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Collaborating Authors
SPE Europec/EAGE Annual Conference and Exhibition
Abstract Scoping studies using data from three mature fields suggest that simple workflows that use only essential stratigraphic and facies constraints are as good in capturing overall reservoir fluid flow response as complex, highly constrained workflows that use detailed stratigraphic and facies constraints. Thus, considerable time and cost saving may be realized during initial model building and updating if simple, but appropriate, workflows are used. The reservoirs studied include a Permian-age carbonate reservoir in New Mexico, an Upper Miocene deepwater clastic reservoir in California, and an Eocene-age shallow water clastic reservoir in Venezuela. Two dimensional cross section models of the deepwater clastic reservoir showed that cumulative production and water breakthrough times were essentially the same for models using the two major stratigraphic picks as for models constrained by 12 detailed stratigraphic picks. Three dimensional streamline simulation was used to demonstrate that adding facies and rock type constraints had little impact on recovery factors for a carbonate reservoir scoping project area consisting of 25, 5-spot waterflood patterns. Likewise, a very complex workflow for the shallow water clastic data set from Venezuela constrained by eight facies and 16 detailed stratigraphic picks yielded the same reservoir response as a simple, two facies, and four major stratigraphic picks constrained workflow. These studies suggest that for reservoirs with moderate to high net to gross (>30–40%) or with small differences in the porosity vs. permeability trends of facies/rock types that simple geological modeling workflows are adequate for subsequent fluid flow simulation. Models generated using the shallow water clastic data sets and evaluated using three dimensional streamline simulation showed that varying the semivariogram range parameters by factors between 0.25 and 2 times the data driven range value also had little effect on reservoir response. An important issue surrounds the impact of up-scaling on fluid flow response. Vertical up-scaling by factors commonly used for full field simulation models has little impact on fluid flow response based on studies of the New Mexico carbonate reservoir and the shallow water clastic reservoir in Venezuela. However, areal up-scaling of models generated using a very fine 50 foot areal grid significantly alters the fluid flow characteristics and warrants additional study. Introduction This paper presents the results of several small studies done over the past six years or so that provide insight into how to efficiently build static models for mature fields that preserve those geological features (e.g. heterogeneity) critical to fluid flow. Numerous recent papers have addressed issues critical to mature field characterization, static and dynamic modeling, and management.[1–5] A variety of papers have been published that address specific aspects of how best to capture critical geological heterogeneities in earth models prior to and during upscaling for dynamic simulation.6–14 The primary focus of this paper is to compare the fluid flow response of dynamic models derived from static models generated using stochastic workflows that utilize differing amounts of geological complexity (constraints) using data from a carbonate and two clastic reservoirs. Although not the primary focus of this paper, results from a study of vertical and areal upscaling of a carbonate reservoir are also presented. Carbonate Reservoir Study A scoping study was done in order to assess the effect of incorporating varying amounts of geological detail or constraints using a data-rich portion of the Eunice Monument South Unit (EMSU) reservoir is located in Lea County, New Mexico about 25 miles south of the city of Hobbs (Fig. 1). The field was discovered in 1929 and has produced about 15% of the estimated 1000 MMSTB OOIP from over 250 wells as of early 2001, when this study was completed.
