scaling up to field situations the reduction in productivity is a better measure. Designing an RPM treatment to a fixed reduction in water productivity demonstrated that low volume - high permeability reduction is better than larger volumes with lower permeability reduction. In high productive wells there may be situations where certain RPM systems fail to reduce the water productivity adequately. By including pressure constraints on the injection of the RPM fluid, the planned pumping schedule is derived.

The criteria for increased oil production are reported as a balance between the increased drawdown, based on the water-cut reduction and improved lift, and the reduction in oil productivity. The critical oil productivity depends on the water productivity, initial water-cut, density difference between the water and the hydrocarbon phase, and depth (TVD). It is clearly demonstrated that the potential for increased oil production increases by increasing the ratio between the oil and the water productivity reduction (M). In addition, M increases as RRFw increases and the volume decreases.

The time to restore the productivity from the oil zone, the clean up time, can be understood based on the fractional flow theory. In theory, the clean up time can be derived from relative permeability curves or the saturation profiles during the oil back production. Also the clean up time was reduced by the use of low volume - high water permeability reduction.
Investigation of Cleanup Efficiency of Hydraulically Fractured Wells in Gas Condensate Reservoirs
Authors: Ghahri P. , Jamiolahmady M. , Sohrabi M.
Published: May 2009

In tight gas reservoirs, gas well production after hydraulic fracturing (HF) is often greatly impaired, through various mechanisms by invasion of fracturing fluid (FF) into the matrix and fracture and poor cleanup efficiency. In the last four decades, fracture face damage and fracture conductivity impairment has been considered as the main sources of such poor performance albeit with conflicting reports on the relative significance of these two effects. Furthermore, there are still several important issues, which have been either overlooked or not properly addressed in this process.

The scope of this study is to investigate the performance of cleanup efficiency in gas and gas condensate reservoir during HF. A single-well model was constructed using ECLIPSE300 compositional numerical simulator to conduct a comprehensive sensitivity study on pertinent parameters. The effect of FF depth of invasion and its negative impact on the fracture permeability (kf), matrix permeability and that of capillary pressure (Pcm), pressure drawdown, initial water saturation (Swi), FF mobility and hysteresis on the gas production from two tight rocks were investigated.

We have been able to reproduce the simulation results reported by previous investigators. However, our results demonstrated that when a more realistic FF depth of invasion into the fracture and matrix, as proposed here, was simulated the reported severe reduction in the gas production, during some of HF operations, was observed in our simulation study. Pcm increased the negative impact of FF invasion into the formation over that of the reduction in kf. If Pcm of the invaded zone was reduced using surfactants, back flow of FF improved, which impaired the out flow of gas for sometime. The negative impact of permeability reduction of the matrix invaded zone is more pronounced for the case with Swi. The improved mobility of FF and presence of condensate improved the FF recovery. These results, which verify the real causes of an ineffective cleanup, can be used for an improved planning of HF operations.
VES: An Alternative to Biopolymers in Reservoir Drill-In Fluids
Authors: Ravitz Ray , Moore LaTosha , Lu Shawn
Published: May 2009

A novel reservoir drill-in fluid (RDF) has been developed that utilizes viscoelastic surfactants (VES) as the primary viscosifier and as a consequence, eliminates the need to use biopolymers for viscosity. Biopolymers have been the standard RDF viscosifier for a long time. They provide stable rheological properties required for drilling and completing the reservoir section, but they have been difficult to remove as very few chemical breakers can effectively destroy the polymer chain. The VES-based viscosifier can be easily removed by a variety of non-aqueous materials, including produced hydrocarbons making this new RDF a viable alternative for a variety of openhole completion projects, particularly low-temperature and injector applications.

