bluuebunny/crossref_metadata_2025 huggingface dataset:
Modeling Well Performance for Fractured Horizontal Gas Wells
Authors: Lin Jiajing , Zhu Ding
Published: July 2010

In tight gas reservoirs, horizontal wells have been used to increase reservoir contact and hydraulic fracturing has been applied to further extend the contact of the reservoir. Point source solution has been used to describe the flow behavior. The method was advanced to the volumetric sources, and pressure change inside the source was considered. We have developed a method that can predict horizontal well performance, and the model can also be applied for fractured horizontal wells. The method solves the problem by superposing a series of slab sources under transient or pseudo-steady state flow conditions. The principle of the method comprises calculation of the semi-analytical response of a rectilinear reservoir with closed outer boundaries. The slab source approach assigns the source a geometry dimension, similar to the volumetric source method, but has the solution similar to the point source method by neglecting the effect of the flow inside the source. When solving the source problem the pressure/flow effect inside source is considered sequentially by superposition principle over multiple sources.

The pressure response is integrated over time to provide continuous pressure behavior. Flow effect inside of fractures can be studied by dividing the fracture into several segments, and each can be treated as a slab source. The method is validated by comparison with the results of analytical solutions of horizontal wells with uniform flux and infinite conductivity, and fractured wells with uniform flux, finite or infinite conductivity. The method provides an effective tool for horizontal well design and well stimulation design for gas reservoirs.

In this paper, we present the details of model development. The examples will be used to illustrate how the model can help to optimize wellbore and fracture design. The method in this paper is more accurate compared with conventional point-source solution, and can handle the transaction from transient flow to pseudo-steady state flow smoothly. The results of the study show that in low permeability formation, hydraulic fracturing has more impact on horizontal well performance.
Drainage Mechanism of Steam with Solvent Coinjection under Steam Assisted Gravity Drainage (SAGD) Process
Authors: Li Weiqiang , Mamora Daulat D.
Published: July 2010

Coinjecting solvent with steam under steam assisted gravity drainage (SAGD) process to reduce the required steam for production has gained importance in recent years. An extensive 2D simulation study to better understand the drainage mechanism of steam with solvent coinjection in the SAGD process shows that the relative condensation times of solvent and steam result in different films of gas solvent, liquid solvent, and water along the fluid interface. There is an optimal solvent type and concentration ratio range for a particular reservoir and operating condition. The solvent stays in or approaches the liquid phase ahead of steam along the fluid interface. Coinjecting the solvent at low concentration ratios can take advantage of the solvent solubility effect without losing too much heat effect from steam. In addition, this study indicates coinjection of suitable solvent mixtures leads to better performance than injection of pure solvent in the field.
Method and Utility of Well Productivity Estimation during Drilling
Authors: Zhang Lingyu , Jalali Younes
Published: July 2010

In this paper we describe two possible use cases of well productivity estimation obtained during the reservoir drilling process. The first concerns estimating a minimum and maximum value for the remaining reservoir footage that is required (beyond bit position) to achieve a target Productivity Index for the well. Thus the only criterion is well productivity not cost. The second concerns deciding within a pre-defined window the termination point of the well based on operator's cost-benefit criteria. The paper emphasizes description of use-case rather than description of the detailed methodology for obtaining these estimates. This is because feedback is required from teams involved in planning and execution of development wells on realistic and worthwhile use-cases, before deciding which option for productivity estimation is most appropriate and most efficient. In this paper, we present a basic method and simple examples based on synthetic data and mathematical solutions available in the literature. We place this in the context of reservoir drilling operations and decision-making.
A New Approach for Casing Program Design with Pressure Uncertainties of Deepwater Exploration Wells
Authors: Guan Zhichuan , Ke Ke , Lu Baoping
Published: July 2010

In exploration wells, particularly in deepwater exploration wells, the information regarding formation pressure has many uncertainties because of the lack of seismic data, logging data and daily drilling report. The present casing program design methods based on the deterministic formation pressure data did not take these uncertainties into account and the results could not satisfy field engineering requirements. This paper describes a method based on probabilistic theory for determining the formation pressure profile with credibility, and a new approach for casing program design has been also introduced. As a result, the formation pressure is not a deterministic value but a range with probability information, as the same with the casing set points selection. And then we describe a quantitative risk analysis method for quantitatively analyzing the risk of the casing point selection design. The model includes four sub-models for determining the quantitative risk due to lost circulation, kicking, collapse and sticking. The results can provide valuable information for designers. In one case study, we illustrate how this approach allows us to compute formation pressure profile with credibility and casing set points for a deep well with formation uncertainties. The risk of several casing program of this well has also been discussed finally.
Numerical Simulation of Subsea Wellhead Stability for Deepwater Drilling
Authors: Guan Zhichuan , Su Kanhua , Qing Chong , Su Yinao
Published: July 2010

