bluuebunny/crossref_metadata_2025 huggingface dataset:
Comparison of the Penetration Rate Models Using Field Data for One of the Gas Fields in Persian Gulf Area
Authors: Rahimzadeh H. , Mostofi M. , Hashemi A. , Salahshoor K.
Published: July 2010

Estimation of the drilling rate of penetration (ROP) has always been a challenge for drilling engineers, since it is the key parameter in drilling optimization. There are many parameters which have significant influence on ROP. Relating penetration rate to these parameters result in defining a model for penetration rate. Hence, several rate of penetration models have been proposed. Among these models, the most well-known ones are Bourgoyne and Young, and Warren's models. In each of these models different parameters have been used to estimate the ROP.

The application of different parameters and their corresponding weights causes the models to predict the ROP with different accuracies. In addition, usage of different assumptions in developing the models results in quiet different areas of application for the two mentioned models. Hence, studying the models' applications and comparison of them would lead to the more successful model recognition.

In this paper, ROP equations are obtained for some depth intervals based on the two mentioned models. For this purpose, drilling data from two wells in one of the Iranian gas fields in Persian Gulf area is used. Based on the resulted equations, the two models are compared and the more suitable equation for future drillings in the same field is proposed.

The result of this study would leads to a large amount of saving in time and money in drilling the new wells. Although one of the models may excel the other one in some cases, it is not true in general. Therefore, some useful recommendations on the usage and application areas of each model will be worked out which leads to low cost drilling, real-time monitoring and optimization, and ROP enhancement.
Experimental Study of Hydraulic Fracturing Caused by Polymer Injection in Unconsolidated Heavy Oil Reservoirs
Authors: Zhou Jian , Dong Yufei , de Pater C. J. , Zitha Pacelli L.
Published: July 2010

Polymer flooding provides a better mobility ratio than water flooding, for a better sweep especially in viscous oil reservoirs that have been under water flood. During polymer injection, larger fractures may be induced compared with water injection. The geometry and propagation behaviours of fractures caused by the injection of viscous fluids in sands under bi-axial stress that simulated unconsolidated formation were studied. The results showed that the geometry of fractures induced by viscous fluids in an unconsolidated formation is a dominantly planar fracture, although it is very tortuous. In view of isotropic stress in the horizontal plane, multiple fractures were induced in several directions. Similar fractures were observed when the injection fluid viscosity was varied by a factor of 3, while keeping the mobility ratio constant. The tests confirm that the injection pressure should exceed the minimum stress by a factor of 2.5 to induce fracture propagation. Below this pressure only matrix flow occurred, although the permeability was enhanced by the injection.
A Review on Utilization of Crosslinked Polymer Gels for Improving Heavy Oil Recovery in Turkey
Authors: Topguder Nazan N.
Published: July 2010

The oil reservoirs in Turkey generally produce from naturally fractured carbonates with high WOR's. This high WOR easily causes rapid decline in oil rates, especially with heavy oil of about 18-20° API. As crosslinked polymer gels are one of the major means to remedy this problem, gels for WOR reduction in oil producers have been applied in TPAO oilfields. Treatments have provided several folds of increase in net oil (from 30 b/d to 120 b/d) production and reduction in WOR from 96-98 % to 30-75%.

Another application of crosslinked polymer gels is conformance control in IOR processes, e.g. CO2 injection, where mobility reduction and improved sweep efficiency is required. Polymer gels provide mobility control by decreasing the permeability of the porous medium, hence CO2 injection pressure is increased and also it is diverted to the previously bypassed zones to recover more incremental oil.

This process is extremely important if the displaced oil is heavy; where that is the case in Bati Raman CO2 injection project of TPAO, which is a well known field project that has been going on for more than twenty years. Crosslinked polymer gels for conformance control have been employed recently in Bati Raman field providing improved sweep efficiency and 12 % increase in net oil recovery.

Field application of polymer gels for water shutoff and conformance improvement have provided both technically and economically successful results in naturally fractured carbonate heavy oil reservoirs in Turkey. The design and field operation process and experience gained from these applications may be very helpful and encouraging for the operators who look for new, reliable and low-cost methods to improve their oil production under today's harsh economic conditions.
Scale Inhibitor Squeeze Treatment Efficiency in Unfractured and Fractured Wells
Authors: Ishkov Oleg , Mackay Eric , Sorbie Ken
Published: July 2010

Deployment of scale inhibitor squeeze treatments generally involves injection of aqueous solutions at pressures higher than the formation pressure and at temperatures lower than the formation temperature. If the pressure and temperature differences are great enough, the pumping activity may lead to the development of fractures in the near-well bore area, if the well has not already been fractured and propped. Therefore, attention needs to be paid to the impact of squeezing fractured wells, unfractured wells, or wells that fracture during the scale inhibitor squeeze treatment.

