bluuebunny/crossref_metadata_2025 huggingface dataset:
A Dynamic Simulation Study of Water Hammer for Offshore Injection Wells to Provide Operation Guidelines
Authors: Tang Yula , Ouyang Liang-Biao
Published: July 2010

In water injectors, rapid shut-in creates a water hammer effect. Over time, injectors that undergo repeated rapid shut-ins often have significantly reduced injectivity and show evidence of sanding and even failure of the down-hole completion. This study is to provide an operational reference for the well injection for an offshore deepwater field to mitigate back-flow and maintain the downhole sand-control device integrity and thus satisfactory water-injectivity.

Two different shut-in scenarios have been investigated. One of the scenarios is that among the three water injection wells, two are shut-in and the third one is kept open. Another scenario is that the top side pump is stopped while the three injection wells are still kept open. Water hammer sensitivity on different parameters, such as valve installation position, stroke time, water back flow conditions and the hydraulic characteristics, has been performed.

For Scenario I, the pressure change due to wellhead shutting-in is around 200 psi at bottomhole (BH), which is much lower than the amplitude seen at the wellhead (3400 psi). The third well which stays open for injection experiences even larger pressure surge (around 450 psi at bottomhole). Back flow for the opening well could be close to 10,000 stb/d. With increasing skin due to cumulative injectivity damage by water particles plugging and/or thermal induced fracture closure at shut-in, the water hammer pressure fluctuation can be as high as 1200 psi.

For Scenario II, pressure fluctuation due to top side shut-in is 300 psi. With SCSSV closing when back flow is felt, the water hammer fluctuation can be reduced to around 200 psi.

Unlike the classic water hammer in the pipeline, water hammer in the water injection wells is much less in terms of surge amplitude, as the high injectivity reservoir behaves like a cushion to absorb the water hammer impact on downhole completion and sand-control infrastructure. Water hammer in the wells and pipeline system experiences: (1) after-flow with reduced BHP and flow rate into formation; (2) back flow when BHP becomes less than reservoir pressure; (3) water flows into reservoir again when BHP starts to increase. This cyclic process continues with reduced amplitude in each cycle due to friction.

Results also show that check valve set at the bottomhole could stop the back flow in less than 1 sec.

This study provides useful reference and operation guidelines on offshore water injection and completion design consideration.
Development and Sustainability of a Small Gas Based Economy
Authors: Boodoo Craig
Published: July 2010

Trinidad and Tobago has become a major player in the export of natural gas and gas related products over the past decade. This reflected a deliberate policy change within Trinidad and Tobago. It involved significant investment in people, technology and infrastructure and has enabled us to exploit several niche as well as some conventional markets that were previously inaccessible. Our markets have expanded from the Caribbean and North America to Europe, Asia, the Orient and Latin America.

This paper discusses some of the steps taken towards developing a small gas based economy and ensuring its sustainability.

We will briefly discuss

The major gas based industries that have been developed; which include Liquefied Natural Gas (LNG), Methanol and Ammonia Production growth from insignificant to world class; in terms of natural gas as well as in the previously mentioned industries Reserves fluctuations; how they are perceived and what does it mean in terms of sustainability Growth of the economy; from a national budget of under 12 billion US dollars to over 50 billion in less than 10 years What is being done to encourage sustainability

The Trinidad model is currently being considered by other states and this paper could help in their decision process.
Layering and Oil Recovery: The Impact of Permeability Contrast, Gravity, Viscosity and Dispersion
Authors: Tungdumrongsub Suphawan , Muggeridge Ann
Published: July 2010

The vertical sweep efficiency of all secondary and tertiary oil recovery processes will be affected by the viscosity and density contrast between the oil and the displacing fluid as well as the existence of layers in the reservoir and the permeability contrast between those layers. Mixing between injected and reservoir fluids driven by physical dispersion will alter the effect of these factors on some enhanced oil recovery processes such as miscible gas injection or low salinity water injection. If physical dispersion is large enough it may result in vertical sweep efficiencies close to 100% but will thereby reduce the microscopic sweep efficiency of the EOR process.

This paper investigates the impact of variations in permeability contrast, gravity, viscosity, and dispersion on the oil recovery from a first-contact miscible gas injection scheme in a two layered reservoir. The variations are characterized in terms of mobility ratio, viscous to gravity ratio, layer permeability contrast, vertical to horizontal permeability ratio and the transverse dispersion number proposed by Lake and Hirasaki (1981). The reservoir behaviour is quantified at early and late time in terms of breakthrough time, oil recovery at 1 PVI and late time and solvent cut.