Subsea wellhead bearings complex stress because it joint with the marine riser and casing string. According to mechanical analysis of subsea wellhead for deepwater drilling, a comprehensive stability of subsea wellhead analysis method was established. The marine environmental loading, drilling vessel drifting, riser mechanical behavior, nonlinear behavior between casing string and formation were considered. A numerical method was adopted to solve this model. Example analysis illustrates, in order to improve the condition of riser, riser top tension is ordinarily increased. The lateral displacement and bending moment of wellhead nearly linear enlarged with the mean drifting offset. The greater TTR may cause wellhead instability because of the wellhead has a limited bearing moment capacity, and then need to disconnect the LMRP and BOP connection promptly. The affection of lateral load is focus on the upper string section, more depth of casing string is almost no affecting on its lateral bearing capacity. With drilling vessel offset or TTR enlargement, the lateral displacement, bending moment, shearing force and the soil reaction along string increased obviously, and acting depth deepened gradually. The measures such as enhance the conductor bending strength, control scour depth on seabed, get geological data sampling of shallow formation can strengthen the stability performance of wellhead.
Hydraulic Pulsed Cavitating Jet Assisted Deep Drilling: An Approach to Improve Rate of Penetration
Authors: Li Gensheng , Shi Huaizhong , Niu Jilei , Huang Zhongwei , Tian Shouceng , Song Xianzhi
Published: July 2010

Hydraulic pulsed cavitating jet drilling is a new combined drilling technology. In this technology the hydraulic pulsed cavitating jet generator is installed upon the bit in the drilling process. Based on modulating pulsed jet and cavitating jet, a new drilling tool is designed which couples advantages of both pulsed jet and cavitating jet. When drilling fluid flows through the tool, fluid is modulated to pulse and cavitation. Thus, pulsed cavitating jet is formed at the outlet of the bit nozzle. Because of jet pulsation, cavitating erosion and local negative pressure effect, bottom cuttings cleaning efficiency is enhanced and the rate of penetration (ROP) is improved. This paper studied the mechanisms of improving the ROP and cuttings cleaning efficiency in hydraulic pulsed cavitating jet drilling. Hydraulic pulsed cavitating jet drilling technology has been applied in 8 oil fields in China, such as Tarim oil field, Xinjiang oil field, etc. The tests in more than 40 wells showed good applicability of the tool to bit types, formations, drilling fluid densities, etc. Hydraulic pulsed cavitating jet can mate with helicoid hydraulic motor and Power V system drilling technology, this technology also can be used in underbalance drilling. The test well depth is 1274 ~ 6162 m. As the result, ROP was improved by 10. 1 to 104. 4 percent and the maximum operation time is about 260 hours in wellbore. Pulsed and cavitating jet coupling can afford an effective approach to improve ROP in deep and ultra-deep well.
Flow Regimes and Transition Characters of the High Viscosity Oil-water Two Phase Flow
Authors: Wang Wei , Gong Jing
Published: July 2010

With the fast development of the offshore oilfield in china, field engineers are now facing with a new challenge, which is the flow assurance of crude oil-water two phases flow in the submarine pipeline. Since the existence of natural surfactants in the crude oil, as resin, asphaltene and etc, crude oil and water two phases tend to form stable water-in-oil (w/o) emulsion and therefore greatly influence their flowing characteristics, as flow patterns and transition characters and especially the pressure drop character.

These have shown obvious differences from the flow of mineral oil-water two phases, which are commonly and widely used for indoor experiments, even when the density and viscosity properties of the mineral oil and crude oil phase are approximately the same. For the guidance of the design and operation of the offshore crude oil-water pipeline, high viscosity mineral oil / crude oil-water two phase flow through horizontal pipe were conducted in a steel laboratory pipe loop (1 inch inner diameter, 52m length). Major similarities and differences are compared between their flow patterns and transition characters.
How Variable Fluid PVT Model Affects the Performance of an Integrated Production System
Authors: Nnochiri Michael , Lawal Kazeem A.
Published: July 2010

Contrary to general assumption, the composition and saturation point of a petroleum fluid system rarely remain constant throughout its production lifetime or transportation path. Consequently, for reliable forecasts of long-term system performance, the initial isothermal model describing the pressure-dependency of fluid properties may no longer be valid. This may warrant pressure-volume-temperature (PVT) model update(s). Ideally, such updates should necessitate regular re-sampling and re-characterisation of reservoir fluid (mixture). However, this may not be pragmatic because of frequency of changes, both between sampling periods and sampling points, in an integrated production system (IPS).

For an IPS, this paper investigates "possible" reference conditions for approximating these PVT variations without recourse to fluid re-sampling and re-characterisation, yet achieving reasonable results. Initial, bubble-point and abandonment conditions, as well as intervals between them, are studied as possible candidates. As a measure of relative performance of these approximate models, recoverable volumes (discounted and undiscounted) of oil, gas and water are compared against those whose hydraulic models are based on the full suite of initial PVT deck. A coupled subsurface-surface system of undersaturated black oil was studied.

