综合利用测井资料评价油气层--以克拉玛依石南油田为例

在论述测井方法和适用条件的基础上，结合石南21井区头屯河组油藏地质特征，探讨了如何利用测井资料识别和定量评价油气层的方法。通过对阵列感应测井的应用效果分析，特别是结合泥浆滤液侵入分析，研究油、水层的测井响应特征，提出了利用测井资料快速、直观判断油层的方法；应用“岩心刻度测井”方法，采用统计分析技术，建立的油层定量评价模型在油藏精细评价和开发井测井解释中得到了应用，提供了精确的油层参数；在油藏的油水分布研究中，通过多口井的地层压力测试（MDT）资料，建立油藏压力剖面及确定储集层中流体密度参数，结合常规测井和试油资料等综合分析，准确地确定了油藏的油水界面。     

Analysis of pressure and pressure derivative without type curve matching, 4. Naturally fractured reservoirs

An alternative method, referred to as direct synthesis, is proposed for interpreting pressure transient tests in naturally fractured reservoirs. This new method offers consistent and accurate results from pressure tests with or without all reservoir flow regimes observed during the test period.Direct synthesis utilizes the characteristic intersection points and slopes of various straight lines from a log-log plot of pressure and pressure derivative data. Values of these points are linked directly to the exact, analytical solutions to obtain reservoir or well parameters. The direct synthesis method offers the following advantages: (1) accurate results from using the exact, analytical equations to calculate reservoir parameters; (2) independent verification is frequently possible from a third unique point; and (3) useful information is obtained when not all flow regimes are observed, as a direct result of the additional characteristic values developed by the method.Application of this technique is presented for single-well pressure tests in an infinite-acting naturally fractured reservoir with pseudosteady-state interporosity flow. Both the effect of wellbore storage and skin are included in the analysis. New analytical and empirical expressions were developed as a result of this work. These expressions are an integral part of the technique and provide the desired accuracy and versatility.Several field examples are given to clarify the technique and also illustrate the accuracy acquired by the method. When possible, a comparative analysis with other methods is included.     

Analysis of gas well late-time pressure and rate data

This work presents new methods for estimating average pressure, reservoir pore volume (initial gas in place) and drainage area from pressure and rate data obtained at a gas well during boundary-dominated flow. The methods, which utilize a combination of a material balance equation and approximations for the wellbore pseudopressure or flow rate obtained during boundary-dominated flow, represent an improvement over previous methods in that the new methods are direct procedures which do not require iteration.     

Estimating in-place volume and reservoir connectivity with real-time and periodic surveillance data

This paper demonstrates the value of collecting and interpreting real-time data. With an intensive data gathering strategy, starting at wells' inception to the mature production phase, we show how transient pressure and rate data can be used to manage a complex carbonate gas reservoir. In particular, reservoir connectivity is discerned with pulse testing and with the leading-edge p/q graph, and continuous updates of in-place volume are made with both static and dynamic material-balance methods and corroborating the same with rate-transient analysis.Interwell connectivity information was deduced during underbalanced drilling by way of interference test between two pairs of wells. Thereafter, transient-pressure tests on individual wells characterized the layered, dual-porosity system, with production logs corroborating the notion of layering. Production maturity over three years has paved the way for estimating connected in-place gas volume associated with each well using the transient-PI, and also with a new method introduced here. This new approach entails plotting both static and dynamic material-balance data on the same graph, yielding the same solution.Errors associated with real-time rate measurements presented interpretation challenges for rate-transient analysis; however, application of a physics-based filtering algorithm resolved this issue. Flow-after-flow tests that were embedded in monthly variable-rate production allocations, in turn, allowed us to obtain average-reservoir pressure explicitly to do the static material-balance analysis.     