This new VES-based RDF system not only suspends soluble bridging material, but supplies the rheological properties necessary to transport cuttings out from the wellbore. Fluid-loss control is achieved with a novel polysaccharide starch that is compatible with the surfactant used in the system. With the addition of this particular starch, the VES-based RDF exhibits similar characteristics to a biopolymer-based RDF which also utilizes polysaccharides and soluble bridging agents, and is stable enough to withstand conventional water-based RDF contaminants.

This paper will detail the laboratory phase involved in the development of this new system. The testing confirmed that the properties normally associated with conventional biopolymer-based RDF systems are also achieved with this innovative VES RDF system. Additional testing revealed solids contamination effects and the effect that the addition of lubricants had on this unique system. Further investigation will also show the effect of a water-based filter cake breaker system currently being used in completion operations. Results of return permeability testing will also be discussed in this paper.

The development of this new RDF system showed that VES technology currently being applied in other aspects in oil and gas completion operations can now be applied in drilling the reservoir, and that this unique system can achieve the same functionality as conventional water-based RDF without the use of biopolymers.
Successful Modelling of Post-Fracture Cleanup in a Layered Tight Gas Reservoir
Authors: Shaoul Josef R. , de Koning Johan , Chapuis Christian , Rochon Jean
Published: May 2009

The issue of filtrate cleanup in tight-gas wells following a hydraulic fracture treatment has long been a topic of discussion in the industry. At one extreme, there is the possibility of a "water block" in which filtrate fluid prevents gas production completely. In other cases, filtrate recovery can vary over a wide range, but without apparent effect on the post-fracture production. This paper describes history matching performed on a hydraulically fractured tight gas well. Fracture growth simulations were performed with a 3D fracture model, using data from a permanent bottomhole gauge for a mini-frac and propped fracture treatment. Net pressure matching during both pumping and shut-in, based on bottomhole gauge data, gave insight into fracture geometry and resulted in two different interpretations of the net pressure data. The two different net pressure matches gave propped length estimates that varied by a factor of two. A new tool automatically generated a reservoir simulator input deck with an explicit gridded representation of the fracture for both of these cases. The model generated includes all the information needed to simulate the initial post-fracture cleanup, including the filtrate invasion profile calculated by the fracture growth model.

This reservoir simulator input deck was used to history match the measured post-fracture production test data (gas rate, water rate, bottomhole pressure). To perform the match, permeability and capillary pressure curves were adjusted for the filtrate-invaded zone and for the reservoir. Initial values for the permeability came from welltest and core results, which had given very different kh estimates. The regained permeability of the proppant pack also had to be adjusted. A reasonable match of the bottomhole pressure and the water rate during the cleanup period was obtained. The history match was good enough to allow forecast runs to be made with the same model, taking into account realistic capillary pressure behavior for the fracture fluid filtrate in the formation. These forecast simulations gave useful insights into the impact of a delayed cleanup on the longterm production behavior of a tight gas well.
Integrated Evaluation of Water Phase Trapping Damage Potential in Tight Gas Reservoirs
Authors: You Lijun , Kang Yili
Published: May 2009

Water phase trapping is the most vital damage to tight sandstone reservoirs, which is different from water blocking, and it is a key barrier to improve resource assessment, successful exploration and efficient development operations. It cannot be evaluated by the traditional method evaluating water blocking. This paper takes example from Daniudi tight gas reservoir in northern Ordos Basin, China. The potential tendency to water phase trapping damage is intense by the research on the geology characters such as abnormal low water saturation, pore structure. The severity of water trapping in Daniudi gas filed was proved by the experiments of the effects of water saturation on gas relative permeability, spontaneous imbibition and phase retention of water and dill-in fluids. Based on the influence mechanisms of initial water saturation, reservoir pressure, liquid properties and pore structure on water phase trapping, dimensionless phase trapping coefficient (PTC) was put forward to predict water phase trapping damage potential. The saturation and invasion depth of filtrate varying with time around wellbore were simulated, the results show that when there is no filtrate cake on the well wall the Daniudi gas reservoirs, especially P1x2+3 gas reservoir is prone to be damaged by water trapping to be wrongly evaluated or to be undervalued. In view of the theories and research results, serial measurements to prevent and treat water phase trapping are adopted to protect gas reservoirs and P1x2+3 gas reservoirs was detected to become the major pay formation. The practices of gas formation damage control verified the results of evaluation.
Water Quality and Well Injectivity: Do Residual Oil-in-Water Emulsions Matter?
Authors: Buret S. , Nabzar L. , Jada A.
Published: May 2009

