bluuebunny/crossref_metadata_2025 huggingface dataset:
A Guide to High Pressure Air Injection (HPAI) Based Oil Recovery
Authors: Moore R. G. , Mehta S. A. , Ursenbach M. G.
Published: December 2007

In recent years, high pressure air injection (HPAI) has proven to be a valuable IOR process, especially in deep, high pressure, low permeability fields where other recovery processes are uneconomic.

This paper will provide engineers and engineering managers with a wide-ranging look at the key factors that should be addressed when considering a high pressure air injection (HPAI) based IOR process in a light oil reservoir. The paper is based on many years of involvement of the authors both in the laboratory and the field, as well as drawing on published literature.

The main focus is on key design and operating criteria that must be considered, including reservoir screening, air injection design, ignition, and monitoring. The benefits and potential risks of HPAI are also discussed.

Along with the discussion of design and operating criteria, the paper contributes significantly in the comparison of oxidation/combustion kinetics for light oils versus heavy oils (HPAI versus in situ combustion), as well as in a discussion of the oil mobilizing effects of a gas flood compared to an advancing thermal (combustion) front.
Time-Dependent Shape Factors for Secondary Recovery in Naturally Fractured Reservoirs
Authors: Penuela G. , Hughes R. G. , Civan F. , Wiggins M. L.
Published: December 2007

An accurate interporosity flow equation incorporating a time-dependent shape factor is derived and verified for improved dual-porosity modeling of waterflooding in naturally fractured reservoirs. This equation expresses the interporosity exchange rate in terms of the oil phase pressure gradient in the matrix, fracture surface area, fluid effective permeability at the matrix/fracture interface, fluid viscosity and a variable matrix-block shape factor. This approach can accommodate the flow directed from matrix to fractures while representing the permeability of interconnected fractures as a tensor. The model equations are expressed in dimensionless form for convenient integration into present numerical simulators for accurate simulation of waterflooding in naturally fractured reservoirs. These features distinguish this model from the conventional sugar-cube modeling of naturally fractured reservoirs.

Fine-grid numerical simulation of a matrix block is performed to verify the flow equation using the time-dependent shape factor. Numerical experiments with various size matrix blocks indicate the shape factor varies with time and converges to the steady-state shape factor value reported in previous studies for single-phase flow. The shape factor for single-phase flow converges to a steady-state value at a speed proportional to the reciprocal of total compressibility, while the shape factor for two-phase flow converges at a speed proportional to the slope obtained from the capillary pressure curve evaluated at the average water saturation present at the matrix/fracture interface. Therefore, the single-phase shape factor converges much more rapidly to its steady-state value than the two-phase shape factor.

This study demonstrates that neglecting the time-dependency of the shape factor introduces significant errors in fractured reservoir simulation, and time-dependent shape factors are needed because of the variation of the water saturation front location in the matrix block, which moves from the fracture face to the block-center as the water flows from the fracture into the matrix.
Effects of Stimulating Indigenous Bacteria in Oil Reservoirs on Relative Permeability Curves
Authors: El Ela M. Abu , El-Tayeb S. , Sayyouh M. H. , Dayem M. Abdel , Desouky S.
Published: December 2007

Laboratory studies show the existence of some strains of bacteria in field crude oils and formation waters. This work is concerned with studying the effect of indigenous bacterial activities on the relative permeability of samples from Egyptian fields. Such study is an original contribution to the knowledge of microbial enhanced oil recovery.

Phase volume studies were carried out using two types of crude oils having different spores forming bacteria. The relative permeability experiments were conducted in sandstone cores. Some available nutrient solutions being used in the field tests were also used.

Based on the phase volume measurements, it was found that the indigenous microbial growth was better after two days incubation time with 1% molasses concentration as a nutrient. Residual oil saturation was found to decrease with stimulating the indigenous bacteria in the crude oils by using 1% molasses concentration. Presence of 1% molasses concentration increases the relative permeability to oil. It was found also that crude oil A, which contains Clostridium sp. and Bacillus sp., gave better relative permeability curve behavior than that of crude oil B, which contains Bacillus sp. only. Salinity increase decreases the relative permeability to oil. In the presence or absence of molasses, no clear trend of absolute permeability on oil-water relative permeability curves was observed.

