bluuebunny/crossref_metadata_2025 huggingface dataset:
The Challenge of Modelling and Deploying Divertion for Subsea Scale Squeeze Application
Authors: Jordan M. M. , Mackay E. J.
Published: May 2009

Due to the increased cost of scale management in subsea compared to platform or onshore fields, and because of the more limited opportunities for interventions, it is becoming increasingly important to carry out a risk analysis process for scale management as early as possible in the field development plan. A critical part of this process is to evaluate methods of chemical deployment for reservoirs where near wellbore scale has been identified as a significant risk to production – often leading to consideration of the scale squeeze process.

This paper discusses how scale squeeze treatment deployment options can be modelled and demonstrates the comparison of mechanical and chemical diversion (particulate or viscosified fluids) with simple rate diversion. In subsea heterogeneous wells diversion via bullhead deployable treatments can be more cost effective than deployment via a rig and coil tubing, provided the treatment distribution is as effective. The ability to model the application process is critical in the economic assessment of coil/rig vs. fix facility deployment in deepwater fields.

The paper will outline the process of chemical selection, reservoir/near wellbore modeling and field application for solid, viscosified divertors or deployment options where high pump rates are utilized to achieved better chemical placement.

Field treatments where this process has been utilized (North Sea, Brazil and West Africa) will be presented along with the results of these treatments. Practical issues related to overcoming the challenges of subsea flow line cleaning and the effective rates required to achieve diversion are discussed, as are monitoring methods following such treatments to ensure effective placement has been achieved.
Successful Continuous, Multi-Stage, Hydraulic Fracturing Using a Seawater-Based Polymer-Free Fluid System, Executed from a Supply Vessel; Black Sea Offshore
Authors: Bukovac Tomislav , Belhaouas Rafik , Perez Daniel , Dragomir Alexandru , Krilov Zoran
Published: May 2009

Current offshore operations are extremely expensive because of the operational environment and the necessary infrastructure. In this environment, emphasis is placed on high-efficiency operations based on specially tailored solutions combining available resources with new technologies.

To introduce greater efficiencies in offshore operations, a horizontal openhole candidate well was selected to be equipped with a permanent completion system that would enable multiple fracturing treatments. Later, it was determined that by using a novel viscoelastic polymer-free surfactant-based fluid, the entire operation could be performed in a single pumping operation, improving efficiency and adding additional savings to the process.

Because a specialized fracturing vessel tailored for operations in the Black Sea was not available, a supply vessel was used. The vessel had all required fracturing equipment rigged up and secured on decks.

To enable sufficient fracturing fluid volume for placing three propped fracturing treatments in a single pumping operation, a polymer-free fracturing fluid was formulated and mixed with seawater continuously.

This novel multistage fracturing system combined with polymer-free viscoelastic surfactant fluid system prepared with seawater was applied in the World for the first time. Results indicate a sustained increased production.
Optimization of Selective Stimulation Treatments Using Coiled Tubing and Fluidic Oscillator Yields Additional Oil Production from Carbonate Formations in Southern Mexico: Case Studies
Authors: De la Fuente Rodríguez Juan Jose , García Torres Francisco , Gutierrez Joel Vladimir Ulloa , Duverney Eduardo Soriano , Campos Carlos Caballero
Published: May 2009

This paper documents efforts to seek alternative and effective treatments for stimulating wells in southern Mexico. It was desired to make treatments more selective, stimulating only areas of oil without contacting contributing areas of water or gas. Stimulation treatments were performed using coiled tubing (CT) and a fluidic oscillator to generate waves of fluid.

In the southern region of Mexico, the commercial production of hydrocarbons is in reservoirs that are naturally fractured carbonates with permeability of 25–150 mD, porosities of 5–15%, and are depleted as a result of exploitation. Also, the progress of oil-water contact and gas-oil contact present challenges when designing treatments for stimulation.

The damage mechanisms encountered in these wells included blockage by water, paraffin, asphaltenes, and scale depositions, which were generated in the near-wellbore area of the well.