The present work is a part of a thorough and systematic laboratory study of oil-in-water emulsion flow in porous media that we have recently undertaken to investigate the mechanisms of oil droplet retention and its consecutive impact on permeability. One of our main objectives was to see how the in-depth propagation of produced water residual dilute emulsion could impair the permeability during Produced water Reinjection (PWRI). During this casework, we used granular packs of sharp-edged silicon carbide grains and stable and dilute dodecane-in-water emulsions. The flow experiments have been performed under well-controlled conditions and we studied the effect of most of the relevant parameters including flow rate, salinity, droplet size and permeability of the porous medium.

A careful monitoring of the salinity and the jamming ratio allowed us to consider and work separately on the two main mechanisms of droplet capture, i.e. surface capture and straining capture. In a previous paper, we reported on the effect of salinity and flow rate on emulsion flow through porous media where the pore size to droplet size ratio (jamming ratio) was very high, ensuring so, that only droplet capture on pore surface is operative. This paper reports on the impact of salinity and jamming ratio on both mechanisms with the main focus on the induced permeability impairment.

We demonstrated that surface capture could induce significant in-depth permeability losses even at high jamming ratio. The maximum permeability loss reached is very sensitive to salinity and flow rate (shear thinning effect). This maximum is always lower than a limiting value dictated by the surface coverage jamming limit of RSA theory. This limiting value increases while decreasing the jamming ratio according to a simple formula extracted from the Poiseuille's law with a mean hydrodynamic thickness of the deposited layer close to the droplet diameter (monolayer deposition). Regarding the straining capture, we determined a critical jamming ratio value of 7 for this mechanism to occur. Preliminary results using only two jamming ratio values and one flow rate are presented. Compared to surface capture, the results show that straining capture induces more severe plugging with a lower rate of propagation. The lower the jamming ratio, the more severe the plugging and the lower the propagation rate. However, more investigations are still required, notably, using various jamming ratios and flow rates to better characterize this important mechanism.
Tailoring Filtrate Rheology for Invasion Control in Heavy and Light Oil Reservoirs
Authors: Moreno R. B. Z. L. , Bonet E. J. , Waldmann A. T. A. , Martins A. L.
Published: May 2009

The role of filtrate rheological properties on drill in fluid invasion control is mentioned by some authors as alternatives to bridging agents. Extensional viscosities and normal stress differences are some of the rheological properties of a drill in fluid which can provide extra friction in the flow through porous media, thus preventing invasion. Most of these studies present either experimental single phase validation or only include a theoretical and numerical simulation approach.

The present paper intends to add the reservoir engineering's point of view to the design of non-invasive polymeric solids free drill in fluids. An innovative experimental study, including injection experiments and CT scanning evaluation (X-Ray/2D), was carried out to investigate the role of rheology from different polymeric solutions on the invasion of different rocks - fluid reservoir systems.

Tests included two different types of polymer (one viscous and one viscoelastic); two different levels of differential pressure (in order to induce shear and extension governed flows), two levels of resident oil viscosity and different rock surface conditions (hydrophilic and hydrophobic).

Experimental results were evaluated through sensitivity models describing fluid invasion. Relevant insights and guidelines arose from the analysis of invading polymeric fluid behavior against expected shear rates and fluid's flow rates into the porous media as the response of the formation's properties and imposed gradient pressure.