This paper presents results of using a simulator to model squeeze treatments for these three scenarios. The simulator has the unique combination of being able to model (i) scale inhibitor propagation and retention in the porous medium, (ii) scale squeeze treatments in unfractured or fractured wells, (iii) the mechanics of fracture propagation during a treatment, (iv) the geochemical reactions that may lead to in situ dissolution or precipitation, and (v) the impact of the injected scale inhibitor on these reactions when they occur within the treatment zone.

Parameters considered in this study include locations in the matrix where scaling reactions occur, and fracture geometry and conductivity. If a fracture is created, the timing of this relative to the injection of the main scale inhibitor treatment volume has also been studied and is found to be very important.

Inappropriate placement of scale inhibitor during a squeeze treatment may mean that downhole zones at risk of scale damage are not adequately protected, even although the observed inhibitor concentrations at the wellhead are above the level required for protection. In this work, a new approach is presented also in which we define and measure the "efficiency" of the squeeze treatment based on produced water ion compositions. This approach takes account of whether the scaling reactions would take place in the treated zone (and hence should be impacted by the presence of inhibitor), or whether they would take place deep within the reservoir.
Effect of Gas Type on Foam Film Permeability and Its Implications for Foam Flow in Porous Media
Authors: Farajzadeh R. , Muruganathan R. M. , Krastev R. , Rossen W. R.
Published: July 2010

The ability of foam to control the gas mobility in porous media is determined in part by the trapped (stationary) fraction of foam, Xt. The common approach to determining Xt is to replace some part of the gas by a "tracer gas" during the steady-state stage of the experiments and fitting the effluent data to a capacitance mass-transfer model. Diffusion between bubbles is quantified by the film permeability coefficient, K (cm/s). We measured the film permeability coefficient of different gases for foam films made of four surfactants. The results show that the value of K is largely dependent on the dissolution of gas in the surfactant solution and increases with increasing gas solubility in the bulk liquid. The measured values of K are consistent with rapid diffusion of tracer through trapped gas adjacent to flowing gas in porous media, and difficulties in interpreting the results of tracer-foam experiments with conventional capacitance models. Effective diffusion coefficients of gases through trapped foam can be estimated from K. These diffusion coefficients differ substantially, and this implies swelling or shrinkage of trapped gas from diffusion. The implications of the results for foam flow in porous media is discussed in detail and some suggestions are given to improve the measurements and modeling of trapped fraction of foam.
Improved Oil Recovery in Chalk: Wettability Alteration or Something Else?
Authors: Zahid Adeel , Stenby Erling H. , Shapiro Alexander A.
Published: July 2010

Improved oil recovery from low permeable chalk reservoirs is regarded as a great challenge because of their complexity and heterogeneity. Historically seawater salinity has not been considered as an important factor in determining the amount of oil recovered. Over the last decade, a number of studies have shown that waterflooding performance is dependent on the composition of injecting brine solution. Extensive laboratory research has been carried out in order to understand improved oil recovery from chalk using surfactant solutions and later on using the modified sea water. The researchers suggested wettability alteration towards more water wetting conditions to be the reason for improvement in oil recovery.

In this paper, we are further investigating the reasons of observed improvement in oil recovery with sulphate ions. Is it really wettability alteration or something else also? Most of the previous work has been made on the basis of spontaneous imbibition using core plugs aged in crude oil. Our study is based on flooding and utilizes completely water wet cores without being aged in crude oil, just saturated with crude oil under vacuum. This would exclude alteration of wettability as a positive factor. Brine without sulphate is considered as the base injected fluid. Waterflooding experiments were carried out with brines without sulphate, as well as brines having different concentrations of sulphate. The effect of temperature, injection rate, crude oils and different sulphate concentration on the total oil recovery and the recovery rate was investigated.

In Stevens Klint outcrop chalk samples, 10% increase in oil recovery was observed with sulphate enriched brine flooded core as compared to core flooded with brine without sulphate ions. We observed also 4-6 % increment of OOIP using brine with sulphate for water wet chalk at high temperatures. This clearly indicates improvement in oil recovery without wettability alteration, because chalk is already water wet. No increment in oil recovery was observed at 40 ºC and, neither, in experiments with North Sea crude oil. This clearly explained that crude oil type also plays a significant role in the effect that brine composition has on waterflood oil recovery.

This study will help in getting more in depth understanding of seawater improved oil recovery process for chalk reservoirs.
Comprehensive Pre-Well Preparation and Collaboration Leads to Record Drilling Performance in Challenging Exploration Well in Sichuan
Authors: Lee Roger , Chang George , Bo Li , Wei Zhang , Jin Xu , Qing Zhu Cheng , Xiang Xia Jia
Published: July 2010

China's Sichuan Province contains prolific gas fields and offers many drilling challenges due to the complex structural geolo gy. The interbedded and abrasive nature of the lithology results in slow drilling penetration rates. Additionally, risk of cavings and stuck pipe limits use of fully stabilized BHAs.

