bluuebunny/crossref_metadata_2025_split huggingface dataset:
Soft Computing Algorithms Accelerate and Improve the History-Matching Process: Elk Hills, California—29R Reservoir
Authors: Firincioglu T. , Ozgen C. , Albertoni A. , O'Brien W. J. , Girbacea R. A. 
Published: December 2007

Abstract
This paper presents the application of soft computing (virtual intelligence) techniques1 to a reservoir simulation history matching problem. The objective of this work was not to automate the history matching process as has been discussed by others2-7, but rather to provide the engineers with the necessary information to improve the speed and quality of their results.
Through the use of virtual intelligence techniques history match error (mismatch – the difference between calculated and observed flow and/or pressure) is correlated to variations in individual history match parameters such as porosity and permeability. An objective function that describes the criteria to minimize the mismatch is defined.
This technology always finds the global minimum associated with the objective function. The technology provides multiple solutions that satisfy any error criteria, and produces related statistical information. The technology can handle continuous or discrete history match parameters.
In this paper we discuss the successful application of this technology to a simulation study of a complex, fractured, porcelanite oil reservoir (29R, Elk Hills field, California). This field has 28 years of history with 42 production wells. A dual porosity formulation was necessary to properly model the fractured nature of the reservoir. Successful history match results obtained in a short period of time for this field showed the accuracy and practicality of this unique history matching technology.
Openhole Horizontal Completions in Niger Delta
Authors: Arukhe J. , Senyk R. , Adaji N. , Adu O. , Nwoke L. , Adegborioye T. , Ogoke V. , Oyebanji P. , Arellano J. L. 
Published: December 2007

Abstract
The Niger Delta is a highly activity region in open hole applications. A wide variety of completion types have been deployed in open hole in the region. A major challenge in these completions is to deliver quality wells through the choice of an optimal sand control system. A locally developed database tracks the performance of the sand face completions, their reliability, observed failures and their causes. The oil reservoirs have used barefoot, standalone screens, slotted liners, gravel packs and expandables while pre-drilled liners have been used for borehole support. The expandable technology is relatively the most recent technique but of the three hundred and forty run so far globally as at September 2005, more than 3/4 has been deployed in Niger Delta alone.
For the non-associated gas reservoirs, most of which have been conventional wells, based on fair understanding of the risks and uncertainties associated with two main sand control options namely, gravel packing and the expandable sand screens, work has been done to show adequate demonstration of the process of selection. This structured approach considers design options based on several factors such as possible problem with under-reaming relatively deep sections, previous performance in the existing high rate gas wells, productivity and better life cycle design perspectives. Within the Darcy permeability regime of the sandstone gas reservoirs, productivity with respect to horizontal versus conventional completion was compared and a matrix capturing the risks impact of a horizontal completion is attempted.
The work concludes by suggesting future concerns in open hole horizontal sand control to include cost of installation failure, accurate modelling upfront and remedial zone isolation after gas/water breakthough
Critical Evaluation of Existing Methods for Accounting for Multiphase Effects Around Producers in Depleting Gas Condensate Reservoirs
Authors: Estrada C. A. , Settari A. 
Published: December 2007

Abstract
Well test analysis techniques use variations of the pseudopressure concept to account for multiphase effects due to condensate drop-out in near-well regions (e.g. Jones and Raghavan1 approach). In this work, an evaluation of the accuracy and applicability of these techniques was carried out using data from the discovery well of the Cupiagua field, including well testing, relative permeabilities (Kr) measured at low capillary number and a tuned PREOS.
Henderson et al's capillary number dependent relative permeability and effective inertial resistance correlations2, as implemented in a commercial simulator, were used to history match the well test data. To investigate the assumptions in the analytical models, numerical simulations were run, first with constant Kr, and then with the effect of capillary number and inertial resistance.
The main conclusions are: For the constant Kr simulation, a constant composition expansion (CCE) data of the flowing composition accurately reproduces the pressure-saturation relationship in the region where both oil and gas are mobile. However, contrary to Fevang and Whitson's assumption3, the constant volume depletion (CVD) data did not match the saturation distribution of the region where only gas flows.When Kr dependence on capillary number and inertial resistance was considered, the immobile oil region practically disappeared. In consequence, the CCE data of the original fluid composition can reproduce the pressure-saturation relationship in the two phase region.Al-Hussainy et al's total skin versus rate plots4 to obtain mechanical skin figures were found to give results similar to those obtained by numerical simulation.
In summary, this work identifies clearly the conditions under which the analytical models are not correct, which data should be used for analysis, and when the numerical instead of an analytical approach is required.
Interaction Between Scale Inhibitors and FeCO3 Precipitation on Carbon Steel
Authors: Foss M. , Seiersten M. , Nisancioglu K. 
Published: December 2007