To enhance the effect of the stimulation systems, the fluidic oscillator was used to generate a frequency of impact of 300 to 600 Hz on the formation, weakening the damage and efficiently removing it.

Commonly, in the southern region of Mexico, 90% of the stimulation treatments are bullheaded; however, in highly deviated wells with two or more pay zones, the use of CT with the fluidic oscillator offers an alternative to increase the effectiveness of acid placement.

The synergy of CT, the generation of fluid waves, and the selection system for optimal acid flow through each hole have led to significant results of reduced cost, time, and, in turn, optimizing the volumes of systems required to stimulate wells.

In this paper, results achieved by carrying out selective stimulation treatments as well as technical and economic benefits of using CT and the generation of fluid waves as an alternative stimulation treatment for oil wells are presented.
The Effect of Gas on the Injectivity of Particles in Sandstone
Authors: Nguyen Q. P. , Currie Peter K. , Bouzanga P. S. R.
Published: May 2009

Many operations involve the injection of fluids into the formation around a well. In many cases, the fluids contain colloidal particles, either initially present or introduced during the operation through dirt or naturally-occurring particles. Therefore, all injection schemes potentially suffer from injectivity decline. This injectivity decline is caused by clogging of the formation by particles, forming an external filter cake on the surface of the formation and blocking the pores inside the formation.

This paper reports on the effects of gas on the injectivity of particles in sandstone. Experiments were performed in which water containing micron-sized particles (hematite) was injected into sandstone cores with or without small gas bubbles (nitrogen) present in the water. The position and amount of particle deposition could be determined both visually and by chemical analysis. It was found that the presence of gas reduces the external filter cake formed on the inlet surface of the core. Also, with gas, the particles penetrate deeper inside the core, and more particles pass right through the core and are detected in the effluent stream.

The same effects are enhanced when the mixture of gas bubbles and water is replaced by a foam. This suggests that the presence of gas/water interfaces has a major influence on the retention of particles in the sandstone. Possible mechanisms are discussed.

The pressure drop across the core, when gas or foam is present, is initially higher than in an identical test without gas, because of relative permeability effects or foam flow resistance. But since fewer particles are retained, ultimately the pressure drop is significantly less when gas is present. This effect may be significant in injection operations involving foam and offers ways to mitigate injectivity loss.
Observations on Gas Permeability Measurements under HPHT Conditions in Core Materials Exposed to Cesium Formate Brine
Authors: Downs J. D.
Published: May 2009

Natural gas in its native environment is in thermodynamic equilibrium with the connate liquid water phase and will be saturated with water vapour at reservoir conditions. Full water saturation of gases used in laboratory core flooding tests may not always be achieved, and it is known that the use of dry gas in such experiments can artificially reduce core permeability to gas by dehydrating and crystallising any brine residues left within the cores. This problem of permeability impairment, as a result of water vaporisation by gas, might be expected to become more acute or evident in laboratory tests with high-pressure high-temperature (HPHT) reservoir cores containing high salinity formation brine and high-density completion brine filtrates. These brines may contain salt concentrations that are already close to saturation levels and are more susceptible to crystallisation by dehydration.

The objective of the work described in this paper was to look at the effect of gas humidification levels on the gas permeability of North Sea HPHT reservoir core material exposed to high-density cesium formate brine under HPHT conditions in laboratory core flooding experiments. The results from core flooding experiments at 200°C (392°F) indicated that full HPHT-humidification of the gas phase resulted in a higher gas return permeability when compared with a test using gas humidified at room temperature and high pressure. This finding highlights the importance of ensuring that any gases used in HPHT core flooding tests are fully saturated with water vapour at the test temperature and pressure. It seems likely that the impact of gas humidification levels will be amplified in very low permeability cores subjected to high drawdown pressures.
Wormhole Formation in Carbonates Under Varying Temperature Conditions
Authors: Kalia Nitika , Glasbergen Gerard
Published: May 2009