Conventional roller cone and PDC bit technologies had been tested and were limited by impact damage and abrasive wear. Offset wells required more than 230 days due to short drilling intervals and subsequent tripping time. The goal set by the operator was to complete drilling a well in the XinChang Gas Field in less than 180 days. The target well would reach 4700 m total vertical depth (TVD) and contain a challenging 2500-m long 9 1/2-in. interval. Improving rates of penetration (ROP) and increasing distance drilled would be essential in this section.

To identify the solution, a cross-functional team from the operator and the service company conducted extensive technical reviews. Proprietary software was used to analyze the rock properties, and formation drillability problems were identified. BHA modeling revealed potential system instability issues and provided methods to mitigate vibrations. Review of offset drill bits provided clues to drilling challenges and helped form realistic drilling expectations. The correct solution incorporated both products and service. A revolutionary PDC drill bit containing wear-resistant cutters and an innovative design replaced multiple bits and extended the interval drilled by over 80% in certain sections. More importantly, drilling ROP increased by 60%. Experienced bit run supervisors monitored the drilling process and provided real-time options for improving performance.

This paper will describe the application analysis and review process, the critical PDC bit technology, and the implementation instrumental in achieving the 180-day drilling completion goal set by the operator.
Fracture Modeling and Application Based on Fracture Mechanics
Authors: Mingming Tang , Jinliang Zhang , Xiaoyu Yu
Published: July 2010

Based on the analysis of fracture classification, controlling factors and distribution characteristic, in this article we established the fracture intelligent recognition system. In the reservoir fracture forecast modeling aspect, we established one one FM2 (fracture modeling based on fracture mechanics) system by combining geological statistics and fracture mechanics. Based on the modern fracture mechanics, has established FM2 system. The model has not only considered the temperature field and strain field coupling effect, and introduces Green Strain tensor in the small distortion analysis. Because of the reservoir existence varying degree's aeolotropies, so in the elastoplasticity stress and strain field simulation, mainly uses kinematics hardening theory. But the fracture distribution also influenced by later period structure change and others kinds of factors. In order to compensate the influence of these factors to facture distribution, the auto-adapted intelligent field control fracture modeling method is first raised in this article. Based on the common field control fracture modeling method, by contrasting the fracture distribution data obtained from micro electrical receptivity well log, modify the boundary condition and modulus by according to the error to make the simulation results achieve the most superior match.
The Inhibition of Gas Hydrates and Synergy of the Inhibiting Molecules
Authors: Guan Hua
Published: July 2010

Gas hydrates have become an increasing problem to the oil and gas industry as the development entering deeper water encounters high-pressure and low-temperature regions. However, the mechanisms and applications of kinetic hydrate inhibitors are less well understood. This paper provides an overview of the performance of common hydrate inhibiting molecules that are currently available and discusses the mechanisms of hydrate inhibition and the synergy of different hydrate inhibiting molecules and therefore provides some guidance in future development on hydrate inhibiting molecules for different gases.

This paper investigates the application of kinetic hydrate inhibitors in three different gases and the synergy between different inhibiting molecules. Several commercially available kinetic hydrate inhibitors have been evaluated in the laboratory using a rocking cell apparatus. Three different gas compositions were used in the performance evaluation. The synergy of different inhibitor molecules has been studied through the evaluation of various mixtures. The field requirement for low viscosity and high cloud point for kinetic hydrate inhibitors have also been studied and discussed. The hydrate dissociation curves for three gases have been modelled and the subcooling potential for each of the products has been calculated.

Following the review and optimisation of the different hydrate inhibiting molecules available in the market, it was found that one of the optimised mixtures has outperformed all the individual hydrate inhibiting molecules and mixtures for all three gases. This suggests synergy between the different hydrate inhibiting molecules; the possible mechanisms are discussed in this paper.
Calibration and Analysis of a Novel Downhole Sensor to Determine Fluid Viscosities
Authors: Rondon Javier , Barrufet Maria A. , Falcone Gioia
Published: July 2010