The results obtained are discussed and analyzed in terms of the system phase variation, interfacial forces, wettability characteristics, hydrogen ion concentrations, viscosity effects, and mechanical and mineralogical analysis of the cores.
Microscopic Visualization with High Resolution Optical-Fiber Scope at Steam Chamber Interface on Initial Stage of SAGD Process
Authors: Sasaki Kyuro , Satoshi Akibayashi , Yazawa Nintoku , Kaneko Fuminori
Published: December 2007

Experiments and numerical simulations on initial stages of the steam-assisted gravity drainage (SAGD) process were carried out. Experimental studies used two-dimensional scaled reservoir models to investigate fluids flow characteristics in the steam chamber and production fluids. The rise and growth of the initial steam chamber were observed and visualization of micro-phenomena at inclined interface on the side of the steam chamber with a high-resolution optical-fiber scope was carried out. Very fine water droplets of 0.01 mm order in size were observed at the interface between steam and heavy oil phases. These droplets entered into heavy oil phase and created emulsion together with the heated oil, which flowed down and was produced from the production well. It was successfully demonstrated that these micro phenomena has an influence on chamber expansion rate in horizontal direction and oil production rate.

The numerical simulation of the SAGD process was also performed. The thermal simulator, CMG's STARS™ was used to simulate the experimental steam chamber growth at the initial stage. The simulation used the two-components (water and heavy oil) black oil, three-phase (water, heavy oil and steam) and three-dimensional numerical model for the physical model. The results from the history-matched numerical simulation were found to be in good agreement with those of the experiments for oil production and steam chamber shape by using the Intermediate3-Stone1 wettability model represents fluids behavior cumulating the microscopic phenomena at the chamber interface. Furthermore, a new process named Surfactant-SAGD injecting a surfactant before starting steam injection to enhance the communication between two wells and mobility of the production fluids was tested.
Production Type Curves for the Hunton Formation
Authors: Frederick Jeff L. , Kelkar Mohan , Keefer Brian
Published: December 2007

The Hunton Formation is one of the most promising formations producing oil and gas in Oklahoma. The formation has an anomalous producing behavior. At the inception, the wells produce at relatively high water-oil and gas-oil ratios. Eventually, both the WOR and GOR decrease. This results in increase in oil cut and hence reduction in lifting costs over time. Because of relatively high WOR's, many operators are discouraged from completing the wells, and hence abandoning the effort to produce oil from these formations.

We concentrate on West Carney Field, Lincoln County, Oklahoma for this investigation. The field was "re-discovered" in 1995, and significant drilling activities continue in the field today. The field produces various amounts of gas, oil and water from each well. Because of varying gas oil ratios and water oil ratios over the field, a simple decline curve analysis is not applicable to determine the hydrocarbons in place. Attempts to calculate the reserves based on the electric log data have produced inconsistent results because of poor correlation between log signatures and productivity and connectivity of wells.

In this study, we provide a technique for evaluating the performance of producing wells. Because the wells have variable rates and variable bottom hole pressures, we used the concept of equivalent time as proposed by Agarwal et al. (SPE 57916), and show that we can correctly predict the reserves estimate. Also, we show that it is possible, using Agarwal et al's equivalent time concept, to use automatic type curve matching to predict values of permeability and skin factor.