Matrix stimulation of carbonates involves injecting acid into the wellbore where it reacts with the formation and bypasses the damage. Different types of patterns, like face dissolution, wormhole, and uniform dissolution, are created as a result of the dissolution process. During acid injection, the fluid temperature is typically lower than the formation temperature. As a result, thermal interactions between the fluid and formation occur and lead to retardation of surface reaction rate, decrease in fluid viscosity, and density and increase in diffusivity. Experimental studies of the effect of temperature on wormholing conducted in the past indicated that, depending on the type of acid being injected, a high formation temperature can either aid or impede stimulation. This implies that either a higher or lower total volume of acid might be required to increase the medium permeability. In addition to the temperature difference between the fluid and formation, the fluid-injection rate is also often varied during a single acid job. Therefore, the type of patterns created under lab conditions might not be representative of those formed in the field. Hence, it is not straightforward to design a treatment based on experimental data when flow rate and temperature variations are involved.

In this work, a two-scale continuum model is developed to understand the coupling between flow, reaction, and transport under transient temperature and flow-rate conditions. The effect of fluid temperature on wormholing has been investigated. Specifically, it is shown that injecting a colder fluid in a high-temperature formation leads to a higher wormhole density under laboratory conditions. In addition, it is shown that the acid volume required to achieve a given increase in permeability also depends on the temperature of the injected fluid.

It is important to investigate techniques that enhance hydrocarbon recovery from carbonate reservoirs as more than 50% of the world's current hydrocarbon reserves are present in these formations. The modeling study in this work attempts to answer critical questions pertaining to the effect of temperature variations on stimulation design. In particular, the results from this work can be used to optimize acid volume, flow rates, and acid types in a matrix-acid design.
In Situ Water Blocking Measurements and Interpretation Related to Fracturing Operations in Tight Gas Reservoirs
Authors: Bazin B. , Peysson Y. , Lamy F. , Martin F. , Aubry E. , Chapuis C.
Published: May 2009

Invasion of aqueous drilling, completion or fracturing fluids can reduce the relative permeability to gas and thereby causes a waterblock. In the case of low permeability formations, the capillary pressure tends to be high because of the small pore size. Clean up of water blocks requires high draw down unless water vaporization by the flowing gas is improved by using specific additives like alcohols.

The purpose of this work is to investigate fracture face damage by measuring relevant petrophysical parameters: absolute permeability damage and gas return permeabilities. Measurements are performed in representative conditions of a fracturing operation in a tight gas formation: cores with an absolute permeability of 10 microDarcy set at Swi, experimental pressure of 200 bars for the fracturing fluid invasion. Water and gas saturations during the invasion of the fracturing fluid as well as during the gas back flow are monitored thanks to a XRay equipment. Adding alcohol in the fracturing fluid has a striking effect on resolving the water block. Cake formation on the simulated fracture face is also discussed.

Numerical simulations are performed to assess relative permeabilities from the experimental results. It is shown that the hysteresis of gas and water relative permeabilities has a strong impact on the rate of water removal. Sufficiently high pressure draw down is crucial to overcome capillary forces and initiate alcohol assisted vaporization process. Water removal by water vaporization is assessed and compared to the experimental results.
Case Study:YM204 Obtained High Petroleum Production by Acid Fracture Treatment Combining Fluid Diversion and Fracture Reorientation
Authors: Zhou Fujian , Liu Yuzhang , Liu Xiongfei , Xiong Chunming , Yang Xianyou , Jia Xinfeng , Li Xiangdong , Wang Daobin , Zhang Fuxiang , Shi Hongxiang , Lian Yifeng , Tao Shijun , Qian Chunjiang
Published: May 2009

TARIM is the largest basin abundant in carbonate reservoirs in China. Acid fracturing is the main technology for exploration and development in TARIM carbonate reservoirs, which featured with great depth (4500–7200m), high temperature (250–320F Degrees) and extreme heterogeneity due to fracture formation. If the azimuths of natural fractures and in-situ stress match the azimuth of fracture-and-cavern area from the well, the acid fracturing treatment would generate good effect in general; otherwise, the effect will be non-ideal.