- South America (1.00)
- North America > United States > Texas (1.00)
- North America > United States > California > Kern County (0.28)
- North America > United States > New Mexico > Lea County (0.24)
- Research Report > New Finding (0.86)
- Research Report > Experimental Study (0.86)
- Phanerozoic > Paleozoic > Permian (0.48)
- Phanerozoic > Cenozoic > Neogene > Miocene > Upper Miocene (0.34)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Deep Water Marine Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- South America > Venezuela > Zulia > Maracaibo Basin > Ayacucho Blocks > Lagunillas Field (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (49 more...)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
A Novel 3D Field-Scale Reservoir Numerical Simulator for predicting the Fines Migration and Production Performance
Ju, Binshan (China U. of Geoscience) | Dai, Shugao (Dongsheng Co. Ltd.) | Qiu, Xiaofeng | Wu, Haiqing (Shengli Oil Field Dongsheng Jinggong Petroleum Development Group Co. Lid) | Li, Shitao (Shengli Oil Field Dongsheng Jinggong Petroleum Development Group Co. Lid) | Zhang, Meilan
Abstract Sand fines release and migration is a universal problem in the production of oil from unconsolidated sandstone reservoirs, which can result in both sanding problems and profound effects on oil recovery. A new three dimensional (3D) field scale mathematical model, differing from those used for conventional oil reservoir numerical simulator in that both the advanced theories of sand particle release and migration, is presented. And the model is solved by a finite-difference method and the line successive over relaxation (LSOR) technique. A numerical simulator is written in Fortran 90 and VC++ and it can be used to predict (1) the sand content in produced liquid, (2) the porosity and permeability changes caused by sand release and migration in formation, and (3) well production performances and residual oil distribution. A series of runs of oil field examples with five-spot patterns were made on the numerical simulator. The results show that sanding problems in the oil formation can accelerate the heterogeneity of the reservoir rocks, and has an obvious influence on production performances: water-drive process, water-cut trends, and oil recovery. In a conclusion, the new simulator improves the ability and accuracy for numerical simulating the development of the unconsolidated sandstone reservoirs. Introduction Sanding problems during oil production from unconsolidated sandstone reservoirs, such as Gulf of Mexico reservoirs[1] (Deskin et al., 1991), the Southeast Pauls Valley Field, Oklahoma, and oil fields around the Bohai Gulf, China, may lead to much adverse influence on the production facility. Several papers (Anne et al., 1997[2], Davies et al., 1997[3], Tom et al., 1995[4], Vásquez et al., 1999[5]) have reported the production facility damage and completion difficulty as a result of sanding. Anne et al. (1997[2]) have also studied the relations between water breakthrough and sand production. In fact, sand production can lead to other severe problems such as formation collapse and effects on improving oil recovery. The sanding process includes three steps: first, sand particles are released from the surfaces of porous media when the critical colloidal or hydrodynamic conditions are satisfied (Ju et al., 2002[6]); second, sand particles migrate in pores with flowing fluids; finally, particle deposition on pore surfaces or capture at pore throats may occur in the process of sand migration. Therefore, the phenomena of particle release, migration and retention must be considered in the mathematical model for sanding. According to the literature concerning sanding of formations (Gruesbeck et al., 1982[7], Khilar et al. 1983[8], Liu and Cvian, 1994[9], Ohen, et al., 1990[10], Sharma and Yortsos, 1986[11]), two kinds of models, the macroscopic mathematical model and the microscopic network mathematical model, are classified. The first kind of model, such as Gruesbek and Collins's model[7] (1982), Khilar and Fogler's model[8] (1983) and Ohen and Civan's model[10] (1994), is based on the theories of the flow in macro-continuous porous media and sand particle release and migration. However, the second kind describes the flow characters of fluid and fines migration in micro-networks. Sharma and Yortsos'model[11] (1986) belongs to the microscopic work mathematical model. Unfortunately, the microscopic work mathematical model has some limitations in that it strongly depends on probability, and its numerical solving process uses tremendous amounts of computer time. Consequently, the theories of macro-continuous porous media and fines migration are used to develop a three dimensional (3D) mathematical model for fines migration in oil formation in this paper. Currently, the major approaches to study the sanding process in permeable formations are physical simulation in the laboratory and mathematical simulation. This paper focuses on the mathematical model to simulate sand release and migration process and behavior, the solution methods of the model, and the development of an oil reservoir numerical simulator.