By retaining the initial PVT model throughout the network, predicted oil recovery could be optimistic, up to 38% in this example. However, where a water injection scheme is implemented, corresponding volume of recoverable water could be significantly underestimated, as much as 40% in this example.

In conclusion, the effects of PVT variations might be significant, and for realistic simulation of life-cycle performances, it is recommended that such anticipated variations be incorporated, consistently and efficiently, for the reservoir, wellbore and other subsystems of an IPS. As a future work, the investigation should be extended to the more dynamic volatile oil and gas condensate systems.
Uniform Steam Injection Technology Used in Thermal Horizontal Wells
Authors: Pingyuan Gai , Yongxin Du , Guocheng Lu , Xiaonan Li , Zhiyong Luan , Shulan Li
Published: July 2010

Horizontal well technology is very effective to enhance oil production rate of single well in heavy oil reservoirs because of its large oil drainage area compared with vertical wells. However, since the influence of steam injection parameters and reservoir heterogeneity, length of steam absorption section in thermal horizontal wells is only 50m~70m by using conventional steam injection pipe string. Nowadays, length of completion section in thermal horizontal wells is generally about 200m, therefore controlled reserves in 130m~150m horizontal section can't be effectively produced by using conventional steam injection technology. In order to improve recovery effect of thermal horizontal wells, adaptive uniform steam injection technology is developed in Shengli oilfield. Based on studying and designing adaptive uniform flow regulator, steam injection parameters, number and arrangement of adaptive uniform flow regulators are optimized according to steam equipment capacity and reservoir properties, thus realizing uniform steam absorption in long horizontal sections. Reservoirs of whole horizontal section in thermal horizontal wells can be effectively produced and producing degree of controlled reserves in horizontal wells can be increased. Not only oil recovery rate of thermal horizontal wells is enhanced, but also oil recovery ratio.
The Use of Monte Carlo Simulation for Uncertainty Estimation in Gamma Densitometry Measurements
Authors: Arubi I. M. , Yeung H.
Published: July 2010

Measurement uncertainty is increasingly seen as essential in quality assurance for industry. The uncertainty associated with a value of a physical quantity provides a quantitative measure of the reliability and trustworthiness of that value. The ISO Guide to the Expression of Uncertainty in Measurement (GUM), which provides international agreed recommendations for the evaluation of uncertainty, recommends an approach based on the propagation of distribution using Monte Carlo Simulation (MCS). Uncertainty in multiphase flow measurement results from the uncertainty in the fluid density, phase volume fraction and velocity measurements.

In this work, the application of MCS as flow measurement uncertainty estimation method for gamma densitometry in multiphase flow is presented. A response database was obtained by pulling up Polyvinyl Chloride (PVC) ‘blobs’ in a static column of water/oil. Phase volume fractions and velocities measurement were obtained from the energy attenuation data of a caesium-137 radioisotope-based densitometer. MCS is then used to estimate the uncertainties in these measurements.

We present preliminary results and demonstrates the simplicity and reliability of this approach to uncertainty assessment. We opined that this method is suited for radiation-based metering technique because of its reliance on randomness, as such it does capture the natural stochastic process inherent in the interaction of gamma rays and multiphase flow.
Successful Application of the New Double-effect Protector in Deep Well Drilling
Authors: Zhu Xiaohua , Liu Shaohu , Shi Changshuai , Tong Hua , Nie Rongguo
Published: July 2010

This paper discusses a new double-effect protector (DEP). The serious wear of casing and drill pipe brings huge economic losses in drilling. On the basis of the traditional technology, a new DEP is designed, to reduce the wear of casing and drill pipe. The DEP's volume, which can be worn, increases 14% than the traditional protector's. As design and optimization by CAE software, the maximum stress, which is caused by the contacting collision&friction, is greatly lowered. As design and optimization by using CFD software, the fluid pressure loss of the DEP's annulus space, is decreased 17.5% than the traditional protector's. A new composite has been synthesized firstly, and has excellent mechanical performance, for example, abrasion resistant performance at high temperature. By using the Nonlinear Drillstring System Dynamics Simulation and Torque & Drag forecasting software, the study has been completed, which is about installed number and position of DEPs, for reducing wear on casing and friction on drill string in the typical deep well, and then the scheme, that the DEP is reasonably mounted, is applied while drilling. This document describes the first application of the DEP in X301 on Southwest oilfield, Sichuan, China. From the practice, the DEP's average working life has been enhanced 200 hours. Because of the use of the DEP, the wear of casing and drill pipe is effectively reduced, the quality of wellbore is improved, and the drilling period is shortened. The DEP and matching technology can provide effective technical support for deep well drilling and post-mining.
Cyclic Preheating Test in SAGD Horizontal Wells of Liaohe Oilfield
Authors: Songliang Peng , Aiwu Yuan , Hua Jiang , Shoujun Zhang
Published: July 2010

