Real Oilfield Research Articles

Fluid- and Rock-Property Effects on Reserves Estimation

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 148717, ’Effects of Fluid and Rock Properties on Reserves Estimation,’ by Kegang Ling, SPE, Zheng Shen, SPE, Texas A&M University, prepared for the 2011 SPE Eastern Regional Meeting, Columbus, Ohio, 17-19 August. The paper has not been peer reviewed. Precise reserves calculation is fundamental for production forecasting. Great efforts are made to obtain fluid and rock properties such as porosity, permeability, saturation, rock and fluid compressibility, viscosity, fluid gravity, gas z-factor, saturation pressure, reservoir pressure, and temperature. There is always uncertainty regarding the information because of instrument sensitivity and limitations, measurement error, environmental effects, sample interval, location, and how representative of the rock the sample is. A systematic study on the effects of fluid and rock properties on reserves estimation was conducted. Introduction Fluid and rock properties control the volume of original hydrocarbon in place and the recoverable oil and gas. Uncertainty and error exist because of the instrument sensitivity and limitations, measurement error, environmental effects, sample interval, location, and how representative of the rock the sample is. Measuring rock properties under reservoir conditions is very difficult. A synthetic field was built to study the effects of fluid and rock properties. It is an oil field with aquifer support. The initial reservoir pressure is above the bubblepoint pressure. Initially, five producers were drilled to produce oil. With time, reservoir pressure declined. As the reservoir pressure declined below the bubblepoint with production, solution gas was released from oil. When the gas saturation reached critical saturation, it began to flow with the oil and water. This three-phase flow in the reservoir represents the middle and late production periods. Model Description The simulation model divides the reservoir into 93×93×2 gridblocks. The reservoir is modified to an irregular shape by assigning zero porosity and permeability to gridblocks at the reservoir edge. To populate the rock properties, different porosities, permeabilities, depths, and pay thicknesses were assigned to each gridblock. Initially, a uniform oil/water contact divided the porous sand into oil and water zones. Pressure at datum was assigned such that pressure above and below the datum can be calculated according to in-situ fluid density. Initial water saturation was assigned to respect the real oil reservoir. Rock and water compressibilities were incorporated and were assumed to be constant at different pressures. Oil viscosity varied with the pressure because solution gas has a significant effect on it. Water viscosity was kept constant. Oil gravity, gas specific gravity, water specific gravity, formation-volume factor (FVF) for oil and gas, and solution-gas/oil ratio were assigned with values often found in real oil fields.

Development of a Single-Borehole Radar for Well Logging

An impulse-based single-borehole radar prototype has been developed for well logging. The borehole radar is comprised of subsurface sonde and surface equipment. An armored 7-conductor well logging cable is used to connect subsurface sonde and surface equipment which is well compatible with the other well logging instruments. The performance experiments of the prototype have been conducted in a test field. The results show that the prototype system is capable of detecting the target which is 8 meters away from the borehole. This radar prototype has been employed in a real oil field well with a depth of about 1600 meters. Compared with conventional resistivity well logging tools, the prototype system provides comprehensive well-bore formation analysis information. DOI: http://dx.doi.org/10.11591/telkomnika.v10i8.1629 Full Text: PDF

Fast Predicting of Water Injection Breakthrough Time by Percolation Theory

One particular practical problem in oil recovery is to predict the time to breakthrough of an injected fluid in one well and the subsequent decay in the production rate of oil in another. Because we only have a stochastic view of the distribution of rock properties, we need to predict the uncertainty in the breakthrough time and post-breakthrough behavior in order to calculate the economic risk. In this paper, we apply scaling laws from percolation theory to predict the distribution of breakthrough times that can be calculated algebraically rather than directly via very time-consuming numerical simulation of large number of realizations. The main contribution is to show that percolation theory, when applied to a realistic model, can be used to obtain the same results as calculated in a more conventional way but significantly more quickly. Specially, when the parameters of scaling law optimized, we found that a previously proposed scaling form for the breakthrough time distribution when applied to a real oil field is in good agreement with more time consuming simulation results. Consequently, these methods can be used in practical engineering circumstances to aid decision making for real field problems.

Prognostication of the anticorrosive activity in the series of pentenylarylamines and their industrial introduction

Quantum-chemical parameters and regression analysis were used to predict and synthesize a number of compounds with the highest inhibiting activity in the series of pentenylarylamines. For the compounds with the highest inhibiting activity, tri-2,4,6-(1′-methyl-2′-butenyl)aniline and di-2,6-(1′-methyl-2′-butenyl)-4-methylaniline, technical documentation was developed and their inhibiting activity in media as close as possible to real oilfield conditions were performed. On the basis of results of these tests, the given compounds are recommended for pilot tests.