- South America > Venezuela > Trujillo > Maracaibo Basin > Ayacucho Blocks > Ceuta-Tomoporo Field (0.99)
- North America > United States > Oklahoma > Southeast Pauls Valley Field (0.99)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
Abstract Water based drill-in fluids usually contain starch and xanthan polymers and sized calcium carbonate particles, which help in developing an effective filter cake during drilling process to control fluid loss. Proper removal of the drill-in fluid filter cake from the pay zone is essential to maximize productivity. The latest technique for filter cake clean-up is the application of acid and enzymes in a single stage. The prime advantage of this technique is the uniform placement of acid through precursor in long horizontal wells. Other benefits include: cost and time saving by avoiding multistage treatment and reduced risk of tools corrosion, which is associated with mineral acids. A detailed study was conducted to evaluate the efficiency of acid-precursor-enzyme system to be used in multi-lateral, maximum reservoir contact wells. The evaluation was performed by using samples of polymer based drill-in fluids and dry bulk of sized calcium carbonate in terms of return permeability determination, change in particle size distribution, and weight loss. Results indicated that the generated acid mainly targeted fine particles of calcium carbonate present in drill-in fluids and dry bulk. This paper presents results of lab investigations and merits (or demerits) of single stage treatments. Introduction The acid-precursor-enzyme system (APES) is a wellbore cleaning chemical. It is composed of ingredients including enzymes and acid-precursor and designed to act in two ways: to degrade the polymer present in the filter cake by enzymatic action and to dissolve calcium carbonate by acid generated in-situ. The basis of the process is that an acid precursor compound is mixed in brine, where the acid is generated over a period of time and reacts with calcium carbonate, while substrate specific enzymes simultaneously act on polymers like starch and xanthan. The enzyme-based process of generating acid in-situ and filter cake removal in a single stage has been studied.[1–3] The present investigation is an attempt to examine the merits and limitations of APES in maximum reservoir contact (MRC) wells. In the recent years, with the shift from vertical and horizontal wells to MRC well types, the longer horizontal hole section have become more challenging to clean-up as access to the pay zone with coiled tubing is becoming more expensive and in some cases difficult. Hence a filter cake clean-up system was required to clean the pay zone by using drill string immediate after drilling. DIFs with reasonable properties and favorable particle size distribution (PSD) were designed to meet the challenging task of MRC drilling. MRC wells have proved their success as a productivity enhancement and economical option for field development in Saudi Arabian fields.[4] The objective of the study was to determine the efficiency of the APES in terms of permeability improvement as a synergic effect of polymer degradation by enzymes and calcium carbonate dissolution through acid generation.
- Europe (0.69)
- Asia > Middle East (0.46)
- North America > United States (0.46)
Abstract During CO2 injection into fractured reservoirs the overall oil recovery will be the result of the complex interplay of several mechanisms such as viscous flow, extraction by molecular diffusion and gravity drainage. In order to study the component exchange between the matrix and the fracture system during the CO2 injection, CO2 injection experiments at reservoir conditions have been carried out using 60 cm long 4.6 cm diameter composite cores from an outcrop analogue to one of the North Sea reservoir rock. The core and core holder assembly were designed to allow a 2 mm fissure to surround the core plug simulating a fracture. Live reservoir fluid was prepared and used for saturating of the matrix system. Because of the large permeability contrast between core (4 mD) and fracture it is difficult to saturate the core by simply flooding the system with live oil. Oil would flow through the fracture and only partially saturate the core To overcome this problem a unique technique has been developed for saturating the matrix system with reservoir fluids. This method ensures a homogeneous fluid composition within the pore system before the fracture system is initialized with the CO2. During the experiments CO2 was injected at a low and constant rate into the fractured system. The component exchange between the oil in the matrix and CO2 in the fracture was monitored by analyzing the produced fluids. The recovery profiles and the fluid compositions were used to construct a compositional numerical model. The results from the experiments in the long core as well as the simulation studies show the importance of the diffusion mechanism in these experiments. The results have proved that the key mechanism to recover oil from the tight matrix block was diffusion and the gravity drainage had no significant effect at the experimental conditions used. Introduction In fractured reservoirs, matrix blocks are assumed to act as sources of oil and fractures are a flow conduit through which the oil is flowing towards the producing wells. Depends on the matrix blocks geometry and the reservoir fluid properties, oil from the matrix block is transferred to the fracture system by different mechanisms. Based on classical fractured reservoir production mechanisms, when a tall and permeable oil-saturated matrix block is surrounded by gas in the fracture, oil drains from the matrix as a result of the density difference between the gas in the fracture and the oil in the matrix (gravity dominated mechanism). In case of low permeability and small size matrix blocks with high capillary pressure, the gravity drainage mechanism is inefficient and molecular diffusion mechanism will dominate. To quantify and understand the contribution of the above mechanisms for oil recovery during CO2 injection in highly fractured under-saturated light oil reservoirs, it is necessary to perform laboratory experiments at the reservoir conditions. Due to the large compositional space involved in this process it is also necessary to initialize the matrix and fracture system with the representative reservoir fluids. However, in this kind of experiments saturating the pore system with live oil is very difficult. Due to large permeability contrast between matrix and fracture, normal core flooding can not be used for saturating the pore system. Oil would flow through the fracture and only partially saturate the pore system. Because of this problem, dead oil was used for saturating the pore system in most of the experimental studies reported in literature. For example in the CO2 gravity drainage experiments performed by Li et al.,[1] the core was saturated by dead oil while the experiment was supposed to be at the reservoir conditions. Dry gas injection in fractured chalk by Øyno et al.[2] conducted by saturating the matrix system with live oil, but still their method for initialization of the pore system with live oil is not certain. In their experiment the oil recombination was carried out in the core holder where the matrix and fracture were placed. The oil/gas mixture was circulated in the system and pressure was monitored. Once pressure had stabilized, they assumed that the pore system is saturated with the live oil. In this method, since the pore system was saturated with oil by a very slow diffusion mechanism, therefore the pressure stabilization over a short time interval will not guarantee the homogeneous initialization of the pore system with representative reservoir fluids.