We evaluate the gas, oil and water rates separately to calculate permeability and skin factor. We then use the results to estimate recovery factors and the quality of our initial completions. This type of analysis is useful for economic evaluation, planning of surface facilities, and future field development and exploitation. Further, if sufficient early production data are available, the procedure can also allow us to predict various reservoir parameters that can be used for additional evaluation.
Evaluation of Crossflow Effects in Multilateral Wells
Authors: Zhu D. , Hill A. D. , Landrum W. R.
Published: December 2007

As drilling and completion technology has advanced dramatically, developing new oil fields faces new opportunities of well structure selection, especially for the fields that are sensitive to issues such as environmental conservation, cost effectiveness, safety control, and well management. Horizontal, multi-branching and multilateral technologies have been used in many field applications all over the world to enhance the reservoir recovery in a cost-effective way. When the well structures become complex, producing from these "fancy wells" could become difficult, and sometimes, detrimental to overall recovery. To study the strategies for optimizing multilateral wells, we have developed a mathematical model to predict well performance for horizontal and multilateral wells using coupled multiphase models of wellbore/reservoir flow. The flow distribution along the laterals is predicted as a function of tubing head pressure (deliverability of the well), and overall well performance as a function of time is predicted by a simple material balance relationship.

A common problem for such wells is that commingled production from multilateral branches can often lead to crossflow from one reservoir compartment to another. The likelihood of crossflow depends on initial reservoir conditions, but also very much on the operating conditions of the well. Deleterious interactions between commingled reservoirs accessed by multilateral wells must be reliably preventable for these types of completions to have broad application. Some case studies and hypothetical examples are presented in the paper to show the procedures for optimizing the well structure and well performance. Production strategies that would help to eliminate crossflow are discussed.
Propagation of Cross-linkers Used in In-Situ Gelled Acids in Carbonate Reservoirs
Authors: Nasr-El-Din H. A. , Taylor K. C. , Al-Hajji H. H.
Published: December 2007

In-situ gelled acids are used in well stimulation to improve sweep efficiency during acid placement. These acids comprise a polymer, a cross-linker and a breaker in addition to chemicals used with regular acids. The gelation reaction in these systems occurs over a narrow range of pH (2-4). The gel forms once the acid reacts with the carbonate formation and the pH rises to a value above 2. The gel breaks once the pH rises above a value greater than 4. Propagation of the crosslinker plays a key role in the success of these acids. However, in a recent paper by Lynn and Nasr-El-Din,1 there was evidence of precipitation of the cross-linker in some systems. The cross-linker is typically a multi-valent cation (iron(III) or zirconium(IV)), which may precipitate at high pH values or react with hydrogen sulfide (in the case of sour wells) to precipitate damaging material. Coreflood experiments were conducted at 100°F in a linear mode to determine the rate of propagation of various cross-linkers in reservoir cores (mainly calcite). This temperature represents bottom hole temperature of seawater injectors in a carbonate reservoir in Saudi Arabia.

Propagation of the cross-linker in carbonate cores was examined by measuring the concentration of the cross-linker in the core effluent and comparing it with the chloride ion concentration (used as a tracer). The profile of the tracer was used to determine dispersion of the acid in the core, whereas the area between the tracer and cross-linker profiles was used to determine the amount of cross-linker precipitated or retained in the core. The effects of acid concentration, slug volume, injection rate, cross-linker type, and polymer loading on the rate of propagation of the cross-linker were examined in detail.

The following conclusions were made. 1. Viscous fingering effects that occur during pumping low-viscosity post-flush fluids affect the propagation of the cross-linker in reservoir cores. 2. The rate of propagation of the cross-linkers depends on the type of cross-linker used (iron, zirconium, etc.), and 3. Results of this study will help production engineers to design acid treatments with minimum damage due to precipitation/retention of the cross-linker.
DOWS Downhole Oil-Water Separation Cross-Waterflood Economics
Authors: Jokhio S. A. , Berry M. R. , Bangash Y. K.
Published: December 2007

Downhole oil-water separation (DOWS) provides the ability to conduct a cross-waterflood using a single wellbore that penetrates stacked waterflood zones. In this application of DOWS technology, production from one waterflooded zone is used as the inlet stream to the separation process. The oil-rich stream is produced to the surface while the water stream is injected into the second zone as shown in Fig. 5.

Potential benefits include reduced well count, reduced lifting costs, reduced expenditures for surface water handling facilities, reduced treating costs, smaller surface footprint and reduced environmental risk. Potential disadvantages include DOWS installation costs, more expensive workovers, more difficult and costly monitoring and larger wellbore requirements.