Overall, dispersion dominates oil recovery when the transverse dispersion number is greater than one regardless of mobility ratio, layer permeability contrast or viscous to gravity ratio. The transverse dispersion number can be used to evaluate the impact of cross-layer mixing on vertical sweep for a far wider range of flow regimes than originally investigated by Lake and Hirasaki (1981). This work demonstrates that the transverse dispersion number can and should be used to assess whether vertical or microscopic sweep efficiency will be dominant in any displacements where dispersion may have an impact on recovery.
Static and Dynamic Estimates of CO2 Storage Capacity in Two Saline Formations in the UK
Authors: Jin Min , Pickup Gillian , Mackay Eric , Todd Adrian , Monaghan Alison , Naylor Mark
Published: July 2010

Estimation of CO2 storage capacity is a key step in the appraisal of CO2 storage sites. Different calculation methods may lead to widely diverging values. The compressibility method is a commonly used static method for estimating storage capacity of saline aquifers: it is simple, easy to use and requires a minimum of input data. Alternatively, a numerical reservoir simulation provides a dynamic method which includes Darcy flow calculations. More input data are required for dynamic simulation, and it is more computationally intensive, but it takes into account migration pathways and dissolution effects, so is generally more accurate and more useful. For example, the CO2 migration plume may be used to identify appropriate monitoring techniques.

Two typical saline aquifer storage sites were analysed using both static and dynamic methods. One site has a comparatively simple geology, while the other has a more complex geology. For each site both static and dynamic capacity calculations were performed. CO2 injection for 15 years was followed by a closure period lasting thousands of years. The proportion of dissolved CO2 and the proportion immobilised by pore scale trapping were calculated.

The results of both geological systems show that the migration of CO2 is strongly influenced by the local topography of the upper surface of the aquifer formation. The calculated storage efficiency for the first site varied between 0.5% and 1% of total pore volume, depending on whether the systems boundaries were considered open or closed. Simulation of the deeper, more complex geological system gave storage capacities as high as 2.75%.

This work is part of the CASSEM (CO2 Aquifer Storage Site Evaluation and Monitoring) integrated study to derive methodologies for assessment of CO2 storage in saline formations. Although, static estimates are useful for initial assessment, we demonstrate the value of performing dynamic storage calculations, and the opportunities to identify mechanisms for optimising the storage capacity.
Experimental Research of work of Different ESP Stages on the Viscous Fluids
Authors: Mokhov Mikhail , Tsunevskiy Andrey
Published: July 2010

Recent years there is trend of oil production increase from the wells with abnormal operating conditions. One of the complicated factors is elevated viscosity of the oil well production. Selection of the high-performance equipment for the work in such conditions is nowadays very relevant. The purpose of this research is a comparison of work of different construction ESP stages on the viscous fluids.

Tests of work of Different ESP Stages were hold on the experimental bedstead of Oil Field Development and Exploitation Department of Gubkin University. Tested ESP Sections are shown in Figure 1.

The following ESP stages were used as a subject for comparison: production stage VNN5-125, production stage VNN5-125 with bored impeller blades, and new construction stage with open-type impeller, which was developed at the Oil Field Development and Exploitation Department of Gubkin University.
Iterative History Matching Technique for Estimating Reservoir Parameters from Seismic Data
Authors: de Souza R. M. , Machado A. F. , Munerato F. P. , Schiozer D. J.
Published: July 2010

High uncertainties associated with unknown fluids and pressure distributions could hamper the history matching process. Accordingly, efforts have been made to evaluate these properties distributions from static and dynamic seismic attributes. Nevertheless, these new methodologies aim to develop quantitatively seismic data integration, which require a suitable association between Petro-Elastic and Flux Models parameters dealing with the inherent inter-dependence between simulation and rock physics parameters.

In this paper it is presented an iterative workflow between two optimization processes. Firstly, a coupling between a Petro-Elastic Model and a reservoir simulator provides Acoustic Impedance (AI) values for two numerical models that have to be matched. The one that has to be honored provides the synthetic "observed" AI data and the other gives the calculated AI values. An objective function based on these is minimized through a Pre-Conditioned Conjugate-Gradient method under reservoir simulation constraints, in order to achieve saturation and pressure trends.

As a second step, a history matching procedure where the saturation/pressure values derived from the former one are now the models to be honored. Then, this information is combined with flux lines in the parameterization phase delineating reservoir heterogeneities to define regions where permeability objective functions are optimized. The saturation/pressure trends, evaluated by this last step, are used to update the initial inputs at the first one, providing history matching constraints to the overall processes.

This technique allowed to determine faults and permeability channels with less uncertainties and higher accuracy and decreasing in time-consuming of the history matching procedure was obtained. Moreover, this methodology improved the reservoir behavior predictions reliability, through quantitative seismic data integration in the history matching process.

Certainly the major goals are the integration aspects of this proposed methodology combined with the obtained improvements in the history matching process.
Experimental Research of Work of Different ESP Stages on the Viscous Fluids
Authors: Mokhov Mikhail , Tsunevskiy Andrey
Published: July 2010

Recent years there is trend of oil production increase from the wells with abnormal operating conditions. One of the complicated factors is elevated viscosity of the oil well production. Selection of the high-performance equipment for the work in such conditions is nowadays very relevant. The purpose of this research is a comparison of work of different construction ESP stages on the viscous fluids.