Treatment of oilfield produced water by dissolved air precipitation/solvent sublation

Dissolved Air Precipitation/Solvent Sublation (DAP/SS) was used for treatment of simulated and real oilfield produced water to generate very fine bubbles which are necessary for effective separation. In this method micro bubbles produced by saturation of air in a pressurized packed column were released in an atmospheric column leading the bubbles to raise resulting trapped contaminants in the Gibbs layer around them to be removed by a layer of immiscible solvent at the top of column. The method was conducted to solutions including Benzene, Toluene and Chlorobenzene (ClB) as part of BTEX contaminants in produced water, mixture of them as simulated produced water and real oilfield produced water. Obtained results for Removal Efficiency (RE) has been compared with a mathematical model of separation process to determine the ability of the model to predict RE and the important operating parameters. Effect of pressure in packed column (4, 5, 6, and 7bar), salinity of samples and bubble size as important parameters on RE were examined. The results indicated positive effect of pressure and salinity on RE via reducing bubble size and increasing air flow rate in column. Furthermore the method was applied to a mixture of components to analyze effect of co-existence of components on RE. Presence of more than one component in the solution led to slower removal of contaminants due to limitation on number of bubbles. Also effect of DAP/SS system for TOG removal of produced water was investigated where RE of 70% achieved.

Catalytic Aquathermolysis Used for Viscosity Reduction of Heavy Crude Oils: A Review

The catalytic aquathermolysis becomes an important area for investigation to solve some of the problems during exploration of heavy crude oil. It has been reported in 1982 by Hyne et al. that metals can accelerate the aquathermolysis and thereafter the uses of several catalysts on this reaction have been studied. It is believed that superheated water passes heat to the hydrocarbon, and some asphaltene molecules are broken down by thermal heat to small molecules. Hence the viscosity as well as flow properties of heavy oil are improved. Moreover, the added heat provides driving force or pressure so that the viscous oils can flow easily and increases the oil production. When the catalyst is present on this reaction system, the viscosity is reduced very deeply. In general the catalysts employed for aquathermolysis are mineral, water-soluble, oil soluble, and dispersed catalyst. The viscosity reduction with these catalysts is in the order of mineral < water-soluble catalyst < oil-soluble catalyst < dispersed catalyst. It has also been found that during aquathermolysis, the saturates and aromatics increase while the amount of asphaltene and resin decreases. The use of different hydrogen donors on aquathermolysis also improves the quality of the heavy crude oil. The most commonly used hydrogen donor is tetralin. Moreover, when tetralin is used with a catalyst, the viscosity is also reduced more effectively. The use of catalysts in the real oil field indicates that the catalysts can substantially reduce viscosity and hence the catalytic aquathermolysis process can be used successfully for exploration of heavy crude oils. However, the oil soluble and dispersed catalysts are slightly more active than the water-soluble catalyst. The cost of the former two types of catalysts may be higher than the preparation cost of simple water-soluble catalysts. Therefore, more research is needed so that the catalysts can be used for this process more economically. Another problem is the efficiency of these catalysts in the oil field. The activity of the catalysts depends on the homogeneity of the temperature in the oil floor. When the superheated water is injected into the oil reservoir, the oil surface temperature is high. However, temperature is gradually lower on the depth of the oil floor, and hence the catalyst loses its activity. So, further investigation is also necessary to address this aspect.

Fractured reservoirs with fracture corridors

ABSTRACTOutcrop studies reveal a common occurrence of tabular zones of significantly‐increased fracture intensity affecting otherwise well‐lithified rocks. These zones, called fracture corridors, can have a profound effect on multi‐phase fluid flow in the subsurface. Using standard geo‐modelling tools, it is possible to generate 3D realizations of reservoirs that contain distributions of such fracture corridors that are consistent with observations, including the vertical frequency in pseudo‐wells inserted into the model at random locations. These models can generate the inputs to flow simulation. The approach adopted here is to run the flow simulations in a single‐porosity representation where the flow effects of fractures are upscaled into equivalent cell‐based properties, preserving a clear spatial relationship between the input geology and the resulting cellular model. The simulated reservoir performance outcomes are very similar to those seen in real oilfields: extreme variability between wells, early water breakthrough, disappointing recoveries and patchy saturation distributions. Thus, a model based on fracture corridors can provide an explanation for the observed flow performance of a suitable field. However, the use of seismics to identify fracture corridors is not an easy task. New work is needed to predict the seismic responses of fracture corridor systems to be able to judge whether it is likely that we can robustly detect and characterize these flow‐significant features adequately.