DOWS technology is widely viewed as a potentially highly valuable technology with a high price tag and a high risk of failure. A major failure node for DOWS installation is the injection zone. Injection into a water flooded zone reduces the injectivity problems, and provides a benefit from the work required to inject the water stream. If a DOWS installation can economically be justified on its own merits anywhere, it will be in a cross-water flood application. The question remains; Can a DOWS cross-water flood be economically justified?

This paper is divided in four parts. First, DOWS technology in general and cross-waterflood application in particular are briefly described. Second, the operational advantages and disadvantages of this application of DOWS technology are briefly discussed. Thirdly the parameters of economic model are reviewed in some detail. Lastly, the characteristics of a waterflood operation that can benefit economically from this technology are summarized.
Energy Sources and Energy Intensity for the Twenty-First Century
Authors: Economides M. J. , Demarchos A. S. , Saputelli L.
Published: December 2007

A country's wealth is closely related to its energy consumption. For example, the United States, the richest nation, with a per capita income of about $34,000 is also one of the highest consumers of energy with an annual per capita consumption of about 355 million British thermal units (MMBTU). Energy consumption is the most discernible national characteristic that separates rich from poor countries. The correlation between per capita energy consumption and per capita income among all nations is clear. However, the energy use in other developed countries is also a function of their geography, the makeup of those countries and even the cultural preferences of their citizens.

Throughout the last two centuries, energy consumption in the creation of wealth and the form of primary energy sources, have not been constant. The process has been dynamic and technology has played a considerable role in the changing of the status of many countries, most notably Japan. Efficiencies developed elsewhere are adopted by other countries and lead to an increase in wealth. Globalization of the economy will certainly aid this process in the future.

Energy consumption and heightened demand worldwide, may prove perhaps the most formidable international challenge of the twenty first century. As early as 2010, at current energy growth, chronic energy shortages are likely to emerge which may evolve into a serious energy crunch. The most logical way to prevent this situation is to transition rapidly to natural gas and, eventually, to hydrogen. In this paper, natural gas is viewed as the compelling next fuel of choice and as the necessary stepping-stone towards hydrogen. Also offered here are production, consumption and transition forecasts.
Applicability of Sachdeva's Choke Flow Model in Southwest Louisiana Gas Condensate Wells
Authors: Guo Boyun , Al-Bemani Ali Soud , Ghalambor Ali
Published: December 2007

Sachdeva's multiphase choke flow model has capabilities of predicting critical-subcritical boundary and liquid and gas flow rates for given upstream and downstream pressures. Although this model was shown to be accurate by Sachdeva et al. in their original paper using laboratory and field data, inaccuracy of the model has been found in other field applications. It is highly desirable for production engineers to find the applicability of this model when it is applied to gas condensate wells.

In this study, the accuracy of the Sachdeva's choke model was evaluated using data from oil and gas condensate wells in Southwest Louisiana. Comparisons of the results from the model and field measurements indicate that Sachdeva's choke model generally under-estimates gas and condensate flow rates. Based on measurements from 239 gas condensate wells it was found that the model under-estimates gas rate and liquid rate by as much as 40% and 60%, respectively. The model also failed to calculate mass flow rates for 48 condensate wells where relatively low-pressure differentials at chokes and high-flow rates were observed.

The investigation further went on to improve the performance of Sachdeva's choke model. It was found that the error of the model could be minimized using different values of choke discharge coefficient (CD). For gas condensate wells, the error in gas flow rate calculations can be minimized using CD = 1.073. However, the error in liquid flow rate calculations for condensate wells is minimum when CD = 1.532.
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

The Aguarague field is located in the Devonian Basin, NW 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 and as a result the field gas production decreased substantially. This triggered a study in 1995 to try to find a means of enlarging the life of the reservoir. The study indicated that without any modifications gas production could be expected to lapse at most to 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.
Stepwise Compositional Simulation of a Multilayer, Giant Gas Condensate Field
Authors: Jimenez T. , Marruffo I. , Cabrera J. , Cosentino L. , Caussade S.
Published: December 2007

The Oficina Formation, Eastern Venezuela, contains large amounts of gas reserves, which are strategic for the energetic policy of the country. In the Zapatos-Mata R field, these reserves are stored in a thick transgressive sequence of deltaic channels and shore bars (over 3000 ft), as rich gas condensate accumulations of various importance, from few to hundreds of Bcf. Over 400 wells have been drilled in the area since the 1950's, which in general have been selectively completed in progressively shallower intervals. Gas injection has been implemented in most of the main reservoirs since the early 1960's.