Tests of work of Different ESP Stages were hold on the experimental bedstead of Oil Field Development and Exploitation Department of Gubkin University. Tested ESP Sections are shown in Figure 1.

The following ESP stages were used as a subject for comparison: production stage VNN5-125, production stage VNN5-125 with bored impeller blades, and new construction stage with open-type impeller, which was developed at the Oil Field Development and Exploitation Department of Gubkin University.
Application of Integrated Production and Reservoir Modeling to Optimize Deepwater Development
Authors: Stoisits R. F. , Bashagour H. M. , Su C. G.
Published: July 2010

A deepwater satellite field project encompasses two fields which are in the general vicinity of two existing Floating Production Storage and Offloading (FPSO) vessels. A number of development architectures that include various subsea tie-backs to two existing FPSOs and, in some cases, an additional FPSO were potential candidates for development. To accelerate the project schedule, Reservoir and Subsea, Umbilicals, Risers, and Flowlines (SURF) Engineering were conducted in parallel. In order to establish an optimal SURF architecture, a method to forecast production behavior of the various architectures is required. To achieve this objective, an Integrated Production Modeling (IPM) tool was developed. Components of this tool model reservoir material balance, well, flowline, riser, and facility performance throughout the project life. Flow assurance analysis, project planning, evaluation, and optimization are facilitated by this model. IPM achieves these objectives by enabling rapid generation of production forecasts consistent with available field information while honoring hydraulic and capacity constraints. When an optimal SURF architecture was developed, system operability was assessed by applying transient flowline and riser analysis to the production system. System operability requires that the SURF architecture is viable over a range of operating conditions spanning upside and turndown scenarios. Upon completion of the rigorous reservoir models, rate profiles were generated by reservoir simulation and compared to the range of rates used to develop the SURF architecture. The reservoir simulation rate profile was contained within the operating range used to develop the SURF architecture. Application of IPM resulted in an optimal SURF architecture, which was developed in parallel with the rigorous reservoir models. The parallel engineering effort allowed an extensive investigation of SURF architectures while accelerating the project schedule.
An Effective Stimulation Fluid for Deep Carbonate Reservoirs: A Core Flood Study
Authors: Mahmoud M. A. , Nasr-El-Din H. A. , De Wolf C. A. , LePage J. N.
Published: July 2010

Matrix acidizing is used to remove near wellbore damage and create channels or wormholes in carbonate formations to improve well performance. The use of conventional matrix acidizing fluids with HCl is not effective in some cases because of the rapid acid spending. Previous studies have demonstrated the use of chelates such as ethylenediaminetetraacetic acid (EDTA) and N-hydroxyethylenediaminetriacetic acid (HEDTA) as alternatives for HCl to stimulate carbonate reservoirs.

A recently introduced chelating agent was examined to stimulate deep carbonate reservoirs. This chelating agent can be used at very low injection rates to avoid fracturing the target zone during the treatment, which may occur if HCl is used at high flow rates. The chelating agent used in this study was glutamic acid-N, N-diacetic acid (GLDA). Two sets of calcium carbonate cores were used one with 1.5 in. diameter and 20 in. length and the other set was 1.5 in. diameter and 6 in. length. Calcium carbonate cores such as Indiana limestone cores were used in this study. A dolomite core 1.5 in. diameter and 6 in. length was used to investigate the ability of this chelating agent to stimulate dolomite cores. The cores were treated with GLDA at various pH (1.7–13) and temperatures (180–300°F). The concentrations of dissolved calcium, magnesium, and GLDA in the core effluent were measured for material balance determination.

GLDA was found to be highly effective in creating wormholes over a wide range of pH (1.7–13) in calcite cores. Increasing temperature enhanced the reaction rate, more calcite was dissolved, and larger wormholes were formed for different pH with smaller volumes of GLDA solutions. In addition, GLDA was very effective in creating wormholes in the dolomite core as it is a good chelate for magnesium. GLDA was found to be equally effective in creating wormholes in short and long cores.
History-Matching With Sensitivity-Based Parameter Modifications at Grid-Block Level
Authors: Almuallim H. , Edwards K. , Ganzer L.
Published: July 2010

Traditionally, history-matching has been a trial-and-error process, where various model parameters are repeatedly adjusted over successive simulation runs so that the difference, or mismatch, between simulated and observed values is minimized. In general, the relationship between such mismatch and the values of the parameters is quite complex. A great deal of expertise is required to figure out patterns that capture such relationship intuitively. Moreover, the number of parameters is so immense that the engineer has to restrict the attention to a small set of parameters, possibly missing influential ones.

In this work, we rigorously compute the derivatives of the mismatch with respect to each parameter, taking advantage of all pieces of simulator outputs, as well as our detailed knowledge of the fluid flow equations implemented within the reservoir fluid-flow simulator. With this new approach, a single simulation run followed by a derivatives calculation session is sufficient to detect how each parameter affects the mismatch, and hence, to decide how (or whether) to change each parameter to improve the match.