Application of TDS technique to developed reservoirs

Well test interpretation methods for a single well in infinite reservoirs may not be suitable for those wells when their pressure is affected by other wells operating in the same reservoir. This effect becomes more significant as both the flow rate and the test duration increase. It is observed in drawdown tests when the well experiences an additional pressure decline due to production from other wells and, also, when the well produces under pseudosteady state before shut-in it for a buildup test. When pressure data are interpreted as recorded, estimation of reservoir parameters may not be accurate. Slider1–3 introduced a technique for analyzing a pressure test that takes into account the effect of nearby active wells. Corrected or extrapolated pressures are obtained by applying the superposition principle to include the pressure decline contribution from the neighboring wells. Traditional semilog plots are then constructed and permeability and skin factor can be estimated, respectively, from the slope and intercept of their linear trend.A new technique, called TDS (Tiab's Direct Synthesis), was designed to analyze pressure and pressure derivative data without using type-curve matching. It uses characteristic features found on the derivative plot, so reservoir parameters are directly estimated. It depends upon how well the pressure derivative is calculated. If derivative is taken to the recorded pressure data the resulting curve will not be properly defined and the estimated parameters may be erroneous. Application of the TDS technique to wells in depleted reservoirs is presented here. The recorded pressure is extrapolated to include the contribution from other wells as suggested by Slider. Once the pressure derivative of the extrapolated data is taken, the TDS technique as discussed by Tiab [Tiab, D. 1993. Analysis of Pressure and Pressure Derivative without Type-Curve Matching: 1- Factor de daño and Wellbore Storage. J. Pet. Sci. Eng. 12 (1995), 171–181.] can be readily applied. It was successfully tested with synthetic and field examples. A comparative analysis was carried out to see the effects when derivative is taken to uncorrected pressure data and the estimation of permeability, skin factor and drainage area.     

多重复合低渗透油藏注水井压力动态分析

低渗透油藏岩性发育不均匀,常表现为多重复合油藏特征。这一特点难以从油井测试资料中观察到,而在水井测试资料却有所反映。水井测试资料曲线往往存在后期多次上翘现象,而显示出油水井间的地层特点。但是,对这些资料的解释具有一定难度。在前人研究的基础上,建立了多重复合油藏试井理论模型,研制出理论图版,分析了压力动态特征。文中列举出油水井对应测试的分析实例,以此说明加强低渗透油藏注水井压力动态分析的必要性。     

塔河油田四区缝洞性油藏缝洞单元划分方法研究

随着塔河油田奥陶系油藏的开发,划分缝洞单元的重要性逐渐的表现出来,而缝洞型碳酸盐岩油藏缝洞单元的划分方法没有统一模式,文章通过实例列举出了三种方法,分别是地层压力趋势分析法、井间干扰试井法、示踪剂检测法等.利用这些方法将塔河油田进行单元划分,为指导油藏开发提供了一定的依据.     

气井产能分析方法研究

用常规方法处理产能测试数据时,发现许多气井的井底压力测试数据很难达到常规气井产能分析方法的基本要求：每改变一个工作制度(每改变一次产量),气井的井底压力应达到稳定后才能测试压力,可是,达到“拟稳定流状态”比较难。这就使得测试压力与达到稳定时的压力有一定的误差,针对这种情况,提出一种新的分析方法,该方法引入测试点的误差值,建立带约束条件的优化模型,从而获得可靠的结果。该方法克服了测试中需要长时间达到稳定状态这一限制,同时可以缩短测试时间,对低渗透储层特别适用。通过实际资料处理与对比分析,验证了该方法的实用可靠性。     

Correction of source-rock permeability measurements owing to slip flow and Knudsen diffusion: a method and its evaluation

Source-rock permeability is a key parameter that controls the gas production rate from unconventional reservoirs. Measured source-rock permeability in the laboratory, however, is not an intrinsic property of a rock sample, but depends on pore pressure and temperature as a result of the relative importance of slip flow and diffusion in gas flow in lowpermeability media. To estimate the intrinsic permeability which is required to determine effective permeability values for the reservoir conditions, this study presents a simple approach to correct the laboratory permeability measurements based on the theory of gas flow in a micro/nano-tube that includes effects of viscous flow, slip flow and Knudsen diffusion under different pore pressure and temperature conditions. The approach has been verified using published shale laboratory data.The ‘‘corrected'(or intrinsic) permeability is considerably smaller than the measured permeability. A larger measured permeability generally corresponds to a smaller relative difference between measured and corrected permeability values. A plot based on our approach is presented to describe the relationships between measured and corrected permeability for typical Gas Research Institute permeability test conditions. The developed approach also allows estimating the effective permeability in reservoir conditions from a laboratory permeability measurement.     