In the super heavy oil reservoirs of Liaohe Oilfield, the cyclic preheating of SAGD horizontal wells can only be achieved by mechanical lifting due to the deep burial depth and low formation pressure. The cyclic preheating of SAGD horizontal wells becomes even more complicated in terms of injection and production technology due to the limitation of wellbore space, the complexity of the wellbore structure of horizontal wells and the high temperature of produced fluids, leading to great difficulty in controlling the injection and production parameters. Therefore, the test was conducted to enable the injection/production ratio to be 1: 1, meeting the requirement in the reservoir design by optimal pipestring design, optimal selection of injection and production parameters and controlling the backpressure at the wellhead. At the same time, some supporting techniques, such as a new type of dual pipe wellhead for simultaneous injection and production and high temperature lifting technique have been developed, effectively ensuring the success of the cyclic preheating test of SAGD horizontal wells. By monitoring the temperature profile in the upper horizontal well, it was observed that more than 85% of the horizontal interval has been evenly heated. The success of the test has provided valuable experiences and strong technical support for conducting cyclic preheating of SAGD horizontal wells in similar reservoirs in Liaohe Oilfield and other oilfields in China, and even in foreign countries.
Simulations of Asphaltene Deposition in Submarine Pipelines by CFD
Authors: Hongjun Zhu , Jiaqiang Jing , Qingping Li , Xichong Yu , Junwen Chen
Published: July 2010

The transportation of heavy or waxy crude oils presents some special design problems, which must take into account the requirements for the control of asphaltene deposition on interior surfaces of the pipeline. With the asphaltene deposition of the crude oils, the effective cross-sectional area or flow passage of the pipeline will be shrunken continuously, which influences their flow properties and threatens their safe transportation. Therefore, the influence of asphaltene deposition on their flow properties should be known well to safely design and operate the pipeline. The focus in this paper is on the asphaltene deposition rate and the influence of the asphaltene deposition on flow properties.

Simulations of heavy crude oil flow in different structural pipelines after various deposition patterns are presented using 3D CFD. The flow velocity of heavy crude oil increases with the reduction of the effective cross-sectional area of the pipe, which leads to its vibration and shorter service life. In the other hand, pressure and temperature in the shrunken effective cross-sectional area decrease with the increase of velocity, intensifying the asphaltene deposition and transportation difficulty. While flow properties vary depending on deposition patterns, flow rates and the pipe geometry. So the influence of asphaltene deposition on flow properties in different structural pipelines with various deposition patterns is diverse. The impact of deposition in bending and reducer pipelines is greater than that in straight ones. And the impact in serious deposition pipelines is greater than that in slight deposition ones. So flow properties change drastically in bending and reducer pipelines with serious asphaltene deposition, leading to rapid blockage of the pipelines. The results of this paper can provide a guide for safe design and transportation of heavy crude oil pipeline.
Design of Water-based Drilling Fluids for an Extended Reach Well with a Horizontal Displacement of 8000m Located in Liuhua Oilfield
Authors: Jienian Yan , Jiaojiao Geng , Zhiyong Li , Deli Gao , Jianhua Wang , Shengying Zhao
Published: July 2010

Design of drilling fluids is crucial to extended reach drilling (ERD) with the challenges including borehole stability, hole cleaning, lubricity and equivalent circulating density (ECD) management. Normally, oil-based drilling fluids would be the best choice for an extended reach well with a horizontal displacement of 8000m. However, the Liuhua Oilfield is located in the South China Sea, an environmentally sensitive area. It is necessary to develop the high performance water-based drilling fluids which offer the performance to match oil-based drilling fluids.

The integrated design proposal of water-based drilling fluids for the well Liuhua 11-1-B3 ERW4 with a horizontal displacement of 8000m (26247ft) is discussed in this paper, including design criteria, the formulations and the parameters of performance of the drilling fluids in each interval of the well. The more attention is paid to the 12 1/4-in. open hole section, where a kind of high performance water-based mud (HPWBM) is prepared. The two newly developed chemical additives, an amine polymer and an aluminum complex, are added in the KCl/polymer drilling fluid which was successfully used in the extended reach wells with a horizontal displacement of 6000m in this oilfield. In addition, a membrane-forming agent is added in this mud system and an optimized combination of lubricants was used to improve the lubricity of the drilling fluid.

Numerous experiments were conducted to evaluate the various properties of this novel water-based drilling fluid. The experimental results indicate that it has excellent rheological properties, very low filtration rate, good lubricity and strongly inhibitive character to shale, which are very close to the commonly used oil-based drilling fluids.