Calculated data and laboratory measured data were compared and discussed in order to identify dominant parameters on drilling fluid invasion's process. Invasion depth, contact time and saturation profiles were carefully analyzed. A comprehensive analysis, based on CT scan images, of the invasion flow patterns (plug or fingering) is detailed and results indicate that viscoelastic properties may prevent invasion in heavy oils.
Formation Damage Reduction in Retrograde Gas Wells With the Use of Systematic Production Rate Changes
Authors: Quintero Luis F. , Klishch R.
Published: May 2009

The use of systematic changes in flow rate in a retrograde gas well can reduce the formation damage caused during drilling or completion. When a formation containing retrograde gas is drilled with water based fluids that are incompatible with the native water, a process of permeability reduction occurs. The same process may occur when the completion fluid is incompatible and the formation is perforated overbalanced. When the well is put on production the near borehole region has a pressure below the dew point of the gas. In this scenario the flow rate turbulent effects may lead to the formation of an emulsion of the precipitated oil and the invading water which cannot be reabsorbed into the gas phase even if pressure is increased by a rate reduction. These emulsion droplets can nevertheless be dislodged mechanically by creating a fatigue effect in the capillary forces that bound them to the pore throats.

This paper describes the production behavior of a retrograde gas well in a consolidated sandstone formation in the Dnieper-Donets basin which was subjected to a series of choke changes in an attempt to reduce skin. Choke sizes ranging from 3 mm to 9 mm were systematically used over a period of 7 months. The theory behind the skin reduction and the selection criteria for the choke changes is presented. Results from the well show a dramatic increase of gas rate of more than 100% over the evaluation period, while wellhead pressure also increased by 33%. The prognosis has been validated by buildup tests.

The technology presented here may be used in wells which have suffered the formation damage described above. It requires almost no capital expenditures and if properly implemented may increase the flow rate and hence the net present value of retrograde gas fields.
New Insights into Application of Foam for Acid Diversion
Authors: Farajzadeh Rouhollah , Andrianov Alexey , Bruining Hans , Zitha Pacelli L. J.
Published: May 2009

Foam is widely used to divert acid or abandon the high permeable layers. In this type of application foam should considerably reduce gas mobility. The nature of the gas and the surfactant may influence foaming behavior and thus the efficiency of the foam. In this paper an experimental study of the behaviorof CO2 and N2 foams in granular porous media using X-ray Computed Tomography is reported. In the experiments gas is forced through natural porous media initially saturated with a surfactant solution, a process known as SurfactantAlternatingGas (SAG). The CO2 was either under sub- or super-critical conditions whereas N2 remained under subcritical conditions in all experiments. Alpha Olefin Sulfonate (AOS) surfactant was used as foaming agent. We found that injection of gas following a slug of surfactant can considerably reduce gas mobility and promote higher liquid recovery at the experimental conditions investigated. Foaming of CO2 builds-up a lower pressure drop over the core at both low and high pressures than N2. Both gases require a certain penetration depth to develop into foam. This length is longer for N2 (larger entrance effect) and increases with growing gas velocity. Moreover, the ultimate liquid recovery by CO2 foam is always lower than by N2 foam. The possible mechanisms explaining the observed differences in foaming behavior of the two gases are discussed in detail.
Skin Free Production Through a New Gravel Pack Completion for Gas
Authors: Trieb Andreas , Philippovich Nikolaus , Überer Wolfgang , Nederlof Eduard , Thomas Florian
Published: May 2009

OMV-AUT is running the Schönkirchen-Reyersdorf and the Tallesbrunn gas storage facilities with capacities of 1.77 respectively 0.3 billion m3 in the Vienna basin. These facilities at depths between 1000 and 1300 meters are former sandstone gas reservoirs operated with traditional external gravel packed (GP) vertical wells. Increasing gas demand and the urge to increase efficiency prompted an effort to adapt the whole system to a state of the art operation by making full use of available technology. This included:

Application of a novel low damage drill-in fluid system Recompleting former inside as outside casing gravel packs Drilling high performance horizontal wells Completing these horizontals with an expandable sand screen (ESS) respectively with a horizontal open hole gravel pack (HOHGP)

During the project, new field quality control procedures were established and laboratory tests run to demonstrate the potential of the mud system. The mud system used had been designed for oil wells, but never before proved for gas storage. Despite many simultaneous changes in parameters, well tests confirm the assumption of substantial gains due to meticulous QC, intense cooperation and modern technology.
Improving Water Injectivity in Barrancas Mature Field with Produced Water Reinjection: A Team Approach
Authors: Cavallaro A. N. , Sitta M. , Torre I. , Palma G. , Lanza E.
Published: May 2009

Produced water reinjection (PWRI) is one of the most usual ways of produced water reuse in mature fields with high water cut. The relationship between water quality and injectivity decline in wells is well known and it is particularly important in mature fields, such as Barrancas, an old field located in Mendoza-Argentina, with more than 40 years of water injection. In this reservoir significant injectivity losses were recorded when fresh water was replaced by produced water in the 90's. Formation Damage mechanism is mainly caused by external cake. Particles are principally, iron sulfide, calcium carbonate, and oil droplets.

Water treatment and injection well chemical stimulation are two important contributions to oil lifting cost at Barrancas. The average water quality is quite good between water treatment plant and wells. In spite of this, injection wells require regular acidic and non acidic stimulations to restore injectivity.

To identify the causes, a team effort combining field experience, chemical and bacteriological analysis, laboratory and on site core flooding test was performed.

Through this work, water quality performance between plant and down hole well at the level of perforated zones was analyzed. Oil and solids chemical dispersants were tested during core experiments to avoid fall of injectiviy.

The experimental study has demonstrated that the use of dispersants could help to maintain water quality stability at the level of case perforations. A pilot in a selected group of wells will be implemented. It is likely to be successful.

Down-hole water quality is a critical parameter as well as the on site evaluation tests. Based on the outcome new experiences and down-hole monitoring tool will be developed.

The final goal is to improve water quality stability at the level of formation, prevent injectivity decline and reduce working pressure.
Recent Developments in the Deposition of Colloidal Asphaltene in Capillary Flow: Experiments and Mesoscopic Simulation
Authors: Wilson Alexander D. , Boek Edo S. , Ladva Hemant K. , Crawshaw John , Padding Johan T.
Published: May 2009

The aggregation and deposition of asphaltenic material in reservoir rock are significant problems in the oil industry and can adversely affect the producibility of a given reservoir. To obtain a fundamental understanding of this phenomenon, we have studied the deposition and aggregation of colloidal asphaltene in capillary flow by experiment and simulation. For the simulation, we have used the stochastic rotation dynamics (SRD) method, in which the solvent hydrodynamics emerge from the collisions between the solvent particles, while the Brownian motion emerges naturally from the interactions between the colloidal asphaltene particles and the solvent.

We compare our simulation results with flow experiments in glass capillaries where we use extracted asphaltenes only in toluene, re-precipitated with n-Heptane and also asphaltenes precipitated from the whole oil. In the experiments, the asphaltene precipitation and deposition dynamics were monitored in a slot capillary using optical microscopy under flow conditions similar to those used in the simulation.

Maintaining a constant flow rate of 5μL/min, we found that the pressure drop across the capillary first increased slowly, followed by a sharp increase, corresponding to a complete local blockage of the capillary. Subsequently the pressure fell sharply as asphaltenes were re-entrained. This condition was confirmed by the visual observations that showed the slow buildup of asphaltenes deposit followed by the sudden erosion of a channel through the deposit at the time when the pressure suddenly decreased.