- North America > United States (0.93)
- Europe > United Kingdom > North Sea (0.24)
- Europe > Norway > North Sea (0.24)
- (2 more...)
- Research Report > New Finding (0.86)
- Research Report > Experimental Study (0.86)
Abstract The conventional reserve estimate methods for waterdrive reservoirs are well established. Typically, the techniques proposed by Havlena and Odeh and McEwen are used. In general, the reserves estimated from the Havlena-Odeh and McEwen procedures are not unique since the recorded historical production data is simultaneously solved for aquifer parameters and reserves. Normally, multiple combinations of reserves and aquifer parameters match the field data equally well. Hence, a range of reserves rather than a unique value is found. The upper and lower limits of the reserve range may vary several folds. To pick the best solution out of the multiple realizations, statistical parameters are calculated for all the matches. The solution with some minimum statistical indicator is considered to be the best solution. Among the statistical indicators suggested are the standard absolute relative error, normalized sums of squares of differences, standard deviation, normalized standard deviation, curvature, and coefficient of variation. The reserve estimate based on some minimum statistical indicator may not be reliable. The best reserve estimate corresponding to the minimum standard absolute relative error may differ from those corresponding to the minimum normalized standard deviation or the minimum coefficient of variation. In this paper, a hybrid approach making use of available methods is employed to narrow the reserve range estimates in waterdrive gas reservoirs.
Abstract Concession 97 in the Sirte basin of Libya is subdivided into three different exploitation areas (figure 1). The operator, Wintershall, developed discoveries in each area in 1988, 1990 and 1995 respectively. The producing reservoirs are in the challenging Sarir and Lidam horizons. The Sarir reservoirs are stratified sandstones with medium to very low permeability. The Lidam formation, consisting of a lower limestone and an upper dolomite, has limited net pay. While reservoir rock properties in both Sarir and Lidam reservoirs are of rather poor quality, the oil properties are very favourable. Ongoing appraisal and the application of advanced exploration methods in recent years resulted in the discovery of additional fields and extensions. Substantial additional volumes have been appraised. However, primary recovery factors are expected to be relatively low. Recent discoveries and the optimisation of the existing fields led to the completion of an integrated re-development of the entire concession. Three decentralized gas-oil separation plants were recently replaced by a central unit including gas utilization. A key challenge of such a scheme is the long distances, of up to 50 km, between oilfields and the separation plant. Trunk-lines with multiphase pumps are utilized to overcome the pressure losses and to allow reasonable backpressures at the wellheads. Considerable savings in operational expenditures were achieved and the integrated concession development approach will enable the operator to apply different improved recovery strategies. The synergies gained from combining improved recovery methods are seen as a prerequisite for commercial application. This paper aims to illustrate the integration of new field development and mature field re-development. The integration scheme enables the operator to implement improved recovery methods in difficult reservoirs which are not feasible on a stand-alone basis. Introduction Intensive exploration and appraisal activities were conducted in concession 97 between 1966 and 1970 (figure 2). However, the resulting discoveries were considered marginal at that point in time. In 1988 Tuama oilfield (C97-III) was put into production via Bu Attifel production facilities. In early 1990 the Hamid oilfield (C97-II) started production through a new GOSP. The field extension well G3–97, drilled in 1993, resulted in a substantial increase of discovered STOOIP and led to the production start up of the Nakhla oilfield (C97-I) through a new GOSP in 1995. Further development activities in the producing fields and the discovery of the N-Field in 2002 substantiate the current production of about 20,000 bopd from a total of 28 wells. Active aquifer pressure support was observed only in two reservoir compartments of Tuama and N-Field. All fields are at depths between 10,000 and 14,000 ft. Ongoing appraisal and advanced seismic exploration methods resulted in recent years in the discovery of additional fields and extensions. Substantial additional oil accumulations could be appraised. To date more than 1.5 Bstb of STOOIP has been discovered in the concession. However, only about 50 MMstb have been produced so far. The primary recovery factors are relatively low because of the poor reservoir rock properties. Low well productivities, the unpredictable distribution of volcanoclastics and reservoir compartmentalisation are key characteristics for most of C97 discoveries. The applied exploration and development strategy has to follow a step by step approach to account for the specific risks and to benefit from the learning of each step.