A QUALITY CONTROL SYSTEM TO REDUCE UNCERTAINTY IN INTERPRETING FORMATION PRESSURES FOR RESERVOIR AND BASIN PRESSURE SYSTEM ANALYSIS

Downhole formation pressure data can be difficult to obtain and the quality of the data produced varies significantly with age, tool type and geology. Furthermore, even if a new well is characterised effectively and high quality data obtained, the radius of investigation is small compared to the size of the area typically being assessed. Nevertheless, understanding the subsurface formation pressure system is a prerequisite for any basin or reservoir evaluation during exploration, appraisal and production. It requires integrating pressure and subsurface data from spatially disparate wells, and requires direct, quantitative comparison of historical and contemporary data‐sets. This comparison needs to be objective, repeatable and robust. This paper describes a qualitative system for systematically and objectively comparing all types of formation pressure measurements to provide a basis for a qualitative interpretation of the subsurface formation pressure system. The application of the system consists of a set of questions designed to assess the quality and quantity of formation pressure data available from information in the well completion report. Each question defines quantitative limits for key pressure test parameters that determine the quality class of the formation pressure of that test. The questions require a ‘yes’ or ‘no’ answer, and the cumulative set of answers results in a code that reflects the overall quality of the data. The resulting set of codes can be used directly or can be further subdivided into a set of five reliability classes. The system does not assess the accuracy of an individual pressure test, but provides a context for meaningful comparisons to be made of formation pressure data acquired under spatially and temporally disparate conditions. This allows for an interpretation of the data to be made that accounts for the variable reliability of individual data points. The system is generic and can be applied to any basin, onshore or offshore. It is suitable for field‐scale studies up to basin‐scale studies and can be applied to producing or non‐producing data. This paper outlines the underlying principles and the methodology required to apply the quality code system. It includes examples of how application of both the quality codes and the reliability classes can simplify the interpretation of a scattered data‐set and provide tools to effectively communicate the results.     

利用生产数据确定低渗气藏单井合理产量

低渗气藏气井合理产量的确定是实现气藏稳产和提高采出程度的关键,但低渗气藏气井自然产能低,稳产期短,试井资料匮乏,给低渗气井合理配产带来较大困难.针对该情况,基于气井生产系统,将物质平衡方程与产能方程结合,通过生产数据建立多目标优化函数,并通过生产历史拟合确定出低渗气井的产能方程、单井控制储量和地层压力.在此基础上,考虑低渗气井的启动压力梯度、稳产时间、临界携液流量和外输压力等因素,建立了综合多种因素的低渗气藏合理配产模式.现场实际应用表明,该配产方法合理、可靠,对低渗气藏实际生产具有现实指导意义.     

A New Equation for the Determination of a Well Drainage Area in Naturally Fractured Reservoirs

Abstract

In reservoir study, the relationship between the reservoir performances and well bore is a key for any well completion design and well production optimization. In order to estimate the behavior of reservoir pressure with different production flow rates, the well drainage area is necessary. The well drainage area is estimated from well test under pseudo-steady-state production when the change of reservoir pressure with time is constant. The MBH method is used to estimate well drainage area and its shape in conventional reservoirs. But for the case of naturally fractured reservoirs, a small amount of research has been done on the determination of well drainage area and shape. There are a few limited methods to determine the drainage area of a well in naturally fractured reservoirs that have been presented in recent years. The authors compare the available methods with a new developed equation for determination of the drainage area of a well in naturally fractured reservoir. The presented new equation is easy to apply and it has high accuracy.     