The results of risk analysis show that the design proposal of this water-based drilling fluid is feasible and can meet the drilling requirements of ERD with a horizontal displacement of 8000m open hole section in this area with less pollution of the sea and without increasing more cost.
Mechanisms and Prevention of Damage for Formations with Low-porosity and Low-permeability
Authors: Jiaojiao Geng , Jienian Yan , Zhiyoong Li , Zhong He
Published: July 2010

The protection of target formations with low-porosity and low-permeability is an advanced research project in petroleum engineering and has important significance for the increase in reserves and production. Conventionally, the core flooding tests have been adopted for determining the mechanism of formation damage. However, the permeability is too low to be carried out the core flooding tests easily for this type of formations, furthermore, the typical core samples are hard to get in some reservoirs.

Focusing on the typical formations with low-porosity and low-permeability, the mathematical models for predicting five kinds of sensitivities of formations and the damage induced by water blocking quantitatively were established in this study on the basis of numerous experimental results, applying the theory of petrophysics and interfacial chemistry for reservoirs and the intelligent method of ANN (Artificial Neural Network).

The practical software has been developed to predict the degree of sensitivities and water blocking of formations, so as to determine the mechanisms of damage and guide the design of drilling fluids. This software is very convenient for use only by inputting the related formation parameters. It can be instead of the complicated and time-consuming laboratory tests. Extensive applications show that more than 85% of predicted results are in agreement with the measured results, indicating its satisfactory reliability.

In this study, the methods for preventing the damage caused by water blocking effectively have been discussed by virtue of selecting proper surfactants. In addition, the novel drilling fluid suitable for protecting the reservoirs with low-porosity and low-permeability are developed.
Pressure Transient Analysis with a Dual Changing Wellbore Storage Model
Authors: Suzuki Ikkou , Nomura Masahiko
Published: July 2010

This paper presents a new model for analysis of changing wellbore storage during pressure transient testing. The model accounts for the combination of instantaneous change of wellbore storage with wellbore phase redistribution effects. Both wellbore effects are incorporated mathematically into a new solution of diffusivity equation. Type curves for various combinations of related parameters are generated to develop an insight into pressure transient behavior. The practical utility of the new model is demonstrated through application to the actual field data.
Successful Application of the Sand Removal Technique by use of Concentric Tubing Jet Pump in Karamay Shallow Heavy Oil Horizontal Well
Authors: Jia-huai Wang , Bin Xie , Xiang-jie Luo , Hong Zheng , Xin-ming Ma
Published: July 2010

The punched or slotted screen pipe is used for the well completion of the shallow heavy oil horizontal well in Xinjiang oilfield. But the sand is still produced significantly in some wells Because the permeability is high, the formation pressure is low, the oil sands cementation at normal temperature is strong, it is hard for the conventional hydraulic sand washing to shatter the oil/sand bed, the sand washing fluid is lost substantially, the sand carrier fluid cannot reverse out which cannot effectively remove the sand deposition in the horizontal section. Therefore, the Jet Negative Pressure Sand Removal Technique by Concentric Tubing and assorted tools were designed and developed. The computational software of sand-washing optimization was developed. The application results in 14 wells proves that this Technique can efficiently and completely remove the sand deposition in the wellbore of heavy oil horizontal well which solves the production reduction and off production problem caused by sand deposition along the wellbore in the heavy oil horizontal wells.
Operational Geological Uncertainties and Improvement Plan for 2km Dual-lateral Horizontal Well within Tight Gas Reservoir in Changbei Tight Gas Field, Ordos Basin, West China
Authors: Xiumei Gong , Kwong-Yin Soo , Wu Su , Singh Navpreet
Published: July 2010

Changbei field, as one of the largest onshore sedimentary basin in China, is situated at North Shaanxi Province, Ordos basin. The main tight gas reservoir deposits in the Upper Paleozoic, Lower Permian Shanxi clastic Formation (P1S2). The combination of 2km long single and dual-lateral barefoot horizontal wells is successfully used to drill from surface location "clusters" into the lower Permian Shanxi (P1S2) Formation to maximize the gas production. Several key geological uncertainties which control the optimal landing of the 12¼" well trajectory and placement of the 8 ½" hole in the reservoir along with the delivery of the 2 km horizontal well length have been identified: 1. Top reservoir prognosis, 2. Reservoir thickness prediction and 3. Spatial distribution of unstable carbonaceous claystone bodies within and along marginal reservoir areas. And relevant improvement plans that have been put in place to mitigate the operation challenges had been analyzed.
Wettability Alteration During Water Flooding and Carbon Dioxide Flooding of Reservoir Chalk Rocks
Authors: Fjelde Ingebret , Asen Siv Marie
Published: July 2010

In the presented work the wettability conditions of reservoir chalk plugs have been characterised after water flooding with formation water, after spontaneous imbibition and water flooding by sea water, and after the first cycle of water alternating carbon dioxide flooding (CO2-WAG). Core plugs from a fractured chalk reservoir in the North Sea were used in the experiments carried out at reservoir conditions. Easily accessible sulphate in the core plugs was removed before the core plugs were drained to initial water saturation by using the porous disc method. Wettability acquisition was then carried out using stock tank oil. The wettability conditions of the chalk plugs were characterised by the spontaneous imbibition of water and the water-wet area determined by the sulphate wettability test.

