bluuebunny/crossref_metadata_2025_split huggingface dataset:
Productivity Decline in Oil Wells Related to Asphaltene Precipitation and Emulsion Blocks
Authors: Kokal Sunil , Al-Dawood Naseem , Fontanilla Jerry , Al-Ghamdi Abdullah , Nasr-El-Din Hisham , Al-Rufaie Yousef 
Published: December 2007

SummarySeveral oil wells in a Saudi Arabian field have shown a significant decline in oil productivity in recent years. A few have "died" prematurely, while others have become intermittent producers. The oil productivity decline is aggravated by water encroachment and has occurred with relatively low water rates and without any significant drop in reservoir pressure. These wells have low productivity indices (PIs), resulting in relatively low flowing bottom-hole pressures (FBHPs).This paper presents the results of an investigative case study to determine the causes of productivity decline in these wells. A multidisciplinary team was set up with engineers and scientists from reservoir management, production engineering, and the R&D Center for the investigative study. The team focused on multiple aspects, including reservoir and production engineering as well as a comprehensive laboratory and field investigation.The results of this study indicate that one of the main causes of productivity decline in these wells is related to asphaltene precipitation and the subsequent formation of tight emulsions downhole. The emulsions block the pore throats and cause formation damage, which leads to productivity decline. Another factor that further aggravates the productivity of these wells is poor rock quality in the area. Possible causes of formation damage by inorganic scaling and leakage and mixing of gas from a deeper reservoir have been eliminated.Well-test analyses on some of the affected wells show that the formation-damage mechanism in the affected area is further aggravated by poor reservoir rock quality. The time-lapse pressure-transient analysis also indicates a deterioration of skin and productivity with time.On the basis of these findings, a special solvent treatment was recommended and designed as a pilot trial for one of the dead wells. The treatment included squeezing xylene and demulsifier to dissolve the asphaltenes and break the tight emulsions around the wellbore area. The treatment resulted in only a slight improvement in the PI, and the well died after a few days. Currently, a stimulation treatment with acid and demulsifier is being implemented in selected wells. The results of the field trials are described here.
The Dynamics of Electrical-Submersible-Pump Populations and the Implication for Dual-ESP Systems
Authors: Sawaryn S. J. 
Published: December 2007

Summary
This paper contains analytical expressions illustrating the growth, renewal, and decline of single electrical-submersible-pump (ESP) populations and their transition to dual-ESP systems. Critical assumptions are justified with published data, and the commercial implications of the conclusions are presented. Discussion starts with possible misinterpretations of instantaneous run time (IRT), which is a commonly adopted measure of pump reliability. Statistical renewal theory is then used to quantify the sensitivity of workover-delay time to rig availability and to determine the expected change in failure rates when replacing an existing pump population with more reliable units. The transition is shown to be relatively insensitive, even to large improvements in reliability.
Dual ESPs are considered as a means of improving the run life. When analyzed as a standby redundant system, they are predicted to exhibit a gamma distribution. Under certain conditions, the replacement of an existing pump population with dual ESPs is predicted to result in a faster reduction in the workover rate and confer additional commercial benefits compared with a single ESP with the same mean time to failure (MTTF). The first dual-ESP system for the Milne Point field, Alaska, was successfully run in a Kuparuk well in April 2000.
It is concluded that dual-ESP systems deserve greater consideration. The material is of interest to vendors designing ESP systems and those managing fields that use ESPs, particularly those involved in incentive-based contracts.
Predicting Present and Future Well Productivities for Solution-Gas-Drive Reservoirs (includes associated paper 9019 )
Authors: Al-Saadoon Faleh T. 
Published: December 2007