The Estimation of Reservoir Brine Properties During Crude Oil Production Using a Simple Predictive Tool

Most oil wells eventually produce some quantity of reservoir brine (formation water) over their lifetime. Increased water production is usually indicated by a significant increase in the water to oil ratio (WOR) of the well. As the WOR of well increases, it causes costly added water handling, it reduces efficiency of the depletion mechanism, the afflicted well may be abandoned early, there can be loss of the total field overall recovery, and because reservoir brine (formation water) is corrosive its disposal becomes expensive. In this work, a simple Arrhenius type function is presented for estimation of reservoir brine (formation water) properties for temperatures above 30°C and salt contents between 5% and 25% by mass. An Arrhenius type function has been selected because it is easier than existing approaches, less complicated with fewer computations, and suitable for engineers. These expressions can then be incorporated into further calculations that require predictions of reservoir brine (formation water) properties as functions of temperature and salt content. Estimations are found to be in excellent agreement with the reliable data in the literature with average absolute deviation being around 0.09–2.6%. The tool developed in this study can be useful for the petroleum engineers to have a quick check on the reservoir brine properties at various conditions without opting for any experimental measurements. In particular, chemical and petroleum engineers would find the proposed approach to be user-friendly with transparent calculations involving no complex expressions.     

A general approach for deliverability calculations of gas wells

This paper presents a general and a simplified method for deliverability calculations of gas wells, which among other advantages, eliminates the need for conventional multipoint tests. The analytical solution to the diffusivity equation for real gas flow under stabilized or pseudo-steady-state flow conditions and a wide range of rock and fluid properties are used to generate an empirical correlation for calculating gas well deliverability. The rock, fluid and system properties, used in developing previous correlations found in literature, were limited to reservoir pressure, reservoir temperature, gas specific gravity, reservoir permeability, wellbore radius, well drainage area, and shape factor. Additional key properties such as reservoir porosity, net formation thickness and skin factor are included in this work to develop a more general dimensionless Inflow Performance Relationship (IPR). It is found that the general correlation, developed is this study, presents the observed field data much closer than previous ones found in the literature. In addition, based on the larger data set, an empirical relation to predict future deliverability from current flow test data is also developed.The two modified and general relations developed in this work provide a simple procedure for gas deliverability calculations which greatly simplifies the conventional deliverability testing methods. The required data can be obtained from a buildup test, or a single-point flow test, instead of an elaborate multipoint flow test. Further, the broad range of practically all rock and fluid properties used in developing the modified dimensionless IPR curves should cover the majority of the field situations generally encountered. The use of the modified dimensionless IPR curves, the pseudopressure formulation and the sensitivity analysis indicate a generality of the approach presented in this paper, irrespective of the gas reservoir system under study.     

Individual well flowing rate recovery from PDG transient pressure with either assigned daily rate or total cumulative production of the well or group of wells through wavelet approach

The advent of permanent down-hole gauge (PDG) makes the real-time reservoir monitoring and management possible, where the long term transient data can be processed to distill information about the reservoir through using recently developed wavelet transform algorithm. However, the key in analyzing the PDG data, particularly transient pressure, is to get the flowing rate history right during the pressure draw downs and build ups.In practice, the most available flowing rate data include assigned daily rate, total cumulative production of the well or group of wells with a measurement error tolerance at about ±10%. While multiphase down home rate data is rather expensive to have, the industry is desperately looking for ways to get the flowing rate history right.The second big problem in analyzing long term PDG data is that there is a time shift between the flowing rate and the corresponding transient pressure. In other words, when the rate goes up, the pressure also goes up instead of going down as expected. This caused a big problem in reservoir simulation, history matching and numerical well testing.This paper presents a technique based on the recently developed wavelet approach to recover flowing rate history directly from the measured PDG transient pressure, under the most common practical conditions described above.In this method, the exact timing of the rate change is identified through wavelet high frequency analysis. Then the rate and pressure are synchronized in every identified time intervals. Since the rate and the frequency amplitude of the transformed transient pressure are proportional, the real rate value in each time interval can be derived under the given common practical conditions.Both synthetic and field examples were used to demonstrate and further validate the developed technique, which showed very promising results.     