Abstract
Transportation of wet (water containing) gas and condensate in carbon steel pipelines requires corrosion control. By increasing the pH to a level where FeCO3 precipitates as a protective film on the iron surface the corrosion rate can be reduced to a low level. This method, called pH stabilization, is primarily used for carbon steel pipelines with no co-production of formation water and where glycol is applied as hydrate inhibitor. Increasing the pH promotes precipitation of carbonates of Ca2+, Ba2+ and Sr2+. To prevent excessive scaling, scale inhibitors might be added. The effect these scale inhibitors have on the corrosion rate of steel was the main focus for this study. Two scale inhibitor products were tested. Both products increased corrosion at high pH by preventing growth of protective carbonate films. The scale inhibitors also affected FeCO3 film formed prior to inhibitor addition. In addition they reduced the corrosion rate as such. The resulting corrosion rate was lower than the rate without carbonate film at the same pH, but higher than the rate with protective film. Overall, the corrosion rate was too high.
Injectivity Impairment Due to Sulfate Scaling During PWRI: Analytical Model
Authors: Bedrikovetsky P. , Mackay E. , Monteiro R. P. , Patricio F. , Rosário F. F. 
Published: December 2007

AbstractPrevious work has derived an analytical model for simultaneous flow of incompatible waters in porous media with sulphate salt precipitation, determined typical values of kinetics reaction coefficient from corefloods and what the impact would be on productivity impairment during sulphate scaling.This paper extends the previous work, by modelling the injectivity impairment during simultaneous injection of incompatible waters, i.e. cation-rich produced water (PWRI) and seawater with sulphate anions. An analytical model with explicit expressions for deposited concentration and injectivity decline was developed.The location of scale deposition and the resulting injectivity impairment are calculated for a range of sensitivities, including reaction kinetics (ranging from minimum to maximum values as obtained from coreflood and field data), fraction of produced water in the injected mixture and barium concentration in produced/re-injected water.The theoretical parameter of the size of formation-damaged zone was introduced. It was found out that almost all deposition takes place in 2-4 well radii neighbourhood. Calculations show that simultaneous injection of seawater with produced water containing even decimal fractions of ppm of barium would results in significant injectivity decline.
Increasing the Production From Marginal Gas Wells
Authors: Bowman C. W. , Collins J. A. 
Published: December 2007

Abstract
A large number of gas production wells in Europe are mature and are virtually incapable of lifting liquid, which has built up over time, out of the well. A well in a gas field was suffering from these liquid loading problems. The gas pressure was insufficient to unload the well for an extended period of time. A proprietary computer model, developed by Baker Petrolite and specifically designed to identify wells which will respond to chemical treatment, was used to determine whether a foamer product could help unload the gas well. Removal of the water would also help to reduce downhole corrosion. The application of the foamer also had to take into account the different gas well operating standards in Europe compared to those of some other parts of the world. Subsequent selection of the foamer was achieved by the use of the computer model and by laboratory test work using actual well fluids. Consequently the chemical was applied downhole by continuous injection via capillary tubing.
The maximum production rate achieved during the trial was 0.1 MMSCMD. The volume of gas production was increased five-fold. No problems were encountered with downstream processing. The use of this foamer technology was of considerable value to the gas producer in this marginal field.
It was shown that the rapid and methodical use of these unique services can help alleviate the loss in gas production shown by wells suffering from liquid loading.
A Dynamic Economic Indicator to Evaluate SAGD Performance
Authors: Shin H. , Polikar M. 
Published: December 2007

Abstract
A new economic indicator, called simple thermal efficiency parameter (STEP), was developed to evaluate the performance of a steam-assisted gravity drainage (SAGD) project. Its usefulness as an economic indicator was validated qualitatively and quantitatively. STEP is based on cumulative steam-oil ratio (CSOR), calendar day oil rate (CDOR) and recovery factor (RF) for the time corresponding to an instantaneous steam-oil ratio (SOR) of 4.
In this study, a dynamic model for STEP called STEP-D was developed to be used as an economic indicator under the changing conditions of the economic limit of SOR and heavy oil price. STEP-D is calculated from the original STEP value by including the two dynamic factors, heavy oil price and SOR economic limit. The results showed a good linear relationship between STEP-D and net present value (NPV), with a higher than 0.93 correlation coefficient. STEP-D may therefore be a valuable economic indicator under dynamic situations.
An Integrated Technique for Production Data Analysis With Application to Mature Fields
Authors: Gaskari R. , Mohaghegh S. D. , Jalali J. 
Published: December 2007