One of the first and most important steps in analyzing the performance of any conventionallycompleted flowing well is to determine the well'sproduction rate for any given flowing bottomhole pressure. The flow of oil (and/or water) from theformation into the bottom of the well is governedmainly by the productivity index (PI) of the well. In other words, the PI is a measure of the well'spotential or ability to produce fluids as related to areduction in the flowing bottomhole pressure. The PIis defined at any given time (i.e., at fixed reservoirpressure pe) as the rate of change of the productionrate with drawdown, or
dq dqPI = J =..........(1)d(Pe-Pwf) dpwf
Muskat, Gilbert, Vogel, and others indicatedthat in a two-phase reservoir liquid and gas now thePI is not constant. They concluded that a plot of pwfvs. qo will not yield a straight line but a curved line concave to the origin. Gilbert termed this completegraph the inflow performance relationship (IPR) ofthe well.It appears, therefore, that the PI is subject tochange at any specific time under differingdrawdown conditions. It also appears that the PIchanges throughout the life of a well for a particulardrawdown condition.Vogel developed a general dimensionless relationship for solution-gas-drive reservoirs toprovide accurate calculations for oilwellproductivity. Standing developed a procedure forcalculating the future IPR.This paper is a response to some common errorsthat appear in the literature. Standing, for instance, defines the PI of a well as J= qo/ (Pe - pwf) (Eq.3). This definition is true, however, only if J is assumed to be constant. This unwarranted assumptionhas led to erroneous results as proved later.It is very important to emphasize that, in general,
If J is assumed to be constant (as is the case for oilwells when the oil is undersaturated throughout theproducing formation), then
q = J(Pe - P wf).............................(2)
Eq. 2 holds only when J is (or is assumed to be)constant.If J cannot be assumed to be constant (as forsolution-gas-drive reservoirs operating at or belowthe saturation pressure), then J can be obtained fromVogel's equation.Vogel's equation may be written as
..........(3)
As J= - (dqo)/(dP wf), then by differentiatingboth sides of Eq. 3 with respect to pwf, yields
..........(4)
It is evident from Eq. 4 that as the drawdownincreases (i.e., as Pwf decreases at a given Pe) Jdecreases. When Pwf approaches Pe (i.e., zerodrawdown), then J becomes equal to J *, where
9 qo maxJ* =........................(5)5 P e
Thus,
J 1 P wf (1+8 .....................(6)J* 9 P e
Eqs. 4 and 6 are different from those obtained byStanding. He assumed that J = qo/(Pe - Pwf), which is not true for solution-gas-drive reservoirs.Vogel's equation may be rearranged in thefollowing form.
P. 868＾
Phase Behavior of a Gas-Condensate/Water System
Authors: Kokal Sunil , Al-Dokhi Mohammad , Sayegh Selim 
Published: December 2007

Summary
Gas-condensate reservoirs are an essential part of Saudi Arabia's hydrocarbon resources. A good understanding of the effect of water on the phase-behavior properties of these hydrocarbons is essential for accurately forecasting the performance of the reservoirs with numerical simulators. In addition, the scaling and corrosion tendencies of the produced brine are strongly influenced by mass transfer with the hydrocarbon phase.
This paper presents unique experimental phase-behavior data for a typical Saudi Arabian gas-condensate three-phase (aqueous/ condensate/gas) system. The objective of this work is to quantify the effect of the aqueous phase on gas-condensate fluid properties.
The results show that appreciable amounts of carbon dioxide and methane are partitioned from the gas-condensate phase into the aqueous phase. Another important observation is the mass transfer of water into the condensate phase. The mass transfer between the condensate and aqueous phases results in a slight decrease in the gas/condensate ratio (GCR). The carbon dioxide in solution makes the brine acidic and can dissolve carbonate minerals from the formation (e.g., calcium carbonate). In addition, the acidic or sour brine will be quite corrosive. The experimental results are compared with equation-of-state (EOS) and other correlations published in the literature.
Integrated Optimization for Rate Allocation in Reservoir Simulation
Authors: Davidson Jeffrey E. , Beckner Bret L. 
Published: December 2007