Study on attribute characterization for reservoir dynamic monitoring by seismic

Study on characterizing reservoir parameters dynamic variations by time-lapse seismic attributes is the theoretical basis for effectively distinguishing reservoir parameters variations and conducting time-lapse seismic interpretation, and it is also a key step for time-lapse seismic application in real oil fields. Based on the rock physical model of unconsolidated sandstone, the different effects of oil saturation and effective pressure variations on seismic P-wave and S-wave velocities are calculated and analyzed. Using numerical simulation on decoupled wave equations, the responses of seismic amplitude with different offsets to reservoir oil saturation variations are analyzed, pre-stack time-lapse seismic attributes differences for oil saturation and effective pressure variations of P-P wave and P-S converted wave are calculated, and time-lapse seismic AVO (Amplitude Versus Offset) response rules of P-P wave and P-S converted wave to effective pressure and oil saturation variations are compared. The theoretical modeling study shows that it is feasible to distinguish different reservoir parameters dynamic variations by pre-stack time-lapse seismic information, including pre-stack time-lapse seismic attributes and AVO information, which has great potential in improving time-lapse seismic interpretation precision. It also shows that the time-lapse seismic response mechanism study on objective oil fields is especially important in establishing effective time-lapse seismic data process and interpretation scheme.

A sequential numerical chemical compositional simulator

Chemical flooding in the petroleum industry has a larger scale of oil recovery efficiency than water flooding. On the other hand, it is far more technical, costly, and risky. Numerical reservoir simulation can be employed to conduct mechanism study, feasibility evaluation, pilot plan optimization, and performance prediction for chemical flooding to improve recovery efficiency and reduce operational costs. In this article, we study numerical simulation of chemical flooding such as alkaline, surfactant, polymer, and foam (ASP+foam) flooding. The main displacement mechanisms in this type of flooding are interfacial tension lowering, capillary desaturation, chemical synergetic effects, and mobility control. The model of chemical flooding involves such physicochemical phenomena as dispersion, diffusion, adsorption, chemical reactions, and in situ generation of surfactant from acidic crude oil. The numerical simulator is based on a sequential solution approach that solves both pressure and compositions implicitly, and is applied to three experiments, a chemical flow without mass transfer between phases, a laboratory sandstone core, and an ASP+foam displacement problem with mass transfer, and to a real oilfield. A comparison with UTCHEM is also performed. These applications and comparison indicate that this numerical simulator is practical, efficient, and accurate for simulating complex chemical flooding processes.

Multi‐Layer Pipes for Hydrocarbons Conveyance

AbstractThe replacement of metals with plastics in piping systems is a well established practice in a vast range of public and industrial applications. However, difficulties still exist, mainly related to the limited chemical resistance of the polymers commonly used in pipe manufacturing to some conveyed fluids. This prevents using plastic pipes in important applications such as the transport of liquid hydrocarbons, particularly in oil fields. The use of chemically resistant polymers, such as fluorinated polyolefins, is precluded by high cost and poor mechanical properties. Co‐extrusion of multi‐layer pipes carrying an internal chemically resistant liner can be a viable alternative capable to extend the use of plastic pipes to refining and chemical industries. An experimental PE/PA multi‐layer pipe has been developed whose resistance to diffusion and mechanical properties have been tested. Tests in real oil fields confirm the good performance of the new pipes.

Vertical Permeability From In Situ Horizontal Measurements in Shaly-Sand Reservoirs