A novel diversion acid fracturing (acidizing) technology, which combines fracture reorientation technology and fluid diversion technology, has been developed to solve the problem. When hydraulic fractures are initiated and extended in unfavorable direction, the fracture reorientation technology utilizing DCF (Degradable Cleaning Fluid, with great block efficiency and high compressive strength) can be adopted to temporarily block the fracture and ensure the hydraulic fracture would reorientate in advantageous direction. DCF is a mixture of TDF (temperature-degradable fibers), which would remain stable at 260 Degrees Fahrenheit while degrade thoroughly at 280 Degrees F, and soluble particles. By using visco-elastic surfactant based self-diversion acid, the fluid diversion technology could achieve deep penetration and efficient acid placement.

Well YM204 has no production before stimulation. The azimuth of maximum principal stress is about NE45 Degrees. FMI data shows that natural fractures in Ordovician carbonate formation are oriented at NW315-SE135 Degrees while there is a fracture-and-cavern area about 150m to the northeast of the wellbore according to the seismic lateral prediction. Thus, acid fracturing treatment combining fracture reorientation technology and fluid diversion technology was conducted in this well. Post-treatment evaluation indicates that the fracture-and-cavern area has been connected to the wellbore and the output remained over 100t/d of oil and 7000m3/d of gas.
Determination of Skin Radius Caused by Drilling Operations in Naturally Fractured Reservoirs
Authors: Zamiri Mehdi , Shadizadeh S. R.
Published: May 2009

Drilling fractured formations by overbalanced method causes lost circulation of drilling fluid in fractures. The lost circulation in drilling fractured zones has been traditionally accepted due to inability to control its occurrence. Most of drilled wells in fractured oil zones after completion are conducted on acid job in order to obtain well flowing. If the radius of skin due to lost circulation of drilling fluid through fractured oil zones be determined, the volume of acid needed to conduct any acid job can be calculated. The main goal of this work is to obtain a mathematical model for determination of skin radius in naturally fractured oil reservoir wells.

In this study, one vertical fracture is assumed to symmetrically intersect a wellbore. During a lost circulation drilling fluid enters the fracture and displaces formation fluid. The mechanism of lost circulation through the modeled porous medium is formulated using mass transfer phenomena. Obtained equations give concentration of the lost fluid with respect to time and position. Filtration of the drilling fluid at walls of the fracture is considered to be exponential which is ceased after mud cake is formed. A simulator is developed using derived equations in this work. The concentration of the drilling fluid could now be plotted against the position in the fracture and also against the position in lateral direction for each point in the fracture at a given time. These curves tend to be S-shaped.

The position in the fracture at which the curve of concentration reaches zero could be considered to represent skin radius caused by drilling operation. Similarly the position in lateral direction at which the concentration reaches zero represents lateral penetration of the drilling fluid in the matrix from its corresponding position in the fracture.
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

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

Optimal 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

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

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 (>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

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

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

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

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

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

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

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

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.
Comparison of Flowback Aids: Understanding Their Capillary Pressure and Wetting Properties
Authors: Howard Paul R. , Mukhopadhyay Sumitra , Moniaga Nita , Schafer Laura , Penny Glenn , Dismuke Keith
Published: May 2009

Flowback aids are usually surfactants or cosolvents added to stimulation treatments to reduce capillary pressure and water blocks. As the gas reservoirs being stimulated become tighter, the perceived value of these additives has grown. This value must be balanced with the cost of the additives, which can be significant in slickwater fracturing treatments. There is a range of different flowback additives containing water-wetting nonionic to amphoteric, microemulsion, and oil-wetting components. Determining the best additive for a specific reservoir is not a simple matter for the end user, and the existing literature is full of conflicting claims as to which one may be most appropriate.