The water-wet area of reservoir chalk plugs water flooded by formation water was found to be rather small. The spontaneous imbibition of formation water was also rather low for companion core plugs. The prepared reservoir chalk plugs therefore appeared to be close to mixed-wet or preferential oil-wet. Sea water has earlier been found to improve the spontaneous imbibition of water into reservoir chalk plugs from the same field. After spontaneous imbibition and viscous flooding with sea water, the water-wet area of the core plugs was found to be on the average slightly larger than for the core plugs water flooded by the formation water. When the same core plugs were flooded with CO2, most of the oil was produced. After the following sea water injection, the water-wet area was found to be larger than before the simulated first cycle of the CO2-WAG flooding.

During long term spontaneous imbibition experiments followed by viscous water flooding by sea water, slightly alteration of the wettability conditions towards more water-wet was observed. In the first cycle of a CO2-WAG process, the reservoir chalk plugs were found to become even more water-wet. Alteration of the wettability conditions to more water-wet during CO2-WAG processes can be important for the oil recovery in fractured chalk reservoirs, and should therefore be studied further.
Innovative Drag Reduction of Flow in Rock's Micro-channels Using Nano Particles Adsorbing Method
Authors: Di Qinfeng , Shen Chen , Wang Zhanghong , Jing Buhong , Gu Chunyuan , Qian Yuehong
Published: July 2010

Water injection is one of the main means of improving oil recovery in oilfields where high injection pressure or low injection rate is the main problem meted. In order to exploit low permeability reservoir more efficiently, the reservoir reconstruction methods which reduce drag by amplifying pore size, such as acidification, hydraulic fracturing, are used widely. The existent problem is the possibility that the reservoir may be contaminated. Then the surface modification methods, which decrease surface tension of micro-channels, have been used in oilfield. In this paper, an innovative drag reduction method is put forwarded to decrease the drag of laminar flows of water through rock's micro-channels and then decrease the injection pressure of flooding significantly. The solution containing hydrophobic nanoparticles(HNPs) of SiO2 is injected into the micro-channels of reservoir and the HNPs are adsorbed to the wall to form a strong or super hydrophobic layer, which can lead to a slip boundary condition and decrease drag on the fluid. This mechanism has been modified with a series of experiments and simulation methods by the authors. The Scanning Electron Microscope (SEM) pictures show that a hydrophilic wall can adsorb hydrophobic nano-particles tightly and the contact angle pictures of the new surface validate that the hydrophilic wall has been turned to a strong or super hydrophobic surfaces. The core displacement experiments show that the flow resistance through nano-particles adsorbing rock's micro-channels can be reduced greatly, and about 47% of the water-phase effective permeability (WPEP) of the rock samples on average for all four core samples have been gotten, and this means that a slip effect has been made by nano-particles absorbing method. The simulation with lattice Boltzmann Method (LBM) shows that a large slip length of 0.102μm is obtained. Three oilfield tests show that the maximum injection pressure of 12.5 MPa has been dropped and this method will have good application in the development of low permeability oilfields.
Use of CO2 Containing Impurities for Miscible Enhanced Oil Recovery
Authors: Wilkinson John R. , Leahy-Dios Alana , Teletzke Gary F. , Dickson Jasper L.
Published: July 2010

When conducting enhanced oil recovery (EOR) projects, utilizing CO2 as a solvent, there are three primary options for sourcing the CO2 injectant. These are naturally occurring deposits, anthropogenic flue gas capture, or recycled CO2 from an earlier stage of an EOR project. All of these sources may contain impurities that will change the properties of the injectant, potentially impacting all stages of the system. For instance, captured flue gas may contain quantities of N2, while produced or recycled sources may contain CH4 and/natural gas liquids (NGL). Either or both may contain SO2 or H2S. Each of these impurities has a different effect on the thermodynamic and fluid flow characteristics of CO2; exhibiting either beneficial or detrimental impact on miscibility, density and viscosity of the injectant and its interaction with in situ hydrocarbons. Impurities can also modify compression capacity, corrosion control and pipeline specifications. This paper describes the impact of CO2 impurities on all stages of an EOR project, from CO2 capture to flood efficiency prediction.