This paper presents the performance evaluation of a novel sensor designed to measure the in situ the viscosity of a flowing fluid at downhole conditions. The device provides a mechanism to allow the passage of solid particles (i.e. sand) and has a self-cleaning ability should any build-up of these particles restrict the flowing area. The sensor was assembled in a closed flow loop to prevent measurement error due to partial vaporization of the samples at higher temperatures where it was tested and calibrated with mixtures of glycerin and water. Differential pressures, flow rates and temperatures were gathered and used to determine the viscosity of two crude oils with viscosities ranging from 1 to 30 cp and temperatures from 100 to 160 °F. Flow rates were controlled to maintain linearity in the differential pressure response to ensure a laminar flow regime. Viscosity measurements were validated with independent measurements using a Brookfield viscometer and the agreement was within 2%. Using data from this sensor, new viscosity mixing rules were developed to allow determination of mixture compositions from viscosity measurements or mixture viscosities for given compositions. Potential applications include the estimation of diluent to be added to a more viscous fluid to achieve a target viscosity reduction, fluid identification from wireline formation testers, smart well fluid monitoring, enhanced mud logging, and fracture fluid characterization.
Practices of Formation Damage Control for Deep Fractured Tight Gas Reservoir in Western Sichuan Basin
Authors: Yili Kang , Lijun You , Xinghua Xu , Zhonghui Liao
Published: July 2010

Western Sichuan deep tight gas reservoir is characteristic of ultra low permeability, natural fractures developed in heterogeneity, partial ultra low water saturation, hard and brittle shale interlayer. The matrix permeability varies between 0.001mD and 0.1 mD, and the natural fracture width is between 10μm and 2.0mm, while the fracture width can reach up to 5.0mm during the well operations. Lost circulation, inducing severe reservoir damage and increasing non-productive time, happens more frequent. The traditional lost circulation control technologies such as physical, chemical or physicochemical methods, used to permanently chock the lost circulation passage of non pay zone, is not applicable to pay zone. One after another technology such as air underbalanced drilling fluids, non-invasive drill-in fluids and the traditional temporary shielding fluids technology(TSF) were executed for prevention of formation damage duo to lost circulation, but they all do not work well. The air underbalanced drilling has to be given up because of formation water influx and wellbore instability, and non-invasive drill-in fluids does not obtain good results duo to low return permeability rate and low loading pressure ability of filtrate cake in the fractured formation. The traditional temporary shielding fluids technology (TSF) is not competent for the damage prevention of the reservoir with ultra narrow pores and throats. In the light of the special geology and engineering characteristics, a named temporary sealing loss (TSL) fluids with inert particles and acid soluble particles are developed to prevent formation damage in leaky fractured reservoirs. Integrating the advantages of non-invasive fluids and temporary shielding fluids, temporary sealing loss (TSL) technology takes advantage of inert bridging particles and acid soluble filling particles to rapidly form tight plugging zone near the wellbore to seal the throats and fractures effectively. After its application, well X2 and X3 obtain gas production of 52.16×104m3/d and 22.37×104m3/d in 2nd member of Xujiahe formation, respectively.
Innovative Cementing Solution for Long-Term Steam Injection Well Integrity
Authors: DeBruijn G. , Loiseau A. , Chougnet-Sirapian A. , Piot B. , Pershikova E. , Khater W. , Evoy K. , Wilson G.
Published: July 2010

Operators involved in the recovery of hydrocarbons from heavy-oil reservoirs often face the problem of maintaining well integrity in steam-injection wells. A significant portion of these wells suffer various forms of leaks and in the most severe case complete steam breakthrough to surface. Throughout the life of heavy-oil wells, cement material degradation and stresses in the cement sheath induced by extreme temperature cycling result in severe mechanical damage and ultimate failure of the cement sheath. These problems motivate different operators to explore new cementing technologies that are capable of achieving reliable long-term zonal isolation in these extreme conditions.

The main challenge for operators is to design thermally stable cement with mechanical properties sufficient to withstand stresses induced by the large temperature changes. This paper describes the development of a new cement system, which is stable, strong, impermeable and flexible up to a temperature of at least 350°C(650°F), corresponding to the maximum steam injection temperature. Depending on the curing temperature this new cement system provides low Young's modulus of 1,800 to 4,000 MPa while maintaining excellent compressive and tensile strengths compared to cements currently used in the oilfield industry. Aging the cement system for 6 months at steam temperatures demonstrates the stability of the set material properties, including maintaining a low permeability.

Field trials in North America show that this new cement system can be easily implemented into standard cementing operations using conventional equipment. Cement evaluation logs after cement operations confirm that excellent zonal isolation and wellbore integrity are readily achieved.

By keeping adequate strength and flexibility, this new cement system reduces the risk of cement sheath failure and steam migration throughout the life of these steam-injection wells. It provides a long-term well integrity solution for any well exposed to very large temperature increase after the cement initial set, such as in fields exposed to steam temperatures.
Use of Modified Hollow Cylinder Test in Laboratory for Simulation of Downhole Drilling Condition in Shale
Authors: Gabrielsen Glenn K. , Stenebråten Jørn F. , Nes Olav-Magnar , Holt Rune M. , Horsrud Per
Published: July 2010

Several challenges are experienced with wellbores when drilling in shale above and within reservoirs. These are especially prevalent in deviated wells and wells through depleted intervals caused by some years of production.