We calculate the change in the dimensionless permeability as a function of time for both experiment and simulation. By matching the experimental and simulation results, we obtain information about 1) the interaction potential well depth for the particular asphaltenes used in the experiments, and 2) the flow conditions associated with the asphaltene deposition process. The data obtained will also be used as input parameters for a deep-bed filtration model.
Gas Condensate Productivity Improvement by Chemical Wettability Alteration
Authors: Delavarmoghaddam A. , Mirhaj S. A. , Zitha P. L. J.
Published: May 2009

Gas condensate reservoirs with a bottom-hole flowing pressure (BHFP) below the dew point pressure (DPP) suffer from productivity loss of both gas and condensate due to the accumulation of condensate in the near the wellbore. Methods used to restore the productivity, including solvent treatment and hydraulic fracturing, suffer from various limitations and may be effective only temporarily. A recently proposed method to restore well productivity in retrograde condensate wells is chemical wettability alteration in the near-wellbore zone using adsorbed polymers or surfactants. In this paper the gas condensate studies are critically reviewed and the potential of wettability alteration evaluated using reservoir simulations. Radial flow in a prototypical gas condensate reservoir is simulated using the compositional simulator GEM of the CMG suite. The simulations are done in two parts: first several years of production without chemical treatment are considered. Then a new relative permeability set is defined for the treated area around the wellbore. The modified relative permeabilities are developed based on existing experimental studies, by inserting new residual saturations in Honarpour's relative permeability model. A detailed discussion of the assumptions and limitations of this model is offered. The simulation is also run for three different permeabilities. High permeable rocks show smaller amount of condensate trapping in the models run. The flow rate is higher in treated reservoirs due to smaller residual liquid saturation.
Formation Damage and Well Productivity Simulation
Authors: Lohne Arild , Han Liqun , van der Zwaag Claas , van Velzen Hans , Mathisen Anne-Mette , Twynam Allan , Hendriks Wim , Bulgachev Roman , Hatzignatiou Dimitrios G.
Published: May 2009

In this paper we describe a simulation model for computing the formation damage imposed on the formation during overbalanced drilling. The main parts modelled are filter cake build-up under both static and dynamic conditions, fluid loss to the formation, transport of solids and polymers inside the formation including effects of pore lining retention and pore throat plugging, and salinity effects on fines stability and clay swelling. The developed model can handle multi-component water-based mud systems at both the core scale (linear model) and the field scale (2D radial model). Among the computed results are fluid-loss versus time, internal damage distribution and productivity calculations for both the entire well and individual sections.

The simulation model works in part independent on fluid loss experiments, e.g., we do not use fluid leakoff coefficients, but instead we compute the filter cake buildup and its flow resistance from properties ascribed to the individual components in the mud. Some of these properties can be measured directly, such as particle size distribution of solids, effect of polymers on fluid viscosity and formation permeability and porosity. Other properties, which must be determined by tuning the results of the numerical model against fluid loss experiments, are still assumed to be rather case independent, and once determined they can be used in simulations at altered conditions as well as with different mud formulations. A detailed description of the filter cake model is given in the paper.

We present simulations of several static and dynamic fluid loss experiments. The particle transport model is used to simulate a dilute particle injection experiment taken from the literature. Finally, we demonstrate the model's applicability at the field scale and present computational results from an actual well drilled in the North Sea. These results are analysed and it is concluded that the potential impact of the mechanistic modelling approach used is (a) increased understanding of damage mechanisms, (b) improved design of experiments used in the selection process and (c) better predictions at the well scale. This allows for a more efficient and more realistic pre-screening of drilling fluids than traditional core plug testing.
Sand Control Screen Erosion – When Are You at Risk?
Authors: Gillespie George , Jones Colin
Published: May 2009

For Stand Alone Screen (SAS) completions in open hole oil/gas wells, the sand control screen must retain the formation sand effectively, and provide a conduit for fluids to flow into a producing well. The screen's performance and service life depends on the well's operating conditions. A failure may occur while completing the well, or at some time during the well's operating life. The root cause of the screen failure is often difficult to determine with absolute accuracy. Often, it is determined that screen failure occurs due to a combination of plugging and erosion resulting in the loss of sand control.