ABSTRACT
The most common data that engineers can count on, specially in the case of mature fields is production data. Practical methods for production data analysis have come a long way since their introduction to the industry several decades ago and they all fall into two categories: Decline Curve Analysis (DCA) and Type Curve Matching (TCM). While Decline Curve Analysis is independent of any reservoir characteristics Type Curve Matching is a very subjective procedure.
State of the art in production data analysis can provide reasonable reservoir characteristics but it has two major shortcomings:
For reservoir characterization, the process requires bottom - hole or well-head pressure data in addition to rate data. Bottom-hole or well-head pressure data are not usually available in most of the mature fields.
A technique that would allow the integration of results from hundreds of individual wells into a cohesive field-wide or reservoir-wide analysis for business decision making is not part of today's production data analysis toolkit.
In order to overcome these shortcomings a new methodology is introduced in this paper that has three unique specifications:
It does not require pressure data (bottom-hole or well - head); It integrates decline curve analysis, type curve matching, and numerical reservoir simulation (history matching) in order to iteratively converge to a near unique set of reservoir characteristics for each well; It uses fuzzy pattern recognition technology in order to achieve field-wide decisions from the findings of the analysis.
New, Rigorous Material Balance Equation for Gas Flow in a Compressible Formation With Residual Fluid Saturation
Authors: Rahman N. M. A. , Anderson D. M. , Mattar L. 
Published: December 2007

Abstract
Modern computing power has enabled very high accuracy and efficiency in complex calculations. Thus, it follows that reservoir engineering formulations need not be approximate solutions, as was sometimes historically the case. Being one of the most widely used techniques in reservoir engineering, the material balance equation (MBE) for gas is an excellent example of this. The MBE is used not only for estimating the original gas-in-place (OGIP), but also for calculating the decline in average reservoir pressure with depletion. In the majority of cases, the conventional p/Z formulation of the gas material balance is satisfactory. However, certain circumstances, which are sometimes unpredictable, demand formulations with greater accuracy. Although modifications to the standard approach have been presented, to the authors’ knowledge, there is no published gas material balance formulation that is completely rigorous. This study presents a new, rigorous MBE for gas flow in the presence of a compressible formation and residual fluid saturation. Examples will be presented to highlight the capabilities of the new MBE.
Using Reservoir Modeling To Evaluate Stimulation Effectiveness in Multilayered "Tight" Gas Reservoirs: A Case History in the Pinedale Anticline Area
Authors: Schubarth S. K. , Spivey J. P. , Huckabee P. T. 
Published: December 2007

Abstract
Low permeability, or "tight", gas reservoirs are being developed at an ever increasing rate in the U.S. The amazing increase in activity in the Rocky Mountain region over the past decade is a testament to this. Currently, there are several "tight" gas plays in the U.S. that involve the commingling of multiple intervals in order to gain economic viability. The Pinedale Anticline of southwestern Wyoming is one of these areas. The Pinedale Anticline completions pose a particularly complex problem when attempting to evaluate the "best" method of stimulation because as many as twenty-two separate stimulation treatments are placed in up to 70 discrete sand intervals over a gross interval up to 6,000 feet thick. Evaluations are further complicated by variation in permeability exceeding two orders of magnitude and pore pressures increasing from 0.44 psi/ft to 0.83 psi/ft.
The analysis of "tight" gas reservoirs has been the topic of many SPE papers over the past twenty years. Several have presented data indicating the broadness of the permeability distribution which may be encountered when developing these reservoirs1,2,3. The broadness of the permeability distribution, often over two orders of magnitude in breadth, poses a statistical problem when trying to simply compare production response of one set of data to another in a given field. We will quantify the significance of this and present statistical evaluations documenting the probability of obtaining two similar data sets with respect to permeability when broad distributions exist. We then compare the size of the sample set necessary to quantify stimulation effectiveness using production alone with the sample size required when using reservoir simulation.
The reservoir simulation analysis presented in the paper demonstrates a process for use in multiple layered reservoirs for evaluating stimulation effectiveness. The process requires significantly fewer field tests than if production rates were used alone. Multiple production logs were utilized over several producing months in selected wells and are crucial to the production history match process. A wide variety of proppant products are investigated and compared to expected performance from published specifications. This paper will aid engineers working in multi-layered reservoirs understand the complexity of the evaluation process and give them a process for evaluating stimulation effectiveness in their reservoirs.
Quantifying Uncertainty in Original-Gas-in-Place Estimates With Bayesian Integration of Volumetric and Material Balance Analyses
Authors: Aprilia A. W. , Li Z. , McVay D. A. , Lee W. J. 
Published: December 2007