Miscibility, density, and viscosity, along with rock properties, are the primary determinants of flood efficiency in a given rock and fluid setting. A screening tool has been developed to estimate EOR performance for different crude oils. Screening is done for miscibility, density, and viscosity and other parameters important to the efficiency of an EOR process. A key component of the screening tool is a solubility-parameter-based approach to screening CO2 injectants containing impurities for miscibility against a range of crude oils. This technology, combined with worldwide operating experience, has been used to evaluate EOR potential in reservoirs across a full range of pressure, temperature, and fluid compositions. By accurately evaluating the impact of impurities in the injectant, it is also possible to estimate an economic optimum solution for securing and utilizing an injectant supply without incurring the additional costs of treating the stream to remove and dispose of all impurities.

By way of a field example, the paper discusses the impact of miscibility, density and viscosity on the efficiency of the CO2 miscible EOR process. It also presents investigations aimed at extending current light oil recovery projects into reservoirs with either residual oil zones (ROZ), viscous oils or biodegraded crudes.
Scale Management Strategy and its Results in a Giant Deepwater Oilfield in Campos Basin
Authors: Gomes R. M. , Deucher R. H. , Aniceto P. H. , Silva F. A. , Prais F. , Skinner R.
Published: July 2010

Scale occurrence in a giant oilfield located in deepwaters off the Brazilian coast required the implementation of strategies to remediate and prevent scale formation, which was a cause of significant production loss in the field. To prevent scale formation, inhibitor squeeze treatments have been utilized since 2006, when two squeeze treatments indicated an inhibitor lifetime lower than the predicted from laboratory tests. The inhibitor used is derived from the phosphonic acid, making it possible to analyze the inhibitor concentration in the produced water, and consequently, determine its lifetime. Despite the lower lifetime, the wells did not show any production loss, even when inhibitor concentrations were lower than the minimum inhibitor concentration (MIC), determined in laboratory tests. Throughout 2007, due to operational and contractual concerns, it was not possible to perform the squeeze treatments. Consequently, by the end of that year, production losses were verified. In 2008, the inhibition campaign was restarted, and based on the results of 2006 operations, the squeeze treatment volumes were recalculated, in order to obtain a higher inhibitor lifetime. As a result, it was possible to extend the treatment lifetime and maintain the production of the wells stabilized. Historic cases of three wells will be shown, emphasizing the extensive production loss verified when the treatment was not performed, the impact observed in the production when the treatment was delayed and the success obtained when the treatment schedule was accomplished. Beyond the scale occurrence in the production wells, there are also severe scale problems in the production facilities, which will be discussed in this paper. This work describes and details the scale monitoring, prevention and remediation strategies employed in this field, exposing the results obtained, as well as the learned lessons and opportunities to improve the scale management strategy.
Numerical Simulation Studies of Gas Production from Natural Hydrate Accumulations Using Depressurize Technology
Authors: Dou Bin , Jiang Guosheng , Qin Mingju , Wu Xiang , Gao Hui
Published: July 2010

The objective of this study is the analysis of gas production scenarios from gas-hydrate-bearing zone. The zone is characterized by a 15-m-thick hydrate accumulation, the base of which marks the bottom of the hydrate stability zone. The temperature at the bottom of the hydrate layer is 13.5°C, the gas hydrate equilibrium temperature at the formation pressure of 10.7 MPa. The gas hydrate interval has a hydrate saturation SH=0.7, the rest being gas. The analysis of the production scenarios in this paper were conducted using the TOUGH+HYDRATE general-purpose simulator for multi-component, multiphase fluid and heat flow and transport in the subsurface with the EOSHYDR HYDRATE module. Using numerical simulation, we estimate the rates of gas production and gas release from hydrate dissociation, the corresponding cumulative volumes of released and produced gas in single hydrate exploitation well that production gas using depressurize technology. The results of this study indicate that, the decomposition speed of gas hydrate is from high to small, and the process is cycle. The general trend of gas volume production from hydrate is increasing. So as to keep the gas volume stable of gas production from gas hydrate, a certain degree of heat should be added to the gas hydrate production well cyclically in accordance with design parameters. The results of study provide a theory and technical foundation for natural gas hydrate mining able and economic evaluation.
Reservoir Characterisation of the Mio-Pliocene Reservoirs of PM301 in the North Malay Basin
Authors: Carney S. , Abd Aziz I. , Martins W. , Low A. , Kennedy J.
Published: July 2010

Block PM301 is located in the north Malay Basin adjacent to the Malaysia Thailand Joint Development Area (MTJDA) gas hub. Seven gas fields have been discovered in the block to date. In order to move the project through the production value chain, an integrated subsurface study was carried out to gain a deeper understanding of the fields’ potential and an insight into how to optimally develop these complex reservoirs.

The PM301 fields will be challenging to develop as they are relatively small (typically 200Bcf each, GIIP) and geologically complex, associated with deposition in a fluvial to shallow marine setting. There are also petrophysical issues, including fine scale reservoir heterogeneity, complex mineralogy and low-resistivity low-contrast pay. Seismic interpretation is challenging due to shallow gas, the presence of coal and resolution of thin reservoir intervals.