An integrated reservoir study was started during year 2000, with the aim of establishing a new exploitation strategy by means of a simulation model. However, early in the project, it became obvious that a straight full field simulation would have been a prohibitive task, given the complexity of the geology, the variation in the fluid type and properties, and the number of wells, completed intervals and reservoirs (almost 700 official reservoirs were reported in the study area). Still, the availability of a full field model was deemed critical to establish a representative exploitation plan in the prediction phase, especially because a commingled production option is being considered.

An original procedure was therefore defined, based on a stepwise approach. In a preliminary stage, simulation studies were carried out individually for the most important reservoirs. The modeling was performed using a full compositional formulation. Several of these models were built and partially history matched.

In a later stage, these individual models were lumped together in a progressive mode, while checking the quality of the history match. This process eventually led to the building of a full field model, including all the most important reservoirs and over 80% of the total reserves of the area. This model has about 65 layers and more than 300,000 active cells.

Conclusions of the study showed that this stepwise approach is an interesting option for the full scale simulation of giant multilayer gas condensate reservoirs, since it allows for the decoupling of the problems related to the model building and history match issues, which are faced and solved early in the simulation process. Moreover, individual models can be used for investigating the behavior of the single reservoirs, as well as for special tasks like well performance analysis and sensitivities studies.
Gas Well Decline Analysis Under Constant-Pressure Conditions, Wellbore Storage, Damage, and Non-Darcy Flow Effects
Authors: Nashawi Ibrahim Sami , Qasem Fuad H. , Gharbi Ridha , Mir Mohammad I.
Published: December 2007

This paper presents a simple and accurate method to determine all the reservoir parameters for transient constant-pressure drawdown data of gas wells influenced by wellbore storage, formation damage, and high-velocity flow effects. The working equations are written in such a way that allows a graphical analysis of the measured variable rate with time that is very much similar to the analysis of constant-rate production case. No iterative procedure, multi-rate test, nor non-linear regression is necessitated to determine the formation damage and the non-Darcy flow effects. The well test data analysis requires two plots to directly obtain all the parameters of interest. The formation permeability and the non-Darcy flow coefficient are obtained from the first plot, whereas the skin factor is obtained from the second analysis plot.

This work systematically illustrates the applicability of the derived equations using several simulated examples. The final working equations are written in various forms, which allows the well test analyst to select the form that is most convenient for his application. The advantages of the proposed method are clearly shown when the analysis procedure and results are compared to other analysis techniques.
Innovative Critical Sour Gas Extended Production Test Through Surface Coiled Tubing
Authors: Campbell S. F. , Pettigrew S. M. , Gordey K. N.
Published: December 2007

This paper will describe the deliverability test of a critical sour natural gas well using Coiled Tubing as a surface pipeline. Conventional production deliverability tests are constrained by regulatory limitations on emissions and flaring, affecting test duration and reservoir evaluation. Conventional tests also carry a significant environmental impact and the lost revenue from flared gas hamper the economic justification of the test. This paper will describe the concept, background analysis and the field trial production test performed. A safety-focused procedure was developed using surface Coiled Tubing for in-line testing of high rate critical sour gas wells. This prototyped method allows for a proper evaluation of a well without the commitment and installation of a permanent pipeline, without the volume restraint imposed by regulatory limitations, with no harm to the environment and without compromising economic value. It is projected that this method for well production deliverability tests will become an attractive alternative for the Alberta oil and gas industry.
Well Performance Prediction of a Well Experiencing Changes in Completion
Authors: Marhaendrajana T. , Desroches J.
Published: December 2007

This paper presents a new semi-analytical method to predict the production performance of a well stimulated by acid or hydraulic fracture treatment. The new method considers the production history before stimulation, in contrast to current analytical methods that ignore the production history of the "old" well. The initial condition of the "new" well is based upon an "assumed stabilized condition" of the old well.