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.69)
- Africa > Middle East > Libya > Sirte District > Sirte Basin (0.99)
- Africa > Middle East > Libya > Al Jufrah District > Sirte Basin > Lidam Formation (0.99)
Abstract Extensive studies have been conducted on hydrate formation in gaseous systems; however, little information is available on hydrate risks in oil systems. This is partly due to difficulties in measuring the hydrate stability zone in oil systems, as well as problems associated with compositional representation of such systems. Furthermore, it is reported that hydrate formation pose less risks in oil systems than gas systems, partly due to the presence of natural inhibitors, formation of water in oil emulsions, and possibly oil wet pipeline walls. However, little is known of the nature and mechanism of the natural inhibition and the response of the system to an increase in the water cut. In this communication, we present details of two experimental set-ups specifically designed to study the hydrate risks in oil systems. They include a visual high pressure kinetic rig for measuring the hydrate stability zone, crystal size, distribution and the rate of hydrate formation and dissociation, and a glass micromodel for visual observation of hydrate formation / dissociation in micro-scale. We report some of the recently obtained experimental results using the above experimental equipment. The results show that the existing techniques should be revisited for generating reliable data in oil system. We also demonstrate that proper characterization of the heavy end and taking into account the possibility of wax formation may play a role in improving the reliability of predictive techniques. The results provide better understanding and evaluation of risks associated with hydrate formation in pipelines carrying oil. Introduction As deepwater offshore production is widely developing, the problem of flow assurance becomes of major importance. In deepwater pipelines, where reservoir fluids including gas, oil and water with dissolved salts and organic inhibitors are flowing together at low temperatures and high pressures, the formation of hydrates may occur leading to pipeline restriction and blockage. In order to plan the pipeline design and operation and prediction of the hydrate phase boundary, using thermodynamic models is required. The development and validation of the models relies upon experimental study of gas hydrates.[1] There is a significant bank of information available for gas systems that form gas hydrates.[1,2] However, there is significantly less information for oil systems, particularly real reservoir fluids. On the other hand, hydrate formation is greatly influenced by the nature of the reservoir fluid produced. The presence of water/oil (W/O) emulsion greatly aids the transportation of hydrates as slurry in deepwater offshore production and transportation and can solve the problem of flow assurance, partly due to the presence of natural inhibitors (e.g., asphaltene), formation of water in oil emulsions and possibly oil wet pipeline walls. Therefore, studying thermodynamics and kinetics of hydrate formation/ dissociation in oil systems is of great interest. In this communication, a review is made on factors affecting thermodynamics of hydrate formation in oil systems. A thermodynamic model which is capable of predicting different scenarios such as hydrate and wax formation in reservoir fluids is then introduced and capability of the model is investigated. The details of two experimental set-ups specifically designed to study the hydrate risks in oil systems, including a visual high pressure kinetic rig for measuring the hydrate stability zone, crystal size and distribution and the rate of hydrate formation and dissociation and a glass micromodel for visual observation of hydrate formation/ dissociation in micro-scale are presented. Some of the recently experimental results using the above experimental equipments are also presented. The results can provide better understanding of hydrate formation/ dissociation in oil systems.