This approach has been successfully applied to history-match a three-phase case of a reservoir in North America with 45 years of production history and more than 40 wells. We started from a case that has already been matched through conventional means. We show that, based on our technique, very significant improvements can be achieved beyond the point where conventional means have been exhausted using only a small number of simulation runs.
Experimental and Numerical Calculation of Polymer Base Mud without Solids Invasion in a Porous Media
Authors: Moreno R. B. , Bonet E. J.
Published: July 2010

The present paper intends to compare experimental and simulation results for polymer based flow through porous media. An innovative experimental study, including injection experiments and CT scanning evaluation (X-Ray/2D), was carried out to investigate the characteristics of filtrate invasion.

Normally the drilling mud includes solid particles to minimize mud filtrate invasion, however some authors emphasizes the use of drill-in fluids solid free to minimize irreversible damage due to pore plugging by mud's particles. Moreover, peculiar non-Newtonian behavior of polymers has been pointed out as possible solutions to these problems.

For these reasons, we performed experimental and numerical calculation of polymer base mud invasion in a porous media without bridging agents. We are presenting the results of 24 tests and studying in detail one of various experimental runs. Calculated data and laboratory measured data were compared with drilling fluid invasion's process.

Invasion depth, contact time and saturation profiles were carefully analyzed. The CT scan images were very helpful to inform the pattern invasion: stabilized or fingering invasion. The information is very helpful to program adequate drilling mud.
Novel Analytical Methods of Temperature Interpretation in Horizontal Wells
Authors: Muradov K. M. , Davies D. R.
Published: July 2010

Long (horizontal) completion intervals typically show a wide variation in the inflow distribution along their length due to either formation heterogeneity or (frictional) flow pressure losses. Monitoring of the inflow profiles in such wells is an important step in efficient reservoir management. Accurate temperature measurements (using distributed temperature sensors, permanent downhole gauges or other forms of production logging) have become more widely available in recent years. Many published papers describe temperature sensing and its phenomenological interpretation; but few attempts have been made recently to develop a comprehensive mathematical basis for the analysis of downhole temperature behaviour.

This paper presents a holistic, analytical, mathematical model for calculation of the temperature profile in horizontal wells producing liquids for reservoirs where thermal recovery methods are not being employed. The model presented in this paper rigorously accounts for (1) the Joule-Thomson effect, (2) convection, (3) transient fluid expansion and (4) time-dependent heat loss to the surrounding layers.

A synthetic horizontal well model has been built using a commercial, scientific simulator as a test-bed to provide the data to allow a rigorous evaluation of the efficacy of our novel analytical methods. Asymptotic, analytical solutions have also been found for transient and steady-state flow. It has also been found possible, in addition to these constant flow rate solutions, to apply the well known pressure analysis solution techniques for the estimation of (1) thermal properties and (2) inflow profiling.

The methods proposed here can be applied to a wide variety of well completion types, flow conditions and system properties. They form the basis for the calculation of oil and water flow phase cuts and distributions based purely on temperature measurements. Their use will further increase the potential applications of the modern downhole monitoring and control capabilities currently being installed in wells. As such, they will form an essential element of the "digital oil field".
Hydrocarbonate Reservoir Characterization Constrained to Seismic Attributes
Authors: Guillou Olivier , Schiozer Denis José , Biver Pierre
Published: July 2010

The growing difficulties encountered in petroleum exploration and production, such as declining discoveries, increasing coastal distances and field depth, create a constant need for innovation. To improve the knowledge and dominate reservoirs located in remote areas, new tools and methodologies must be developed. With the steady increase in computing power and the birth of new algorithms, this demand can be satisfied and project risks can be reduced.

From new seismic attributes integration methodologies developed into an optimization process based on forward modeling, different valid results have been obtained. In this context, seismic constraint characterization has revealed an effective way to improve the seismic quality and the relevance of generated models (Barens et al, 2004).

This paper proposes to compare the results of three geological modeling methodologies and its impact on a field development risk analysis. The case study is realized on a deep offshore West African turbidite with a relevant exploration wells number and a good 3D seismic survey quality.
Breakouts: Physical and Numerical Modeling
Authors: Villarroel F. M. , Júnior E. V. , Rabello G. F. , Bloch M. , de Azevedo V. A.
Published: July 2010

In-Situ stress knowledge is very important for the oil industry, affecting well location, drilling, stimulation design, and production rates. Breakout detection from the interpretation of wellbore logs, including geophysical measurements, is one of the most applied methods for estimating the horizontal in-situ stresses. This paper presents laboratory tests for breakout simulation with a synthetic sandstone (0.3 × 0.3 × 0.3 m), performed in a large poliaxial cell. The testing apparatus was able to show breakout formation in a central hole in the block, simulating a vertical wellbore. The experimental results were compared and confirmed by numerical simulation through finite elements using a commercial software — ANSYS™ (ANSYS, 2007), and analytical calculations. The stress contrast at the onset of the breakout failure, determined from the experimental results, agreed within 4 % to the value computed from the numerical and analytical analyses.
Pressure Falloff Test Interpretation for Leakage Detection during CO2 Injection in a Deep Saline Aquifer
Authors: Ehlig-Economides C. A. , Anchliya A. , Song B.
Published: July 2010

Geological sequestration of carbon dioxide in deep saline aquifer is proposed as an option for mitigating CO2 emissions into the atmosphere, but multiwell injection into the same aquifer will cause pressurization. While many papers have considered long term CO2 trapping, few have addressed the role of pressure monitoring during injection as a way to ensure that the injection pressure does not exceed a regulated value below the fracturing pressure.