ABSTRACTAccuracy in hydrocarbon reserves estimates affects virtually every phase of the oil and gas business. Unfortunately, reserves estimates are uncertain, since perfect information is seldom available from the reservoir, and uncertainty can complicate the decision-making process. Managers have to make many important decisions early (e.g., facilities expansions, development drilling, etc.) without reliable knowledge of reserves. Thus, it is probably more important to quantify reserves uncertainty early than any other time in the life of a reservoir.Reserves are closely related to original hydrocarbons in place (OHIP). Two methods for estimating OHIP are volumetric and material balance methods. The volumetric method is convenient to calculate OHIP during the early development period, while the material balance method can be used later, after some performance data, particularly pressure and production information, are available. Both methods may have substantial uncertainty.In this paper, we present a methodology that uses a Bayesian approach to quantify the uncertainty of original gas in place (G), aquifer productivity index (J), and the volume of the aquifer (Wi) by combining volumetric and material balance analyses in a water-driven gas reservoir.The results show that we potentially have large uncertainty in OGIP estimates when we consider only volumetric analyses or only material balance analyses. However, by combining the results from both analyses, the uncertainty can be reduced. This reduction in uncertainty should lead to better management decisions in many cases.
Simulation-Based Technology for Rapid Assessment of Redevelopment Potential in Stripper-Gas-Well Fields—Technology Advances and Validation in the Garden Plains Field, Western Canada Sedimentary Basin
Authors: Cheng Y. , McVay D. A. , Wang J. , Ayers W. B. 
Published: December 2007

Abstract
It is often difficult to quantify the redevelopment potential of marginal oil and gas fields due to a wide range of depositional environments, variability in reservoir properties, large numbers of wells, and limited reservoir information. With traditional simulation methods, evaluation of infill potential for these fields is time consuming, labor intensive and frequently cost-prohibitive. Without adequate assessment technology, some unprofitable infill campaigns may be initiated while other promising infill campaigns may be terminated prematurely due to disappointing early results.
In this study, we developed a simulation-based regression technique to assess infill drilling potential in stripper gas well fields. With limited, basic reservoir information, this technique first estimates the spatial distribution of subsurface reservoir properties by rapid history matching of well production data. We implemented a sequential regression algorithm to estimate not only the permeability distribution, but also, the pore volume distribution from available flow rate measurements. Future production is forecast and infill drilling potential is determined using the estimated permeability and pore volume distributions. Because the method employs an approximate reservoir description, it identifies regions of the field with promising infill potential rather than individual infill well locations.
The proposed technique provides rapid, reliable and cost-effective assessment of redevelopment potential in stripper gas well fields. In the paper we first validate our approach using synthetic reservoir data. We then apply the approach to the Second White Specks formation, Garden Plains field, Western Canada Sedimentary Basin. Prediction of infill potential in this gas field, which has more than 700 wells, demonstrates the power and utility of the proposed technique.
The Tools, Techniques, and Advantages Involved in Combining Compression and Plunger Lift in Low-Rate Gas Wells
Authors: Schmitz R. A. , Steele G. D. 
Published: December 2007

Abstract
Plunger lift and compression are two common methods of dealing with liquid loading issues in natural gas wells. However, as the average productivity of the gas wells in the Western Canadian Sedimentary Basin continues to decline, these methods on their own are no longer sufficient for many wells. However, plunger lift combined with compression, using newly-developed and innovative tools and techniques, can provide a solution for many low-rate wells that could not otherwise be produced cost-effectively.
Quasinatural Consolidation of Poorly Consolidated Oilfield Reservoirs
Authors: Larsen T. , Lioliou M. , Josang L. O. , Ostvold T. 
Published: December 2007

Abstract
A new method to prevent sand permeation from unconsolidated or poorly consolidated reservoir formations has been developed. The Quasi Natural Consolidation (QNC)-method involves a controlled in situ precipitation of calcium carbonate scale on sand grains. Experiments show that calcium carbonate forms bridges between sand grains and strengthens the unconsolidated sand pack. The QNC-solution contains Ca2+, urea and urease. When this single-phase solution is injected into the sand pack, calcium carbonate precipitates at a rate which is dependent on the urease concentration and temperature. A series of batch experiments have been carried out in order to establish the optimum solution chemistry/composition for sand consolidation. Consolidation experiments have shown that this method is applicable in the temperature range from 25 °C to at least 65 °C. An untreated sand pack collapsed at a water flow velocity of &lt; 0.01 cm/s (Q/Atot). However, after two QNC-injections at either 25, 50 or 60 °C the sand packs could withstand a water flow velocity &gt;0.38 cm/s without producing sand. The permeability dropped about 25% from the initial ~10 Darcy. Uniaxial strength tests showed that up to 10.56 MPa could be obtained after four injections. Consolidation was obtained also with presence of oil in the sand pack, although with a somewhat reduced efficacy of the treatment. Permeability measurements indicate that the relative water permeability is reduced more than the relative oil permeability after treatment.