- Europe > Norway (0.66)
- North America > United States > Texas (0.46)
- Europe > United Kingdom > Scotland (0.28)
- Research Report > Experimental Study (1.00)
- Research Report > New Finding (0.86)
Abstract Fracturing modeling methods developed for conventional hydraulic fracturing are now being used for unconventional fracturing in waterfracs, water or steam flooding, produced water reinjection, etc. A common feature of these unconventional fracturing processes is the strong interaction among fracture propagation (often with high 3D fluid leakoff), reservoir flow, changes in stresses (poroelastic and thermoelastic effects), and permeability and porosity changes (geomechanical effects) around the fracture. Conventional fracturing models are inadequate under such conditions; moreover, they are also disconnected from well performance forecasting, which makes integrated data analysis difficult. Therefore, it is necessary to seek a new modeling concept including all these mechanisms and their mutual influences. This paper describes a method to model hydraulic fracturing with dynamic transmissibility multipliers based on coupled reservoir and geomechanics simulation. The method is the first step in developing a fracturing model fully coupled into reservoir and geomechanics simulation, where the fracture geometry will be also internally calculated from the fracture face displacements in the coupled FEM geomechanical module. The method described here ignores fracture volume but focuses on the effect of fracture on fluid flow and geomechanics in reservoir by introducing pressure/stress dependent dynamic transmissibility multipliers and treating them as a property of the matrix. This approach allows modeling fracture propagation, dynamical multiphase fracture conductivity, clean-up, and pre- and post-frac well performance in a changing stress, pressure and temperature environment, all in a unified manner. This paper also discusses the strategy of coupling hydraulic fracture propagation, reservoir and geomchanics simulation, resulting in a method to improve the stability of the dynamic hydraulic fracture propagation in coupled reservoir and geomechanics simulation. The case studies in this paper confirm that the strategy and the method to model dynamic hydraulic fracture propagation coupled with reservoir and geomechanics simulation is feasible, flexible and reliable. It is easy and convenient to implement in conventional reservoir simulators and coupled reservoir and geomechanics simulators (such as GEOSIM). Introduction Conventional fracturing models predict fracture geometry based on mass balance of injected fracturing fluid and decouple fracture modeling from reservoir flow by modeling fluid leakoff with 1-D analytical, 2-D analytical or numerical "leak-off models."[1,2,3,4] However, in unconventional fracturing applications such as waterfrac, fracturing in waterflood[5] etc., fracture propagation, fluid flow in reservoir and geomechanical effects (i.e., deformations and stresses) in the reservoir and its surroundings are strongly coupled[8], as shown schematically on Fig.1. The conventional fracturing models don't always work well for unconventional fracturing applications due to singularity of mass balance constraint of fluid in facture, large changes in pressure, temperature and stress in the reservoir, and grid effects caused by (intended) high leakoff rate and/or very long injection time.[5] These factors may result in oscillation of fracture growth with time, and limit the stability of the model.[5]
Abstract The application of extended subsea networks and transportation of unprocessed well-streams are amongst favorable options for reducing field development and operational costs. These pipelines normally convey a cocktail of multiphase fluids, including mixed electrolyte produced water and liquid and gaseous hydrocarbons and may therefore be prone to hydrate formation, which potentially can block the pipe and lead to serious operational problems. For deep water operation, even saturated saline solutions may not provide the required protection, unless combined with chemical inhibitor. The reported data on hydrate formation in mixed salt and chemical inhibitor are very limited and in some cases inconsistent. In this work, a model is introduced to predict the hydrate free zone in mixed salt and chemical inhibitor designed for offshore and deep water applications. The model is based on combination of the Valderrama modification of the Patel-Teja equation of state with non-density dependent mixing rules and a modification of a Debye-Hückel electrostatic term, which is applied to systems containing salt and chemical inhibitor by correcting the properties of the aqueous phase such as dielectric constant, density and molecular weight. A linear mixing rule is used for determining the dielectric constant of salt-free mixture by introducing an interaction parameter (in dielectric constant mixing rule), which is tuned using the freezing point data of aqueous solutions containing salt and organic inhibitor. The binary interaction parameter between salt and organic inhibitor is adjusted using water vapor pressure data in the presence of salt and organic inhibitor. The predictions are compared with experimental data and a literature model, demonstrating the reliability of the developed model. Introduction Accurate knowledge of phase behavior in water-hydrocarbon systems, especially in the presence of salt and/or organic inhibitor is crucial to the design and operation of oil and gas pipelines and production/processing facilities. The application of extended sub-sea gathering networks and the transportation of unprocessed well-streams are favorable options for reducing field development and operational costs. These lines will convey a mixture of multi-phase fluids, including mixed electrolyte produced water and hydrocarbons. One serious concern is that these pipelines and production/processing facilities are prone to hydrate formation, giving rise to pipeline blockage, operational problems and other safety concerns. These can be avoided by either operating outside the hydrate region or transporting hydrates as slurry. The economics of the first option is largely dependent on the accurate determination of the hydrate phase boundary, whereas the amount of hydrates to be transferred could be the main factor in the success of the second option.[1] Many models have been developed that are able to predict the phase equilibria of mixtures containing both electrolyte and non-electrolyte compounds. This is usually done by either introducing complex mixing rules to an equation of state or by coupling the equation of state (short-range interactions) with a Debye-Hückel (D-H) electrostatic term (long-range interactions). The available models are normally developed for electrolyte solutions in the absence of organic inhibitors (e.g., alcohols). However, in cases where the inhibition effect of the produced saline water is not adequate for avoiding gas hydrate formation, organic inhibitors (e.g., methanol, glycol) are added to the pipelines, resulting in a system containing both salt and organic inhibitor. In these cases, it is necessary to take into account the hydrate inhibition effect of combined salt and organic inhibitor. The simplest possible solution is to assume that the combined effect of salts and organic inhibitors on the water activity is the sum of their separate effects. Nasrifar et al.[2] showed that additivity of activities could be assumed if the interaction between the salt and organic inhibitor is neglected. Later, Jager et al.[3] suggested that theoretical models must properly account for the interaction of all species in the water solution in order to predict the effect of mixed inhibitors correctly.