A comprehensive test program was undertaken over a two year period to evaluate erosion of different screen types for open hole completions. Completions were simulated for wire wrap and metal mesh sand screens commonly used in open hole completions.

Configurations of each screen type were installed in a test fixture, and several tests were conducted at different velocities and sand concentrations. The sand was sized to pass through the screen with minimal plugging, which would simulate fines production over time in a producing well. The specific wear rates and per cent of rate loss were determined for each test. Micro photos were used in the analysis of the wear patterns, along with pre and post test measurements of the wire wrap slots or metal mesh pore sizes.

This paper will describe the test methods used, the test results and lessons learned, and will describe a model that can be used to predict a screen's service life based on a given set of well conditions in a SAS open hole completion.
Combining the Prediction of Penetration Depth of Downhole Perforators with the Depth of Invasion
Authors: Gladkikh Mikhail , LeCompte Brian , Harvey William , Makarov Alexander , Antonov Yuriy , Halleck Phillip M.
Published: May 2009

Formation fluids are displaced by drilling mud filtrate as a result of pressure overbalance during drilling. This process changes the petrophysical properties of the near-wellbore zone and creates an invasion zone that has a complex radial profile characterized by the partially decreased porosity, permeability, and altered saturations. Further, at the completion stage the well is cased, cemented, and then perforated to re-establish connection between wellbore and reservoir. During perforation, a shaped charge produces a jet of dense material traveling at very high velocity which penetrates casing, cement, and formation. The resulting tunnel is a rugose tapered cylinder roughly characterized by its diameter and total depth of penetration.

One of the main goals of perforated completion is to ensure fluid flow from the productive reservoir interval to the wellbore. Equally important is the ability of the jet to penetrate beyond the zone of formation damage caused by drilling, connecting the wellbore to the virgin reservoir and alleviating the effect of formation damage on production. The ability to predict the invasion depth and the depth of penetration of downhole perforators is therefore critical for pre-job completion modeling.

This work presents the results of numerical modeling predictions of both drilling mud filtrate invasion during drilling and jet penetration in rock during perforation. The invasion model is further applied to the well data interpretation, and a good agreement with log resistivity profile is shown. In addition, we review and discuss various empirical methods currently used in the industry to predict penetration depth. Despite a variety of available methods and published experimental data, penetration depth results are often inconsistent with each other and are of questionable use in predicting actual downhole penetration.

We highlight the importance of combining accurate invasion and penetration models for the successful pre-job completion planning. The results should be used further with the well-inflow model to maximize well productivity and minimize the effect of formation damage.
Computing True Formation Pressure Using Drilling and Logging Data
Authors: Antonov Yuriy , Wu Jianghui , Kashevarov Aleksander , Makarov Alexander , Gladkikh Mikhail
Published: May 2009

In order to ensure well stability, distinguish high- and low- pressure zones and estimate the level of pressure depletion, information about formation pressure is necessary. Due to formation damage during drilling and mud filtrate invasion, true formation pressure can not be measured directly when formation permeability is relatively small. Therefore, an accurate model of invasion profile is required to calculate true formation pressure from formation testing data. This is possible to achieve by combining drilling with LWD and/or wireline logging data.

This paper describes a method of computing depth of invasion by inversion of resistivity logging data. We use resistivity image data to calculate flushed zone resistivity and induction logging data to compute true formation resistivity. This, in turn, provides an invasion zone profile and significantly reduces the ambiguity of possible solutions. Drilling regime, rate of penetration, wellhead pressure, and mud properties are used to calculate wellbore pressure. The changes in formation pressure during drilling are computed by the hydrodynamic model of invasion.

We present the result of formation testing data processing for water-saturated reservoir. The true formation pressure is estimated using the results of inversion, namely, estimate of mud filtrate volume penetrated into formation.