This work provides models for the injection falloff response that can be used for permanent pressure gauges installed at the injection interval for aquifer characterization and, in particular, for CO2 leak detection. A three region analytical composite reservoir model with sealing or constant pressure outer boundary is used to model numerically simulated falloff data for CO2 injection from a hypothetical 500 MW coal power plant. The analysis shows that regular falloff tests can monitor the advance of the dry zone and provide a reasonable estimate for the average aquifer pressure for the well injection area. The latter can be used for material balance, and simulations show that the behavior of the average pressure versus time is sensitive to the presence of a leak. Furthermore, it may be possible to determine whether the leak is located in the dry zone, two-phase zone, or the unswept brine zone.

Pressure behavior in CO2 storage aquifers has been neglected thus far in the literature. In reality, analysis of successive pressure falloff tests easily distinguishes over time whether a well is injecting into a limited volume exhibiting pseudosteady state behavior, an open aquifer with constant pressure support, or an effectively infinite aquifer. This paper spells out why pressure monitoring makes sense during CO2 injection.
Learnt from Formation Damage Problems to Design Selection of Produced Water Treatment for First Full Field Development Steam EOR Oman
Authors: Nengkoda Ardian , Habsi Mohd , Salmi Ahmed , Annamalai Ilangovan , Ahmed Dilshad , Sariry Sameer , Hadhrami Hamoud
Published: July 2010

The X field of Oman is a highly fractured carbonate field. The main oil bearing reservoir is the Shuaiba/Kharaib formation. Full development of the field will result in large water production that will have to be disposed off. Plan is to inject the produced water into the Al Khlata sands. The availability of sufficient water disposal capacity is a crucial element of the X steam project. If this capacity is constrained, water production from the X field is limited and it may not be possible to maintain the oil rim at the completion depth of the fracture rim producers. This may cause the oil production of the whole field to be deferred. For the base case, the total forecasted water production ranges from 63,000 to 74,000 m3 /d for 30 years. During pilot plant operation in year 1998-2000 and cold production, the formation damage and loss injectivity have been reported at produced water disposal wells. The main objective of this study is to ascertain the cause of rapid injectivity loss and input design for facilities selection. The assessment are cover the oil and solid particle size, fluid chemistry and compatibility, suspended solid in disposed water, the impact of oil in disposed water, fine migration (critical velocity test) and proper produced water treating facilities selection (equipment and technology).
Impact of Fluid Distribution on Scale Inhibitor Squeeze Treatments in Pattern Floods and Fractured Wells
Authors: Rakhimov A. , Vazquez O. , Sorbie K. S. , Mackay E. J.
Published: July 2010

The most common method for preventing scale formation in the well completions is by applying a scale inhibitor (SI) squeeze treatment. Near-well squeeze treatment models generally assume that the flow pattern around the well is radial. Although, this assumption may be reasonable in most scenarios, this paper investigates whether strictly non-radial flow patterns around the well have a major effect on the squeeze treatment.

Sensitivity calculations were performed to identify the impact of waterflood patterns such as Two-Spot, Five-Spot, Line Drive, etc. on the squeeze treatment lifetime in vertical production wells. The second part of the project then continued the study of the impact of flow patterns in fractured vertical production wells. The outcome is that scale squeeze treatments initiated at the same watercut appear not to be impacted by the various flood patterns studied. However, investigation showed that fractured wells typically have longer squeeze lifetimes in comparison to non-fractured wells.

Calculations show that for fractured wells, inhibitor adsorption on the face of the fracture itself has no impact on the treatment lifetime; the longevity of the squeeze is determined by the inhibitor adsorption in the matrix rock outside the fracture. The benefit a fracture brings is in terms of propagating the SI further from the well than would occur in an unfractured radial treatment. In the fractured well the inhibitor is then more greatly retarded by contact with rock over a greater distance than would occur in a matrix only radial treatment. Sensitivity calculations were performed to identify the impact of fracture length.
Hydrate Formation Conditions of Natural Gas with High Content of Carbon Dioxide and the Calculation Model.
Authors: Sun Ruiyan , Li Changjun , Yu Sheng , Wang Shigang , Sun Ouyang , Liu Enbin
Published: July 2010