- North America > United States (0.28)
- Europe > Austria (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.38)
- Reservoir Description and Dynamics > Fluid Characterization (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Hydrates (1.00)
Abstract The environmental concerns, increasing cost of exploration and the technical requirement of high temperature drilling demand the use of environment friendly, economically attractive and thermally stable water-based drilling mud to fulfill the functional behavior of a mud system to complete a well safely and economically. Thermal stability of low cost water-based mud is essential to achieve the technical goal, meet the environmental challenges and reduce the mud cost. This paper describes a novel additive to prevent the thermal degradation of bentonite mud up to a bottom hole temperature of 150 °C. The experimental data of a base bentonite mud showed more than 150% increase in PV, more than 250% increase in YP and more than 100% increase in gel strength after hot rolling at 150 °C for 16 hours. The bentonite mud with novel thermal degradation inhibitor showed about 50% increase in PV and little change in the YP and gel strength characteristic of the bentonite+GSP mud after hot rolling at 150 °C for 16 hours. The environment friendly thermal degradation inhibitor is expected to increase the working temperature range of bentonite mud without causing any damage to the environment. Introduction Drilling fluid is a complex system that contains a fluid phase, a solid phase and a chemical phase. Other than the fluid (either water or oil or both) and the solid phases, different types of chemicals and polymers are used in designing a drilling mud to meet some functional requirements such as appropriate mud rheology, density, mud activity, fluid loss control property etc (Amanullah et al. 1997). Though the factors that guide the choice of a fluid base and the mud additives are complex (Gray, 1980), the selection of the additives must take account of both the technical and environmental factors to eliminate any environmental impact (Amanullah, 1993). However, due to delayed realization of the environmental impact of mud additives such as chemicals, polymers, salt water and oil-based fluids, little attention was paid in the consideration of environmental factors at the early stage of drilling. Moreover, the manifestation of the negative environmental impact of some additives after long period of slow and silent action made the realization even difficult. Due to the detrimental effect of some mud additives such as potassium chloride, potassium sulphate, polyamine etc., the drilling and operating companies were forced to review their mud additive selection guidelines to exclude or control the use of non-environment friendly and low toxic mud additives in the formulation of water-based muds. Since some of the mud additives that were acceptable from environmental point of views decades ago, are not tolerable now-a-days, the industry is keen to avoid the same problem in the future. For this reason, the industry is dedicated to replace some of the low toxic, less harmful and less pure mud additives that are acceptable according to current environmental norms but may not be tolerable in future due to the introduction of increasingly strict environmental legislations to protect the global environment. Moreover, some of the mud additives that are considered environment friendly on the basis of the evaluation of short term exposure effect may not be acceptable if they show long term exposure effect. This may lead to the changes in mud and mud additives selection and disposal guidelines all over the world. This is reflected by the change in the AEUB Guidelines (1996) for gel chemical mud systems by the introduction of new Interim Guidelines (2001) for advanced gel chemical wastes due to the realization of the environmental impact of potassium sulphate containing water-based mud. Darlene Lintott et al. (2003) provide a detailed description of a potassium sulphate-based gel chemical system along with its disposal criteria in terrestrial ecosystems.