Drilling the well to total depth of the wellbore section might be easy. However, in some cases depending upon formation properties and drilling conditions it is a big challenge to come out of the hole and subsequently run casing or liner. It is of great importance to take the right actions regarding recommended downhole parameters like mud circulation rate, RPM on drillstring and pulling speed.

Some of the wellbore aspects to discuss are: unstable hole, small margins between mudweight and collapse pressure, what is the right technique to use with the drillstring, flow rates and finally oil based mud versus water based mud. In case of a marginal downhole situation, it would be beneficial to test out some effects in a laboratory beforehand.

Such questions were discussed and became an issue within a joint industry project on borehole stability in shales run at SINTEF Petroleum Research (SPR). A modified test cell was designed and used with the purpose of systematically testing these effects in the laboratory.

This paper describes how this equipment was designed and tested in order to achieve reliable laboratory results as well as results from initial work on outcrop shale. The main objective was to a certain extent to visualize some effects in a laboratory and conclude with some good recommendations regarding drilling procedures on the rig offshore. Thus for testing some of the down hole effects, a long period of qualification tests was gone through. This was important before real tests could be done on shale at simulated downhole condition. Testing was performed on hollow cylinder samples.

The initial results show that it is possible to run such laboratory simulations. It is possible to a certain extent to visualize some of the effects with varying flowrates and RPM on a drillstring with stabilizer. The laboratory tests so far suggest that high RPM on a drillstring can have destabilizing effects on a wellbore through a section with shale that has been exposed to very close to collapse conditions, calling for optimized drilling procedures in situ.
Rotary Steerable System Enhances Drilling Performance on Horizontal Shale Wells
Authors: Sugiura Junichi , Jones Steve
Published: July 2010

In North America, shale gas wells are typically drilled with build rates of 10°–14°/100ft to land, followed by 3000–5000 ft horizontal sections. As more shale plays open up, horizontal sections have been extended to seek more shale exposure. Today, the majority of shale gas wells are drilled using conventional steerable motors, but as horizontal sections get longer, Rotary Steerable Systems (RSS) become a more viable option to reach the target depth.

Standard RSS currently on the market cannot provide sufficient build rates to drill the curve on shale gas well designs. However, as wells step out further, it has become more common to drill the curve with steerable motors and to drill the lateral with RSS. On shale wells where the curve and the lateral are drilled in the same hole size, it would be more efficient to drill the entire well with RSS. Hence, there is a necessity for higher-dogleg RSS for these applications.

This paper describes the development and testing phase of a new 6 ¾-in. RSS that can produce higher build rates than the standard RSS on the market. During testing, the 6 ¾-in. RSS proved to be capable of producing 12°–15°/100 ft in 8 ½-in.- and 8 ¾-in.-hole-size sections. The system was tested under controlled conditions through variable rock strengths to ensure consistent and predictable build rates, as well as fine dogleg control for horizontal sections.

When sufficient test data had been gathered to prove the RSS was fit for purpose, it was then released for initial field testing on shale gas wells in North America.
Simulation, Design and Management of Waterflooding Projects in Mature Multi-Storey Fields in the Golfo San Jorge Basin - Argentina
Authors: Palacios Gustavo Rogelio , Paradiso Antonio Alfredo , Tuero Fernando
Published: July 2010

The Golfo San Jorge Basin in Argentina presents a great challenge to Reservoir Engineers due to its complex reservoir conformance and scarcity and poor quality of petrophysical and fluid data, making the use of conventional numerical simulators non-pragmatic.

This paper presents a simple and effective methodology that through the integration and validation of all the available data, coupled with an ad-hoc developed software tool, permits the construction of an analytical simulation model to design, monitor and forecast future production of waterflood (WF) projects in this type of multi-storey and mature fields.

Additionally, a summary is presented showing interesting results from a large number of studies with the application of the aforementioned methodology during more than 10 years of experience in WF projects assessment.
An Integrated Method for Well Deliverability Forecasting: A Field Example In ShengLi Oilfield
Authors: Yun Xie , Bin Xin Zhong , Sheng Zhou Jia , Jin Wang , Jun Zhang , Khong Chee Kin , Jing Zhou , Qiang Niu Yu , Li Chen
Published: July 2010

Well deliverability is a critical reservoir parameter that defines well performance. Accurate knowledge of deliverability is very important for reserve booking and production facility design. Reliable well deliverability can be obtained from DST (Drill Stem Test) on selective perforation of individual layers and/or straddle tests for commingled producers. However, these methods are both time and cost consuming. Simple single well analytical model can be built to calculate well deliverability. But it often does not count for certain factors such as: formation heterogeneity & anisotropy, initial oil saturation, reservoir with bottom or edge-drive aquifers, as well as capillary force and relative permeability. Therefore the result can be unreliable. Under this situation, numerical model is the solution.