Abstract The oil industry has become increasingly aware that reservoirs exhibit complex variations of reservoir continuity; in particular, of pore space-related properties such as porosity, permeability, and capillary pressure. These variations reflect the original depositional process, and subsequent diagenetic and tectonic changes. Simple models are often inadequate for predicting reservoir performance and designing a field production management program that optimizes recovery. It is evident to reservoir engineers that optimization depends on the quality of the reservoir undergoing water injection, where the recovery factor is very sensitive to reservoir heterogeneity. Therefore, an accurate knowledge of vertical and lateral permeability distribution is essential. This paper represents results of a research project aimed at determining vertical permeability from in situ horizontal permeability in shaly reservoirs. This is accomplished by considering the microscopic and macroscopic features, such as the type of shale (Kaolinite, Chlorite, and Illite) and grain size. In situ vertical permeability correlations are derived by using various water saturation correlations for Shaly-Sand formations. Several vertical permeability relationships were obtained as a function of horizontal permeability, hydraulic mean radius grain size, and the amount and/or type of shale. Generalized models were developed, and were applied to real oilfield data for calculating vertical and horizontal permeabilities. Introduction Permeability is one of the most important of all formation parameters used by petroleum engineers to determine whether a well should be completed and brought online or abandoned. Vertical permeability is also essential in developing a reservoir management and development program, including determining the optimal drainage points and production rate, optimization completion and perforation design, and planning EOR patterns and injection conditions. Extensive research on permeability has been conducted on clean formations for decades. Vertical permeability in Shaly-Sand formations has long been viewed as problematic. Formations with shale and/or different pore geometries constitute the majority of heterogeneous reservoirs. In this case, reservoir heterogeneity is no longer viewed as a problem, but rather as an opportunity for recovering more oil. In early studies of reservoir engineering, reservoirs were assumed to be homogeneous and isotropic, but also non-uniform. In recent studies, however, the porosity-permeability transform has been used for a better description of a reservoir having some complex geological continuity. Clark(1) showed that, if the rock grains are large, flat, and uniformly oriented along the longest dimension, then the horizontal permeability (Kh) would be higher than the vertical one. Clark(1) also showed that, if the rock was composed mostly of large and uniformly rounded grains, its permeability would be considerably higher and almost equal in both the horizontal and vertical directions. Generally, vertical permeability is lower than horizontal permeability, especially if the sand grains are small and have irregular shape. Most petroleum reservoirs fall in this category. Neasham(2) studied the effect of clay on permeability. He showed that the morphology of clay with the highest air permeability is predominantly the discrete particle. The morphology of dispersed clay in samples falling within an intermediate air permeability range is predominantly of a pore-lining variety.

Modelling of Re-Working Carbonate Sediments under Strong Tidal Current Setting

A numerical model has been developed which successfully simulated not only carbonate precipitation but also re-sedimentation of carbonate material under a strong tidal current environment. Carbonate reservoirs in oil fields, offshore Abu Dhabi, were deposited under such environments, so that there is difficulty to predict the reservoir heterogeneity in the exploitation stage where no more appraisal wells would be available. A numerical process model is the only solution for predicting reservoir heterogeneity under such conditions; however, most of the carbonate models that have been developed in recent years take account only of the generation of carbonate material under specified depositional environments. Sedimentation by tidal currents, which is similar to clastic sedimentation, was also neglected in the models because of its lesser importance for carbonate reservoir characterization. The present model estimates in detail the distribution of tidal current velocity in the field by using a commercial flow model with multi-layered systems. For a simplification, only the bed load transportation was taken into account for transportation of carbonate sediments. It was possible to formulate the effect by bed load transportation as a function of water depth, grain size and current velocity at each point for a given grid system. For simulation of a longer period of ancient sedimentation, the ‘Mean Field Method’ and ‘Error Tolerance Level’ are introduced for effective calculation of the equivalent result using longer time conditions than daily tidal cycles. The model developed was tested against the present-day geologic situation from the Bahamas where many of the input parameters can be observed. Then it is applied to the real oil field, offshore Abu Dhabi. We could reproduce the geologic sequences that are conceptually similar to the observations in both cases. The model thus has the potential to predict ancient reservoir quality at the petroleum exploitation stage.

Gradual Deformation and Iterative Calibration of Sequential Stochastic Simulations

Based on the algorithm for gradual deformation of Gaussian stochastic models, we propose, in this paper, an extension of this method to gradually deforming realizations generated by sequential, not necessarily Gaussian, simulation. As in the Gaussian case, gradual deformation of a sequential simulation preserves spatial variability of the stochastic model and yields in general a regular objective function that can be minimized by an efficient optimization algorithm (e.g., a gradient-based algorithm). Furthermore, we discuss the local gradual deformation and the gradual deformation with respect to the structural parameters (mean, variance, and variogram range, etc.) of realizations generated by sequential simulation. Local gradual deformation may significantly improve calibration speed in the case where observations are scattered in different zones of a field. Gradual deformation with respect to structural parameters is necessary when these parameters cannot be inferred a priori and need to be determined using an inverse procedure. A synthetic example inspired from a real oil field is presented to illustrate different aspects of this approach. Results from this case study demonstrate the efficiency of the gradual deformation approach for constraining facies models generated by sequential indicator simulation. They also show the potential applicability of the proposed approach to complex real cases.

Applications of statistical physics to the oil industry: predicting oil recovery using percolation theory

In this paper we apply scaling laws from percolation theory to the problem of estimating the time for a fluid injected into an oil field (for the purposes of recovering the oil) to breakthrough into a production well. The main contribution is to show that percolation theory, when applied to a realistic model, can be used to obtain the same results as calculated in a more conventional way but significantly more quickly. Specifically, we found that a previously proposed scaling form for the breakthrough time distribution when applied to a real oil field is in good agreement with more time consuming simulation results. Consequently these methods can be used in practical engineering circumstances to aid decision making for real field problems.