In view of the natural gas with high content of carbon dioxide in Jilin oil field, this paper carried out experiments on hydrate formation conditions and studied the calculation model. Hydrate formation conditions of natural gas with high content of carbon dioxide were measured by using DBR device, and the formation temperatures of hydrate were obtained in the pressure range 0.5~15MPa. The molarity of carbon dioxide was 10% ~ 90%. Hydrate formation conditions of natural gas with high content of carbon dioxide were calculated by using vdW-P model and Chen-Guo model. The results show that: the calculation error of both models were more than ±2☐. With the increasing CO2 concentration in the natural gas, the calculation error of vdW-P model increased, but the Chen-Guo model's reduced. In general, the Chen-Guo model is superior to the vdW-P model. Based on the experimental data, the Chen-Guo model was improved. The results of improved Chen-Guo model agreed well with experimental result. The improved Chen-Guo model has high prediction accuracy, satisfies the engineering calculation, and has value popularized and applied.
A Case Study of High-Pressure, Light-Oil Steam Flooding in A Low-Permeability Reservoir
Authors: Shuhong Wu , Zhongyi Zhang , Yongbin Wu , Dehuang Shen , Yu Qian , Fujun Qiao
Published: July 2010

Steam flooding in heavy-oil sands has been well characterized over last decades as a mature technology, and while steam has been injected into light-oil, low-permeability sands almost as long, the mechanisms and effectiveness of this process are much less understood because of the complexities of flow in these sands and high pressure steam injection. This paper examines thermal recovery in such reservoir using both physical and numerical simulation and also describes the performance of pilot test in Daqing oil field.

In regard to recovery mechanisms, wettability alteration, interfacial tension and threshold pressure gradient decline contribute to higher oil displacement and swept efficiency. Vaporization, viscosity reduction, thermal expansion and relative permeability variation accounts for over three quarters of incremental recovery in steam flooding. As a consequence of high-pressure steam flooding five fluid banks form: steam bank, distillate bank, hot water bank, condensate bank and cold water bank, in which steam bank is much smaller than high temperature region. Hence, it is substantially different from shallow heavy-oil situation where both of them are almost similar in size.

This paper details a pilot test in a low-permeability reservoir with depth of 800m, an average permeability around 8 md and a typical porosity of 16%, oil viscosity roughly of 40mpa.s. Waterflood began in 1990 and suffered from low injectivity, poor sweep, and injector-to-producer linkage. These factors tended to degrade waterdlood's effectiveness. An attempt of steamlfood has been used to enhance recovery since 2005. The pilot test shows promising results. The response to steam injection is prompt and significant. The injectivity is doubled and productivity is almost tripled. The oil-steam-ratio is around 0.3. The incremental recovery is predicted to be over 10%. And now, field operator is considering expanding the pilot program to a much larger region.
A Innovative Technology to Extend the Borehole Section in Gas Drilling
Authors: Hongchun Huang , Ning Sun , Jinhai Yu , Jie Feng , Hui Wang
Published: July 2010

Air/gas drilling is an acknowledged practical technology for its significant advantages in rate of penetration enhancement, lost circulation prevention and hydrocarbon reservoir protection. Air/gas drilling technology, however, can only be applied to dry formations in nowadays. When formation drilled water produces, air/gas drilling needs to be converted to mist drilling, foam drilling or liquid mud drilling, which can result in dramatic reduction of drilling speed. This problem becomes the bottleneck to further extend gas drilling applications in a larger scale in China. Aiming at solving water influx problems in the field application of gas drilling, a new technical method was proposed through in-house research. The water production zone and water cut of drilled formation are predicted using the seismic, logging data and the seepage mechanics theory. When the drilled formation begins to produce large volume of water, a material (water absorbent) is injected to promptly absorb the downhole produced water and remove it out of the wellbore, so as to maintain the normal gas drilling. Furthmore, as drilling goes into well sections with incompetent or large water-cut formations, the expanded tube is employed to mechanically plugging the complex borehole section, which enables the air/gas drilling to be continuecd. Based on this solution, a water absorbent with high efficiency was screened out. Related operational procedures of absorbent injection and expanded tube plugging were studied. Field pilot test shows that with the technique, the borehole section in air/gas drilling can be extended, making the best use of air/gas drilling to increas penetration rate, which hence plays an important role for promoting the use and the advancement of air/gas drilling technology.
Horizontal Well Production Technologies in the Thin-Bedded, Bottom-Water Reservoirs in Luliang Oilfield, China
Authors: Jin Huo , Guoxin Shi , Jianguo Lu , Linxiang Sang , Jun Shi , Jianhua Tan , Yi Zhang , Guangxu Fan
Published: July 2010