This paper presents a method to forecast well deliverability with a comprehensive approach to factor in various reservoir parameters. A single well numerical model is developed by integrating Nuclear Magnetic Resonance (NMR), borehole image, open-hole logs, well test and/or formation tester, and core data together. The workflow of the method includes four steps: 1) perform petrophysical interpretation and lithofacies characterization and hydraulic flow unit (HFU) classification, 2) calibrate NMR derived permeability, capillary and relative permeability curves with special core analysis, 3) construct a dynamic model and calibrate it with well testing and/or/ formation testing data, and 4) forecast well deliverability with the calibrate numerical model under different completion and well management options.

A case study is presented to illustrate this integrated approach. The single well model was calibrated with well test data for a tested zone, then the calibrated model was used to forecast well deliverability for the rest zones where no well tests were performed. Subsequently sensitivity analysis was performed on formation damage. Also bottom/edge water drive effect on well deliverability were analyzed. This case study shows that the well deliverability forecasted with this workflow has greatly reduced the uncertainty and enhanced the understanding of the reservoir performance for decision making.
Improved Heavy Oil Recovery by CO2 Injection Augmented with Chemicals
Authors: Zhang Y. P. , Luo P. , Huang S.
Published: July 2010

During water-alternating-gas (WAG) flooding for heavy oil reservoirs, the adverse mobility ratio leads to a considerable amount of injection gas fingering through and overriding the oil zone. To improve the recovery efficiency of the WAG process in a Saskatchewan (Canada) heavy oil reservoir, the Saskatchewan Research Council (SRC) conducted a laboratory feasibility study of augmenting the injection water with chemicals (alkaline/surfactant/polymer). The resulting process is known as CAG, or chemical-alternating-gas (CO2 or flue gas). SRC's integrated approach included interfacial tension (IFT) and rheology measurements, phase behaviour studies, micromodel displacements, and corefloods to evaluate the effectiveness of the CAG process. The results showed that addition of ASP into the injection water could significantly lower IFT (to 10−2 mN/m) and improve mobility. The phase behaviour studies indicated that CO2 could be dissolved readily into reservoir heavy oil at moderate pressures (3.4–6.4 MPa), resulting in dramatic oil expansion (1.2–8.1%) and viscosity reduction (45–88%). It was also demonstrated that the presence of 70% N2 in the CO2 stream (i.e., flue gas) greatly reduced the gas solubility, causing negligible oil swelling and viscosity reduction at the reservoir pressure. It was observed from micromodel displacement tests that CO2 viscous fingering and breakthrough occurred quickly even at a low pressure of 2.3 MPa, indicating the need to lower the capillary pressure between the heavy oil and porous media and add a mobility buffer between the CO2 and heavy oil. The coreflood results showed that a conventional CO2-WAG process recovered more incremental oil than a flue gas-WAG (9.43 vs. 3.58% OOIP), whereas a CO2-CAG and a flue gas-CAG recovered incremental oil of 27.43 and 22.07% OOIP, respectively. The comprehensive studies suggest that the CO2-CAG process holds promise for recovering Saskatchewan's tremendous heavy oil resources.
Using Downhole Temperature Measurement to Assist Reservoir Characterization and Optimization
Authors: Li Zhuoyi , Yin Jichao , Zhu Ding , Datta-Gupta Akhil
Published: July 2010

Downhole temperature distribution in horizontal wells can be an important source of information that helps us characterize the reservoir and understand the bottom-hole flow conditions. The temperature measurements are obtained from permanent monitoring systems such as downhole temperature gauges and fiber optic sensors. Also, production history and bottomhole pressures are usually readily available and are routinely used for history matching to improve the initial geological models. Combining the downhole temperature distribution and the production history, we can extract more reliable information about the reservoir permeability distribution and bottomhole flow conditions that help us optimize the wellbore performance, particularly in horizontal wells.

In this paper, we use a thermal model and a transient, 3D, multiphase flow reservoir model to calculate the wellbore temperature distribution in horizontal wells. By comparing the simulated temperature and the observed data, we first derive large-scale permeability trends in the reservoir. These permeability trends are then incorporated as ‘secondary’ information in the geologic model building and history matching. Finally, the updated permeability models from history matching are used to infer the downhole flow conditions along horizontal wells. The final outcome is a geologic model that is consistent with reservoir static and dynamic information, and also the wellbore temperature measurements.