1D waves in a random poroelastic medium with large fluctuations

We examine the problem of wave propagation in a random poroelastic medium. The porous medium is modelled as a Biot poroelastic solid whose constitutive parameters fluctuate substantially over finite distances. Our main results are asymptotic analytical expressions for the mean velocity-stress wave; this solution incorporates two distinct length scales. The effect of the fluctuations appears on the regular depth coordinate while the parameters of the effective medium arise on a shorter scale of distance. Thus the method that we apply, the theory of averaging, allows us to give a rigorous derivation of the effective medium parameters. It also provides the correction terms which are caused by the fluctuations in the random medium; we find that the relative effect of the latter increases in proportion to ω1/2 where ω denotes the wave frequency. We also show that the fluctuations introduce significant attenuation of the fast Biot compressional wave and dispersion of the slow Biot wave. These results are illustrated by numerical examples using real oilfield data.

A stochastic model for drilling optimization

Drilling optimization problems in oilfields are usually formulated and solved by using deterministic mathematical models, in which uncertain (indeterminate) factors or random issues are not taken into consideration. However, it has been widely experienced that random factors (such as those from soil layers, drill bits, and surface equipment) greatly affect the drilling performance. This paper introduces a new stochastic model for describing such random effects. This model, when used to optimization design, is more practical and provides a better characterization for real oilfield situations as compared with other deterministic models, and has been demonstrated to be more efficient in solving real design problems of drilling optimizations.

Sulfide Stress Cracking of High-Strength Steels In Laboratory and Oilfield Environments

This paper summarizes the results of an examination of the sulfide stress cracking (SSC) susceptibility of selected API and non-API grades of high-strength steels subjected to extensive laboratory and field tests. Introduction High-strength steels commonly used in drilling, completing, and producing' gas and oil wells exhibit catastrophic, brittle failures when exposed to environments containing hydrogen sulfide. This phenomenon is known as sulfide stress cracking (SSC). SSC has long troubled the petroleum industry by placing restrictions on the use of petroleum industry by placing restrictions on the use of high-strength steels in handling sour gas and crude in these applications. As wells become deeper and encounter higher temperature and higher pressure formations, these high-strength steels are needed for effective, economic, and safe completions. High priority is placed on comprehensive design guidelines for commonly used highstrength steels that will allow selection of these materials for specified conditions of temperature and H2S concentration. Many previous studies have used laboratory tests incorporating artificial H2S environments (100 percent H2S, NaCl, HCl, H2SO4, etc.) to investigate the various parameters that affect SSC of steels. Often these studies parameters that affect SSC of steels. Often these studies have failed to relate the laboratory data to observations made in real oilfield environments. Generally, SSC data for many conventional oilfield materials are not available. This paper summarizes the results of an examination of the SSC susceptibility of selected API and nonAPI grades of high-strength steels subjected to extensive laboratory and field tests. The objective of these tests was to determine the limits of SSC susceptibility for these materials in real oilfield environments and to correlate these results with laboratory data. Test Procedure Materials Table 1 lists the materials tested in the present study, along with their chemical compositions. Five API grades of steel tubulars were tested: J-55, C-75, N-80, P-110, and V-150. The non-API steels tested included MOD N-80 (trade mark), SOO-95 (trade mark), SOO-125 (trade mark), and SOO-140 (trade mark). Also included in this examination was a sample of AISI 410 in wrought tubular form. All materials with the exception of the SOO-140 were in the form of 3 1/2- to 4 1/2-in. casing. The SOO-140 was in the form of 7-in. casing. The mechanical properties of these steels are given in Table 2. All materials were heat treated by the supplying manufacturer. Specimens All materials with the exception of the SOO-140 were tested in the form of notched C-rings. An example is shown in Fig. 1. The C-rings were approximately 4 1/2-in. in diameter (3 1/2-in. diameter for SOO-125) with a 0.25-in. wall thickness. The outside surface of each specimen contained a Charpy V-notch, which had a depth of 12 1/2 percent of the specimen thickness. The SOO-140 was tested in the form of notched beam specimens (3.5 X 0.3 X 0.1-in., 12 1/2 percent Charpy V-notch). Such a specimen is also shown in Fig. 1. All specimens were stressed by mechanical deflection using carbon-steel bolts, while neglecting the effect of the C-ring notch. JPT P. 1483