Hutubihe formation in Well block Lu-9 of Luliang oilfield, Junggar basin of Xinjiang, China is characterized by special thin-bedded, low-amplitude reservoirs with edge and bottom water. Non-producing reserves are mostly distributed in small thin-bedded lenticular sand bodies with edge and bottom water. The average reservoir thickness is less than 3m. Therefore, the water-oil contact relationship is relatively complicated and it is difficult to produce oil from vertical wells. As a result, the economic benefit is poor. Based on the detailed reservoir description and dissection of single oil-bearing sandbodies, classification of flow units, accurate identification of net pay and low-resistivity oil-water zones, pilot horizontal-well production is carried out. Meanwhile, research on accurate well track control, reasonable horizontal section length, well placement pattern and injection-production well spaces are performed. Thus, a set of horizontal well production technologies are established for this kind of reservoirs. On the basis of optimization of non-producing reserves of different oil-water relationships and different geological characteristics in the range of an 800m interval, 110 horizontal wells are allocated with the newly-established productivity of 400 thousand tons. The producing extent of reserves has been improved from 50.7% to 83.2% and pretty good effects have been gained.
Formation of Carbonyl Sulfide during Molecular Sieve Dehydration Process from High Sour Natural Gas in China
Authors: Yan Tu , Honggang Chang , Jinlong He
Published: July 2010

Molecular sieves with high silica content are usually selected for dehydration of sour natural gas because of their tolerance to H2S. Some special acid-resistant molecular sieves can maintain their dehydration capabilities over long period.But carbonyl sulfide (COS) is formed by the reaction of H2S and CO2, which is catalyzed by molecular sieves during natural gas dehydration.

The overall development program at Luojiazhai Gas Field(high sour gas contents) of petrochina southwest oil and gas field company chose the molecular sieve adsorption process to dehydrate sour natural gas, but the gas field has not been developed up to now.A set of of the molecular sieve adsorption equipments has been applied at Liangfeng gathering station of Wanzhou city. This is the first plant for high sour gas dehydration using molecular sieve in China. The wet natural gas contains 9% H2S, 11% CO2 and 200ppmv COS. The dry gas flows to a natural gas treating plant to remove H2S and CO2 to meet pipeline specifications.

We found that the water dew points of the treated gas were always lowered to less than -10☐.But this molecular sieve displayed a certain extent of catalytic activity for the reaction converting H2S and CO2 to COS and H2O. The generated amount of changed greatly during operating cycle. The concentration of COS will rise while hot stripping gas moves through the bed.

So for sour gas dehydration and desulfurization, these data may prevent serious design errors. Molecular sieve manufactures were able to gain valuable assistance.
New Methods about the Productivity Contribution Evaluation and Development Features of Natural Fractures in Ultra-Low Permeability Reservoir
Authors: Xinquan Ran , Jiyong Zhao , Shuheng Li , Jianming Fan
Published: July 2010

According to the data such as outcrops, cores, well logging with imaging, and thin sections, the natural fractures are developed in ultra-low permeability reservoirs. The fracture types are with tectonic shear fractures as the dominated which appear in groups and en echelon arrangement. Natural fractures are most developed in sandstone and siltstone, but rarely developed in mudstone.

The tectonic fractures show themself in four groups of the NE, NW, near EW and near SN orientations. Influenced by the heterogeneity of rock mechanics and the current stress field, fractures in NE-orientation are with wide opening and high permeability. Therefore the NE-orientation is the main flow direction of fluid in this area. On the basis of the traditional fracture description methods, a geological model of reservoirs considering the natural fractures is established with the help of modern fine reservoir description and fracture modeling techniques. The planar distribution laws of effective natural fractures that tally with production performance are determined by application of a numerical reservoir simulation inversion technique. A model considering natural fractures and non-Darcy flow is creatively established on the above mentioned basis. Quantitative evaluation of natural fracture and matrix's contribution to the individual well production rate has been conducted by using this model and the numerical reservoir simulation technique. The contribution rate of natural fractures obtained from the two methods to the average individual well production is 30%–40%. Research results show that the understanding of influences of natural fractures on development results of the ultra-low permeability reservoirs is deepened. Quantitive description of effective natural fractures and their assessment method of the contribution rate to the productivity have been preliminarily formed at the same time, which can be used for reference in the development of the same kind of reservoirs.
Studies on the Electroc-Catalytic Degradation of EOR Wastewater by Ce-Ti/TiO2 Electrode
Authors: Yi Zhang , Youyi Zhu , Desheng Ma , Dong Han , Dakuang Han , Shuying Wang
Published: July 2010

Enhanced oil recovery is the most effective method to produced oil from oil reservoir, during the enhanced oil recovery process, many kinds of chemicals, such as polymer and surfactants, are used, so the produced water (wastewater) is complexity and stability. How to treat the oily wastewater becomes an urgent problem in oil industry. So the feasibility and effective of electro-catalytic degradation of EOR wastewater was investigated in this paper. By sol-gel method the rare earth metal cerium (Ce) and titanium (Ti) doped TiO2 thin film electrodes were prepared. The surface topography, element composition and structure of the electrode of Ce-Ti/TiO2, which has the optimal effects for degradation of oily wastewater and polymer, were analyzed by SEM, EDX and XRD methods. The electro-catalytic effects and mechanism were also studied. The results indicated that the main process of electro-catalytic deoiling was electro-burning, and the acidic medium is favorable for oil and hydrolyzed polyacrylamide (HPAM) degradation. The removal rate of CODCr and oil content in the EOR wastewater reached 92.9% and 94.3% respectively. The removal efficiency of polymer was higher 20% than that of the advanced electrochemical oxidation technology, and the de-oiling efficiency enhanced about 8%~9%. After treatment by the electro-catalytic methods, the CODCr and oil content in the EOR wastewater meet with the Chinese discharge standard of the wastewater.
The Study of Development Mechanism and Characteristics for Kela 2 Abnormally High Pressure Gas Field
Authors: Tongwen Jiang , Weihong Zhu , Xiangjiao Xiao , Hongfeng Wang
Published: July 2010