SummaryWhen using a reservoir simulator to predict future field production, one must determine objectives and apply constraints to manage wells and surface facilities. Sequential Quadratic Programming (SQP) methods are used to set well rates in a facility network of a reservoir simulator so that production objectives are maximized (or minimized) subject to constraints on pressures, flow rates, and stream compositions. Actions taken for infeasible conditions are discussed. This method is called Optimized Rate Allocation (ORA). Black-oil and compositional examples are given.
The Effect of Cement Heat of Hydration on the Maximum Annular Temperature of Oil and Gas Wells
Authors: Dillenbeck R. L. , Heinold T. , Rogers M. J. , Mombourquette I. G. 
Published: December 2007

SummaryRecent advances in electronics technology have made it possible to monitor and record real-time annular temperatures in operational wells, both during and after primary cementing. The developments have allowed operators to record the entire annular-temperature history of their wells, including the critical period when cement hydration occurs. The ability to record these actual temperatures can significantly impact the oilfield cementing industry in several ways. Most significantly, currently accepted practice within the industry is to test certain critical aspects of set cement, such as compressive and tensile strength, at the bottomhole static temperature (BHST). If the short-term maximum annular temperature is significantly different from the later BHST of the well, laboratory tests run on cement at a steady BHST may prove to be inaccurate when based on the actual temperature encountered by a cement slurry downhole. Also of concern is the fact that the magnitude of any temperature change after the initial set may have profound effects on the induced stress in the cement sheath as well as on the casing and formation because the maximum temperature spike from hydrating cement may not occur until after the cement has achieved an initial set.On the basis of actual field measurements of annular temperatures, this paper details how the variable factors of individual heat of hydration (HOH), relative annular geometry, and final BHST interact to produce short-term maximum temperatures in the cement sheath. In some instances, these maximum temperatures can vary significantly from the stabilized BHST in a well. The actual annular-temperature data were recovered from wells in both North and South America and include shallow and deep well applications.
Successfully Replacing Oil-Based Drilling Fluids With Water-Based Drilling Fluids: Case Study Demonstrates Value of Extensive Planning and Execution in an Extended-Reach Well
Authors: Stawaisz R. , Taylor S. , Hemphill T. , Tare U. , Morton K. , Valentine T. 
Published: December 2007

Summary
An extended-reach well was planned and successfully drilled with a water-based drilling fluid in an area where wells historically have been drilled with mineral oil- and ester-based drilling fluids—the North Sea central Graben. The high cost of cuttings drilled with inverts that must be shipped to shore for processing and disposal coupled with the potential shutdown of drilling operations in times of bad weather (when cuttings could not be transferred from the rig to supply vessels) led the operator to revisit the use of water-based drilling fluids, especially in the large-diameter hole section in which large amounts of cuttings are generated. However, many water-based systems have been used in the central Graben with little success. The need to develop a stable, shale-inhibiting, waterbased mud (WBM) system capable of performing well in extended-reach drilling (ERD) applications was identified. Extensive prewell modeling of wellbore stability in problematic shale zones and of hole cleaning in the large-diameter interval contributed to the success of this challenging project. This article discusses the planning, preparation, and successful drilling of the intermediate interval with a water-based drilling fluid.
Numerical Studies of Gas Production From Methane Hydrates
Authors: Moridis G. J. 
Published: December 2007