We present several synthetic cases to illustrate the procedure. The results show that with only production history matching without distributed data along the wellbore, the water entry location in horizontal wells can not be detected satisfactorily. Combining production history matching with the temperature distribution in the wellbore, we can get an improved geological model that can match the production history and also, locate the water entry correctly. Based on the downhole flow conditions and the updated geological model, we can now optimize the well performance by controlling the inflow rate distribution, such as shutting the high water inflow sections.
Fracture Permeability of Gas Shale: Effects of Roughness, Fracture Offset, Proppant, and Effective Stress
Authors: Kassis Sarah , Sondergeld Carl H.
Published: July 2010

Domestic gas shale production is made economic through new completion practices which include horizontal wells and multiple hydraulic fractures. The performance of these fractures is improved through the injection of proppant. Success has largely been based on empiricism through field experiments. We attempt to remove some uncertainty in this empiricism through a series of laboratory controlled experiments. We have measured the permeability of fractured rock as a function of effective stress, proppant, proppant distribution and fracture offset. Our findings indicate that fracture offset is as effective as propping a fracture; both increase initial permeabilities more than 1000 fold over initial fracture values. However, the pressure dependence of the propped fracture is stronger, i.e. the permeability is reduced more per increment of pressure than the offset fractures. Neither obeys the simple cubic pressure dependence law proposed by Walsh. A simple monolayer of proppant is as effective as a fairway distribution of proppant in enhancing permeability. Initial fracture permeability is dependent on surface roughness, quantified as root mean square asperity heights. Pressure dependence of permeability of these fractured surfaces does obey the Walsh permeability models. SEM observations of surfaces and proppant suggest a new approach to proppant design.
Hole Cleaning Performance of Gasified Drilling Fluids in Horizontal Well Sections
Authors: Ozbayoglu M. E. , Osgouei R. E. , Ozbayoglu A. M. , Yuksel E.
Published: July 2010

This study aims to investigate the hole cleaning process during the flow of a drilling fluid consist of a gas and a liquid phase through a horizontal annulus. Experiments have been conducted using METU Multiphase Flow Loop under a wide range of air and water flow rates while introducing cuttings into the annulus with several different amounts. Data has been collected for steady state conditions, i.e., liquid, gas and cuttings injection rates are stabilized. Collected data include flow rates of liquid and gas phases, frictional pressure drop inside the test section, local pressures at different locations in the flow loop, and high-speed digital images for identification of solid, liquid and gas distribution inside the wellbore. Digital image processing techniques are applied on the recorded images not only for volumetric phase distribution inside the test section, but also examination of the transport velocities of cuttings particles, which are in dynamic condition. The effects of liquid and gas phases are investigated on cuttings transport behavior under different flow conditions. Observations showed that the major contribution for carrying the cuttings along the wellbore is the liquid phase. However, as the gas flow rate is increased, the flow area left for the liquid phase drastically decreases, which leads to an increase in the local velocity of liquid phase causing the cuttings to be dragged and moved, or a significant erosion on the cuttings bed. Therefore, increase in the flow rate of gas phase causes an improvement in the cuttings transport although the liquid phase flow rate is kept constant. Based on the observations, a mechanistic model which estimates the total cuttings concentration inside the wellbore and developed frictional pressure loss is introduced for gasified fluids flowing through horizontal annulus. The model estimations are in good agreement with the measurements obtained from the experiments. Using the model, minimum liquid and gas flow rates are identified for having an acceptable cuttings concentration inside the wellbore as well as a preferably low frictional pressure drop. Thus, the information obtained from this study is applicable to any underbalanced drilling operation conducted with gas-liquid mixtures, for optimization of flow rates for liquid and gas phases in order to transport the cuttings in the horizontal sections in an effective way with a reasonably low frictional pressure loss.
Comparison of Completion and Heterogeneity Effect on CO2 Sequestration in Shallow and Deep Saline Aquifers
Authors: Yang Fang , Bai Baojun , Tang Dazhen , Dunn-Norman Shari , Wronkiewicz David
Published: July 2010

The effect of completion techniques and reservoir heterogeneity on CO2 storage and injectivity in saline aquifers has been studied using a compositional reservoir simulator CMG-GEM. Two reservoir models were built using data extracted from publications, to represent a deep saline aquifer and a shallow aquifer. The effect of completion methods, including partial perforation of the reservoir net pay (partial completion), well geometry, orientation, location and length, on CO2 storage are discussed. Heterogeneity effect has been addressed considering three parameters: mean permeability, vertical to horizontal permeability ratio, and permeability variation. Sensitivity analysis was carried out using design of experiments (DOE) to determine the dominant factors affecting CO2 storage capacity and CO2 injectivity. Simulation results show that completing all layers, using horizontal wells set in upper layers with a length around 250–300 m are the most favorable choices for CO2 storage capacity in the aquifer examined. Mean permeability affects CO2 storage capacity and injectivity the most; kv/kh affects CO2 injectivity storage capacity more than permeability variation, Vk. More CO2 can be stored in the heterogeneous reservoirs with low mean permeability; however, high injectivity can be achieved in the uniform reservoirs with high mean permeability.
CO2 Sequestration in a Depleted Gas Field: A Material Balance Study
Authors: Stein M. H. , Ghotekar A. L. , Avasthi S. M.
Published: July 2010

The material balance techniques have been used in the oil and gas industry for estimating hydrocarbon reserves for a long time. The objective of this paper is to introduce a fairly simple and fast material balance technique that can provide a fairly good estimate of CO2 storage capacity in depleted gas reservoirs.