This paper compares four different flowback aids: microemulsion, two water-wetting flowback additives, and an oil-wetting additive. Careful laboratory testing was done to look at surface tension and contact angle for each flowback aid using the recommended concentrations. Imbibition and drainage tests were done, which allowed calculating the capillary pressures for the three additives. Drainage tests were performed on 1–3 and 0.1 mD cores. Capillary tube rise testing was also done as a check of the core flood testing capillary pressures. This provided several different methods to determine capillary forces for the flowback aids. In addition, fluid loss testing was done to determine if the flowback additives could improve fluid loss.

All the flowback aids demonstrated low surface tension (~30 dyne/cm), but each was different in terms of surface wettability and adsorption in the rock. In all cases the flowback aids reduced capillary pressure to similar levels 70% lower than water alone. One of the water-wetting additives had much stronger adsorption in the core material than the other additives. The microemulsion and the oil-wetting additive had improved fluid loss in a fully formulated fracturing fluid. In spite of the low capillary pressures, the additives had little effect on clean-up or return permeability on cores above 1 mD.

There are several implications of these results for the operator. Different flowback additives have a tradeoff of properties, and depending on the reservoir, selecting one that leaves the formation with certain wettability may be advantageous. Our testing indicated that understanding the reservoir is important in selecting the appropriate flowback aid.
New Methodology of Mini-Fall-Off Test to Optimize Hydraulic Fracturing in Unconventional Reservoirs
Authors: Ceccarelli R. L , Ciuca A. , Tambini M.
Published: May 2009

Operative and economical optimization of hydraulic fracture stimulation designs requires accurate reservoir description.

For unconventional tight gas reservoirs is it commonly difficult obtain reliable results from conventional build up analysis after flow testing a well because the time required to reach the IARF (Infinite Acting Radial Flow) could be much longer than normal rig time operations will practically allow. In many cases the impossibility of the well to produce after perforation makes the scenario even worst.

Mini-Fall-Off injection test is economical and efficient technical solution to solve this problem providing an excellent starting point to understand unconventional plays and optimize the entered process of hydraulic fracturing technique.

The scope of this work is to present an optimal operative processes which allow understand how, when and where is recommended apply this technology giving a key point to optimize the hydraulic fracture stimulation. Following a theoretical description to this new methodology is provided.

In addition, this work includes a detailed guideline for planning execution and interpretation of the falloff pressure to obtain reliable reservoir transmissibility, reservoir pressure and closure pressure.

Finally, the results of two cases were evaluated and it was determined that a simple field implementation could be adopted as a standard to be used in conventional pre-frac pumping procedures.
Acid-Fracture Conductivity Correlation Development Based on Acid-Fracture Characterization
Authors: Pournik M. , Zhu D. , Hill A. D.
Published: May 2009

Acid fracturing is a stimulation process in which the dissolution of formation rock leaves unevenly etched fracture faces that creates lasting conductivity after fracture closure. The success of acid fracturing depends on the conductivity created and retained under overburden stress in addition to the length of conductive fracture. In order to have sufficient conductivity after fracture closure, the fracture face must be non-uniformly etched by the acid while the strength of the rock is still maintained at high levels to withstand the closure stress.

A systematic experimental study to investigate the effect of etching pattern and rock strength on the resulting fracture conductivity was conducted in a laboratory facility designed to perform acid fracture conductivity characterization. Detailed etched surface characterization and rock strength measurement were performed on acid etched fracture faces in order to correlate to resulting conductivity.

Resulting fracture conductivities clearly show the importance of characterizing acid etching patterns. In evaluating the measured fracture conductivities, we distinguished between those tests in which a prominent channel was created along the middle of the rock samples from those tests in which more uniformly distributed roughness features were created on the fracture faces. The channels developed in small scale laboratory tests are likely artifacts of the apparatus and cannot be expected to scale to field conditions.

For the roughly etched fracture faces, statistical parameters describing the surface roughness in addition to average fracture width were needed to accurately predict measured conductivities. Both etched pattern characterization and resulting conductivity measurements suggested the need to model conductivity of limestone and dolomite samples separately. New conductivity correlations were developed both for limestone and dolomite formations which matched the experimental results better than previous correlations.