Summary
EOSHYDR2 is a new module for the TOUGH2 general-purpose simulator for multicomponent, multiphase fluid and heat flow in the subsurface. By solving the coupled equations of mass and heat balance, EOSHYDR2 can model the nonisothermal gas release, phase behavior, and flow of fluids and heat under conditions typical of common natural hydrate deposits (i.e., in permafrost and in deep ocean sediments) in complex formations, and it can describe binary hydrocarbon systems involving methane.
EOSHYDR2 includes both an equilibrium and a kinetic model of hydrate formation and dissociation. The model accounts for up to four phases (gas phase, liquid phase, ice phase, and hydrate phase) and up to nine components (hydrate, water, native CH4 and CH4 from hydrate dissociation, a second native and dissociated hydrocarbon, salt, water-soluble inhibitors, and a heat pseudocomponent). The mass components are partitioned among the phases. The thermophysical properties of the various mass components can be described at temperatures as low as −110°C. Dissociation, phase changes, and the corresponding thermal effects are fully described, as are the effects of salt and inhibitors. The model can describe all possible hydrate dissociation mechanisms (i.e., depressurization, thermal stimulation, salting-out effects, and inhibitor-induced effects).
Results are presented for four test problems of increasing complexity that explore different mechanisms and strategies for production from typical CH4-hydrate accumulations. The results of the tests indicate that CH4 production from CH4-hydrates could be technically feasible and has significant potential. In particular, thermal stimulation is capable of producing substantial amounts of hydrocarbons, and its effectiveness can be enhanced when coupled with depressurization and the use of inhibitors.
Analytical Solutions for 1D Countercurrent Imbibition in Water-Wet Media
Authors: Kashchiev Dimo , Firoozabadi Abbas 
Published: December 2007

Summary
Analytical solutions for the initial stage of 1D countercurrent flow of water and oil in porous media are presented. Expressions are obtained for the time dependence of the water saturation profile and the oil recovered during spontaneous countercurrent imbibition in rod-like, cylindrical, and spherical cores, for which water is the wetting liquid. Some of the analytical solutions are found to be in good agreement with existing numerical solutions and available experimental data for oil recovery from cores with strong water wettability.
A Model for Foam Generation in Homogeneous Media
Authors: Kam S. I. , Rossen W. R. 
Published: December 2007

Summary
Recent laboratory research in a wide range of porous media shows that creating foam in steady flow in homogeneous media requires exceeding a minimum pressure gradient ∇pmin. Data fit trends predicted by a model in which foam generation depends on attaining sufficient ∇p to mobilize liquid lenses present before foam generation. Data show three regimes: a coarse-foam regime at low ∇p, strong foam at high ∇p, and, in between, an unstable transient regime alternating between weaker and stronger foam.
Here, for the first time, a population-balance foam model incorporates a bubble-creation function that depends on pressure gradient. The new model reproduces the three foam regimes seen in the laboratory, the abrupt occurrence of foam generation at a threshold velocity or pressure gradient, hysteresis in experimental results, the interplay between foam stability and foam generation, the effect of injected-liquid fractional flow on foam generation, and foam behavior in the high-quality and low-quality steady-state strong-foam regimes. Once strong foam is created, the details of the lamella-creation function have little further effect on its rheology, which is controlled by other mechanisms. The fractional-flow curves predicted for foam are complex. This model is a necessary step toward quantitative prediction of foam performance in the field.
Fast and Robust Algorithm for Compositional Modeling: Part II - Two-Phase Flash Computations
Authors: Pan Huanquan , Firoozabadi Abbas 
Published: December 2007

SummaryIn Part I of our study, stability analysis testing in the reduced space was formulated, and its robustness and efficiency in comparison to the conventional approach was explored. In this paper, we present formulations including, first, direct solution of the nonlinear equations, and second, minimization of Gibbs free energy for two-phase flash computations in the reduced space. We use various algorithms including the successive substitution (SS), Newton's method, globally convergent modifications of Newton's method (line searches and trust region), and the dominant eigenvalue method (DEM) for direct solution of the nonlinear equations defining two-phase flash and the minimization of Gibbs free energy. We also suggest a criterion based on the tangent-plane-distance (TPD) for the initialization from the equilibrium ratios. The proposed criterion has a significant effect on reducing the number of iterations.The results from various algorithms reveal that the direct solution of the nonlinear equations in the reduced space, combined with the use of the TPD criterion for initialization in the combined SS and Newton's method, can make flash computations extremely efficient. The efficiency and robustness of flash computations in the critical region are especially remarkable.
Conditional Stochastic Moment Equations for Uncertainty Analysis of Flow in Heterogeneous Reservoirs
Authors: Li L. , Tchelepi H. A. 
Published: December 2007