Sequestration of CO2 in geological formations is a strategy currently being considered for decreasing CO2 emissions to the atmosphere. These geological formations can be either depleted oil and gas reservoirs or saline reservoirs. A depleted gas reservoir can store significantly more gas than a depleted oil reservoir due to the fact that gas is more compressible than oil and the ultimate recovery in gas reservoirs is higher than that in oil reservoirs. Many researchers have published reservoir simulation studies of CO2 sequestration in depleted gas fields, however, a reservoir simulation study, depending on its complexity, can take several months to perform. In this paper, a fairly simple and fast material balance technique, combined with nodal analysis, is presented that can provide a fairly good estimate of CO2 storage capacity in depleted gas reservoirs.

A depleted gas reservoir, for which the production and pressure history data were available, was selected as a candidate to perform this material balance study. First the material balance calculations were performed to estimate the size of the gas reservoir, aquifer and reservoir pressure. The formation parting pressure was estimated based on basic rock mechanics principles as a function of reservoir pressure. The bottom hole injection pressure was maintained below the formation parting pressure, until the surface facilities limitations were reached. As a result of this study, the amount of CO2 that can be stored in this depleted gas reservoir was estimated within a few weeks.
Calculation of Oil and Water Relative Permeability for Extra Low Permeability Reservoir
Authors: Liu Renjing , Liu Huiqing , Li Xiusheng , Wang Jing , Pang Changting
Published: July 2010

As an important parameter of multiphase flow in porous media, relative permeability curve is often calculated by JBN method which ignores the capillary pressure. However, owing to the fine throat and the complex construct in extra low permeability reservoir, the capillary pressure is very significant. In addition, researches have shown that the flow in low permeability media doesn't follow the Darcy's law and there is threshold pressure gradient occurring in the percolation. Therefore, the traditional method is no longer available for the extra low permeability reservoirs and a new method is needed urgently to resolve this problem.

In this paper, the relative permeability of extra-low permeability core was calculated by three methods: JBN method, fractal model and modified JBN method. The fractal model was set up based on the capillary pressure curve and the fractal geometry theory. The modified JBN method taken into the effects of capillary pressure and threshold pressure gradient, and a semi-log fit function other than polynomial function was used to improve the accuracy.

The results show that, comparing with JBN method, the fractal model and the modified JBN method can predict the relative permeability more accurately. And the modified JBN method is the best. The water cut calculated by the new method matched the production data better than that calculated by JBN method.

The new method overcomes the limitations of previous researches. It can be used to calculate relative permeability for extra low permeability reservoirs more accurately and help to develop extra low permeability reservoirs more reasonably.
Research on the Formation Pressure Prediction in the Exploration Area of Northeast Sichuan, China
Authors: Jie Cui , Sun Mingxin , Li Zhonghui
Published: July 2010

The geologic condition in the northeast of Sichuan is so complex that many drilling complexities like leakage, kicking, collapse and sticking often occur. There are many types of gas reservoirs such as pore, interstice, pore-interstice, interstice-pore space and so on. A multiple of pressure system and an ultrahigh pressure gas reservoir exits which contain hydrogen sulfide gas in the carbonate formation. Research on the formation pressure calculation is carried out and a pressure model is established in order to ensure the safety drilling. The priority is to study the pressure in marine formation based on the characteristic of formation pressure which has high sensibility on ratio between P-wave and T-wave's speed in carbonate rock formation. The formation pressure profile is built by the pressure model and well logging date. There is little error in the results so that they can meet the project demands. The results is very important in exploring gas in northeast of Sichuan.
Study on Operating Parameters of CO2 Supercritical Pipelines
Authors: Li Changjun , Wu Xia , Jia Wenlong , Liu Enbin , Liao Kexi
Published: July 2010

Supercritical pipelines are most commonly used in CO2 transportation. Liquid models are always utilized for design and hydraulic checking of those pipelines. However, supercritical CO2 may show significant characteristics of gaseous under certain operating condition. This phenomenon may increase pressure drop so that pressure values will be different from calculation results from liquid models. According to comparing the compression factor and density curve of liquid and supercritical CO2, the fact that when operation parameters of supercritical pipelines occupy in certain pressure and temperature regions, compressibility of CO2 cannot be neglectd is concluded. On the basis of density variation tendency, the method and its steps which are used to delimit compressible region of supercritical CO2 are proposed. Compared with this compressible region, operating parameters of supercritical pipelines can be checked. The application example calculates the pressure drop both by liquid model and gaseous model which considers copressibility. The results verified that delimited method of compressible region is accurate and reasonable.