变流量不稳定试井技术在超深水平井中的应用

不稳定试井是了解油藏信息、获取地层参数的重要监测技术。目前油田通常采用的压力恢复、压力降落不稳定试井方法要求有一定关井期,对生产影响较大,在高产油井、高注水井中尤为突出,因此探索对生产影响小又能获得油藏信息的新型不稳定试井技术是非常必要的。通过塔里木哈得油田未饱和砂岩油藏超深水平井“变流量不稳定试井”探索实例,证实该技术理论成熟、应用条件明确、实施效果良好,是对水平井试井分析技术的丰富与发展,能有效兼顾生产,为开发调整提供有力技术支持,对油田高产稳产具有积极作用。     

GEOLOGICAL MODEL EVALUATION THROUGH WELL TEST SIMULATION: A CASE STUDY FROM THE WYTCH FARM OILFIELD, SOUTHERN ENGLAND

This paper presents an approach to the evaluation of reservoir models using transient pressure data. Braided fluvial sandstones exposed in cliffs in SW England were studied as the surface equivalent of the Triassic Sherwood Sandstone, a reservoir unit at the nearby Wytch Farm oilfield. Three reservoir models were built; each used a different modelling approach ranging in complexity from stochastic pixel‐based modelling using commercially available software, to a spreadsheet random number generator. In order to test these models, numerical well test simulations were conducted using sector models extracted from the geological models constructed. The simulation results were then evaluated against the actual well test data in order to find the model which best represented the field geology. Two wells at Wytch Farm field were studied. The results suggested that for one of the sampled wells, the model built using the spreadsheet random number generator gave the best match to the well test data. In the well, the permeability from the test interpretation matched the geometric average permeability. This average is the “correct” upscaled permeability for a random system, and this was consistent with the random nature of the geological model. For the second well investigated, a more complex “channel object” model appeared to fit the dynamic data better. All the models were built with stationary properties. However, the well test data suggested that some parts of the field have different statistical properties and hence show non‐stationarity. These differences would have to be built into the model representing the local geology. This study presents a workflow that is not yet considered standard in the oil industry, and the use of dynamic data to evaluate geological models requires further development. The study highlights the fact that the comparison or matching of results from reservoir models and well‐test analyses is not always straightforward in that different models may match different wells. The study emphasises the need for integrated analyses of geological and engineering data. The methods and procedures presented are intended to form a feedback loop which can be used to evaluate the representivity of a geological model.     

CORRECTION OF VERTICAL PERMEABILITY ESTIMATED BY HORIZONTAL-WELL PRESSURE TRANSIENT TEST ANALYSIS

Different data are required in order to establish a realistic reservoir model capable of predicting the dynamic field behaviour during the development stage of an oil field. Well testing is considered to be one of the most effective methods for obtaining these reservoir and wellbore data. Numerous analytical models are available and utilised in investigating vertical-well pressure transient tests, on the other hand, horizontal-well pressure transient tests have been considered as more difficult to analyse. In this work, well test data of a horizontal-well are simulated for homogeneous isotropic and anisotropic reservoirs and analysed in order to develop empirical correlations that rectify the vertical reservoir permeability estimated by well testing.     

水平井网渗流分析方法及其在油藏工程中的应用

将油藏工程中水平井网渗流作为复杂源汇边界矩形区域的流动,通过椭圆函数等多重保角变换求得其解析解,并得到渗流场的压力分布、流线分布及井产量。研究了纵向井距、横向井距、水平井段长度及其匹配关系对水平井产能和注水波及系数的影响,给出了应用本文方法和数据进行井网设计的实例,为油藏工程设计提供了直接的理论基础和应用依据。