SummaryWe assume that permeability is a random space function defined by its mean and covariance. The stochastic nature of the permeability description leads to uncertainty in flow-related quantities such as pressure, saturation, and production rate. We extended our statistical moment equation (SME) approach to accommodate conditioning. The conditional statistical moment equations (CSME) framework is a direct approach for quantifying the uncertainty in flow performance caused by uncertainty in the reservoir description. It is quite different from Monte Carlo Simulation (MCS). In MCS, the performance uncertainty is obtained through a statistical post-processing of flow simulations, one for each of a large number of equiprobable realizations of the reservoir description. We developed a CSME computational tool for flow in heterogeneous domains, which we use here to analyze the behavior of the second statistical moment of pressure and velocity in the presence of permeability measurements. We study the effect of both the number and spatial arrangement of available measurements on the computed variances of pressure and velocity. This numerical CSME tool allows us to quantify the value of existing and future information, and that helps in the evaluation of existing projects and in steering future developments. We present several examples that demonstrate how to choose the best sampling locations to obtain maximum reduction in prediction uncertainty. We compare our results with high-resolution MCS.
Reducing Gas-Production Decline Through Dewatering: A Case History From the Naturally Fractured Aguarague Field, Salta, Argentina
Authors: Aguilera R. , Conti J. J. , Lagrenade E. 
Published: December 2007

Summary
The Aguarague field is located in the Devonian basin, northwest of the province of Salta, Argentina. Gas production is obtained from clastics of the Huamampampa formation through an intense network of natural macro- and microfractures. The reservoir is in a north/south-trending symmetrical anticline.
Five high-deliverability gas wells watered out between 1991 and 1994; as a result, the field gas production decreased substantially. This triggered a study in 1995 to try to find a means of extending the life of the reservoir. The study indicated that without any modifications, gas production could be expected to continue, at most, until 1999.
This paper describes how a detailed fracture characterization led to a dewatering project using gas lift, which significantly reduced the gas decline of the reservoir. The project also brought back to gas production some of the wells that had previously watered out. The 1995 forecast is compared with the actual production performance to date.
Estimating Multiphase-Flow Properties From Dual-Packer Formation-Tester Interval Tests and Openhole Array Resistivity Measurements
Authors: Zeybek M. , Ramakrishnan T. S. , Al-Otaibi S. S. , Salamy S. P. , Kuchuk F. J. 
Published: December 2007

SummaryMultiphase flow and production cuts are affected significantly by relative permeabilities under reservoir conditions. However, their in-situ determination is practiced only in isolated instances, and these have used array resistivity logging. Although wireline dualpacker formation testers provide direct flow tests, analysis thus far has been confined to the determination of single-phase permeability and anisotropy. In this paper, we present a methodology to integrate the formation-tester pressure and water-fraction measurements with openhole array resistivity measurements to obtain zonal relative permeabilities of oil and water.It has been demonstrated previously that the filtrate-invasion process, although uncontrolled, contains quantitative information about fractional flow. The sampling process is similar; it is described by the multiphase/multicomponent flow equations for which the initial condition is set by the invasion process. Geometrically, while the invasion process is largely cylindrical, the sampling process is not. To combine the two, we parameterize the invasion problem in terms of multiphase-flow properties and drilling-fluid loss and carry out a simulation exercise, including generation of resistivity logs. The fractional-flow parameters estimated by matching the observed resistivity logs are then used for modeling fluid sampling with a formation tester. Simultaneous matching of the simulation results with the observed water-cut and pressure data allowed for further refinement of the relative permeability curves. A field example of the application of this methodology will be discussed.