Kela2 Gas Field is the main West-to-East gas transmission pipeline gas field with the feature of high geologic reserve, high well productivity, high reservoir pressure, high pressure coefficient, high structure angle and extremely thick reservoir and so on. Base on the main geologic features, has established the geological model fitting the gas reservoir. Through the further study of the geologic features and the development mechanism, has made the conclusions as follows: ①Because of the good quality of reservoir rocks, stress sensitivity has little impact on development effect. ②The static water body is about 5 times of hydrocarbon volume through geological evaluation, so the water drive energy is weak and has little effect on the field development. Thus the field can be developed in high recovery rate, and the reasonable recovery rate is around 4%. ③There is less interlayer interference between high and low permeability zones. Therefore, It is considered that commingled production should be taken for Kela2 gas field. Base on the conclusion, has builded up Kela2 gas field, which is the largest scale deliverability in China. The fundamental theory for Kela2's productivity evaluation and dynamic analysis is well applied to th the Dina and the Dabei gas field which is the similar abnormal high pressure character. Through the applicantion, has formed a systematic development techniques suitable for the submountain region with ultra deep and surpressure of Tarim basin.
UBD Brings about a Big Breakthrough for the Exploration of Algeria Block 350
Authors: Cunzhi Cheng , Benjing Dong , Zuokun Zhou , Jianli Zhang , Junfeng Ma , Qingfang Li , Zuokun Zhou , Guo Wei , Mingfu Ma , Chunshu Zhang
Published: July 2010

Algeria Block 350 is located in the northwest of the Oued Mva sub-basin in the Sahara Desert with an area of 8666km2. From 1972 to 2007, CFPA, Talisman, SSRP, Sonatrach, and CNPCIAE drilled in succession 10 wells in the block. However, all the wells failed to reach an industrial oil and gas production rate due to the high mud content in the tight and low-permeable sandstone reservoirs. Though the hydrocarbon detectors of two wells, Bel-E-1 and Meg-2, which were drilled by CNPC, showed the gas measurement values up to 900,000 ppm, the DST testing results were still far from expectation. In order to eliminate the impact of reservoir pollution caused by drilling fluids, series of stimulation operations such as pickling and large-scale fracturing (calculated crack length 75 meters) were conducted to well Bel-E-1 after it was cased. Nevertheless, the testing results only received 4.8 m3/d of oil and 5800 m3/d of gas, which were still below the threshold for economical benefit. By analyzing existing well data and testing results, experts believe that it is difficult to make an exploration breakthrough by using conventional drilling technology in such a reservoir with poor physical properties, so some other solutions are in need. After more than six months of in-depth research and repeated demonstration, CNPC decided to use underbalanced drilling technology to tackle the block's exploration problems, which has been proved entirely correct finally. On July 25, 2008, the underbalanced horizontal well Bel-Z-1 was tested with 24/64"(9.5mm) choke for the Devonian Siegenian layer, and a result of 9.71×104 m3 of gas and 15 m3 of condensate oil achieved under the WHP of 1314psi. This paper reviews challenges encountered in designing and constructing the well Bel-Z-1 and related solutions so as to share our experience with the industry.
An Analysis of the Performance of Gravel Packs and Slotted Liners in Heavy Oil Operations
Authors: Akhimiona Nosa , Gorham Timothy , Auffant Ariel , Harrelson Jonathan
Published: July 2010

As hydrocarbon prices continue to fluctuate, it is imperative for engineers to come-up with optimum and cost effective ways of managing and developing a field. This is especially true in heavy oil operations, where the margins are very small. So it is pertinent to gain a better and broader understanding on how completion techniques can be optimized to gain the maximum value for companies.

This work presents an analysis/evaluation of gravel packs and slotted liners in a heavy oil field in California. The objective of this work is to compare gravel packs and slotted liners from a production and sand control standpoint. This work also has a secondary objective of re-evaluating the performance of old gravel pack wells that have been sidetracked using slotted liners.

The result of this work indicates that there is not a "one size fits all" solution to the problem of sanding in the field. So, it is imperative that all feasible completion techniques be analyzed and their impact on production and economics be considered. The conclusions and recommendations from this study will provide an insight through which Petroleum Engineers in heavy oil operations will make educated decisions on how to optimally complete a field and also obtain the most value for the investment.