A detailed, integrated data gathering and interpretation effort involved the development of a depositional model, a stratigraphic layering scheme, definition of key depositional and lithofacies and a reservoir characterisation study. Reservoirs have been characterised in terms of rock types and pore types based on petrographic and core analysis data which have been combined with detailed log evaluations to determine potential flow units, baffles and barriers. Detailed analysis of rock property data tied to seismic is one of the most important aspects of the project.

Key lessons learnt include the importance of acquiring good subsurface rock data and the need for meticulous seismic interpretation in order to filter out acquisition artifacts and optimise the data. Also, the application of Lorenz plots and Winland R35 analysis, calibrated to test data provided key rock quality and heterogeneity information. This study and the techniques applied have application in other complex fields.
A Multi-Segment Multiphase Wellbore Model Associated with Dynamic Gridding
Authors: Dong Chao C. , Bahonar Mehdi , Chen Zhangxin , Azaiez Jalel
Published: July 2010

As more and more wells have been put in operation, an accurate modeling of wellbore flow plays a significant role in reservoir simulation. One requirement of a wellbore model is its ability to trace various flow boundaries in the tubing, such as due to phase or flow regime changing. A black oil multi-phase multi-segment dynamical wellbore flow model has been coupled into Stanford's General Purpose Research Simulator (GPRS), which has the capability to simulate the isothermal black oil reservoir model to obtain detailed information on such important quantities as flow pattern and mixture velocity in any specific location of wellbore. A significant problem in this case is how to calculate fluid and velocity properties with a fine grid (segment) on the boundaries of different flow regimes in the wellbore. Local dynamical segment refinement in the well can accurately and effectively handle this problem. This wellbore model includes mass conservation equations for each component and a general pressure drop relationship. The multiphase wellbore flow is represented using a drift-flux model, which includes slip between three fluid phases. The model determines the pressure, mixture flow velocity and phase holdups as functions of time and the axial position along the well or alleviation depth. In addition, this model is capable of generating automatically adaptive segment meshes. We apply the black oil model to simulation of several cases on dynamical local mesh refinement isothermally, and compare the results with fixed coarse and fine meshes. The experiments show that using local segment refinement can yield accurate results with acceptable computational time.
Borehole Stability Challenges in Gas Drilling: Case Studies in West Sichuan Basin
Authors: Li Gao , Meng Yingfen , Liu Houbin , Zhou Yuliang , Zhu Yixin
Published: July 2010

Tight sand gas reservoirs in west Sichuan basin are deeply buried, about 3 to 5 kilometers. They are easily damaged during conventional drilling, and the drillability of the mid-depth sand shale layers is poor. Air drilling and nitrogen drilling are selected to improve ROP and protect formation. However, the borehole stability is a big problem through several pilot gas drillings. In this paper, combined lab investigations with pilot drilling information analysis, it is found that the complex geologic conditions and drilling operations lead to at least four kinds of borehole instability. First, the lithology varies frequently in longitudinal section and the weak argillutite alternate layers rate more than 50% thickness of the whole profile, which leads to mechanic instability problem. Next, drilling open of abnormal high pressure gas layers leads to second wellbore stress distribution, which results in sandstone avalanche and adjacent argillutite layer collapse. Third, wellbore enlargement is common due to breakage of deep friable hard shale layers. At last, aqueous phase invasion due to drilling operation or formation water production from lower layers leads to swelling and weakening of argillutite formation, which results in borehole collapse and sticking. According to such mechanisms, gas drilling borehole stability prediction methods were presented and proved to be helpful to successful gas drillings in this area.
Case Study: The Sand Management and Control Techniques for Complex Fault-Block Reservoir in Gangxi Oilfield
Authors: Jianwen Yan , Yurong Zhang , Yuzhang Liu , Chunming Xiong , Jiandong Liu , Hanbing Xu , Qiqing Han
Published: July 2010

Gangxi Oilfield is a typical complex fault-block oil reservoir which belongs to unconsolidated sandstone reservoirs with high porosity and high permeability. Sand producing, sand jamming and sand bearing are serious problems for most producers in this field during oil production. With the increase in water cut, the sand producing problem is getting worse which seriously impacts normal production of oilfields. According to the statistics for Gangxi Oilfield in the last two years, there were 283 wells with serious sand producing problem, among which 274 had to stop production because of sand producing and sand bearing. The average sand production of single well was 6.96 m3 under inspection operation from the statistics of 73 wells. Based on the locations of producing zones, frac-pack was chosen as the main sand prevention technique for the wells through Minhua formation, circulating packing for the wells through Guantao formation, chemical sand control for horizontal wells and sidetrack drilling wells, and packing layer by layer for the multilayer-section production and long-hole section. By selecting the sand control techniques and optimizing the parameters for Gangxi Field, a scientific basis was laid down for the sand management, and it was applied succefully in the field.