The superposition technique has been extensively used in the literature to model production history (i.e., variable flow rate and variable bottomhole pressure history) and predict well performance. There has not been a detailed study using analytical or semi-analytical solutions that includes the change in well completion (well model change) and that investigates the influence of the production history of the unstimulated well on the well performance prediction of the "stimulated" well. This paper addresses both issues.

The semi-analytical method presented here considers changes in well completion, which are becoming more frequent as recompletions become more common. We present validations of this approach using a numerical reservoir simulator for oil and gas reservoirs in which the wells are recompleted with a hydraulic fracture treatment after some initial production.
Hydrate Inhibition in Gas Wells Treated with Two Low Dosage Hydrate Inhibitors
Authors: Lovell Dean , Pakulski Marek
Published: December 2007

Two low dosage gas hydrate inhibitors, antiagglomerant type and a combination antiagglomerant/kinetic polymeric inhibitor have been successfully field tested in a gas producing well. The well located in Canadian foothills posed challenges for the operators. High pressure, low bottomhole temperature and Joule-Thomson gas decompression cooling effect created favorable conditions for gas hydrates at depths below 300 meters. The well would plug-up with hydrates daily in spite of being treated with 400-500 L of methanol. The operator experienced significant monetary losses due to lost production and had to use considerable amounts of chemicals and time to clean-up hydrates from plugged tubings.

The inhibitors were applied downhole in 20% to 10% methanol solution. This novel approach allowed utilization of existing solvent storage and pumping equipment so that no capital spending was required when converting the hydrate prevention program from methanol to LDHI treatment.

The combination inhibitor was diluted to 20% in methanol in a stock tank and pumped into the well at the approximate rate 30 L/day. Similarly, the antiagglomerant was initially used at 20% solution in methanol and later its concentration was lowered to 10%. The daily inhibitor treatment rate was established at 45 L.

Laboratory results indicate the combination product is a better hydrate inhibitor than the antiagglomerant. However, the cost analysis favors the usage of less expensive antiagglomerant in this application.

Following the successful treatment of one well, several more similar gas wells throughout the field were identified and converted from methanol hydrate prevention method to antiagglomerant treatment.
The Kapok Field - A Step Change for Trinidad Gas Developments
Authors: Lumsden P. J. , Balgobin C. J. , Bodnar D. , Brayshaw A. C. , Dyer B. L. , Gainski M. , Hennington E. R. , Burch T. K. , Farmer C. L. , Saldana M. A.
Published: December 2007

The Kapok Field is located some 37 miles southeast of the island of Trinidad, and consists of three separate offshore gas discoveries: namely Sparrow, Renegade and Parang (Fig. 1). Following discovery, four appraisal wells were drilled into the structures in the late 90s to test areas where seismic images were masked by shallow gas. The wells confirmed the presence of gas condensate and minor oil in a total of 18 sands. The development of the Kapok field presents some unique challenges for Trinidad with comparatively shallow multiple stacked pay, aerially extensive reservoirs, relatively thin columns underlain by large aquifers, and poor seismic imaging caused by shallow gas.

To address these challenges a multidisciplinary reservoir description and stochastic modelling study was conducted to improve understanding of water behaviour - the key reservoir risk - and to plan optimum locations for the field development wells. The integrated workflow for the project incorporated seismic mapping, 3D structural modelling, the use of detailed core descriptions and field analogues, as well as both full field and single sand reservoir simulation.

The development of Kapok will be implemented in two phases: Phase I will develop the reserves associated with Sparrow and Renegade, Phase II will target Parang. Phase I calls for 16 high angle/horizontal, openhole gravel packed wells and the installation of a new 20 slot normally unmanned, remotely operated platform. The wells, some capable of delivering 200+ Mmcfd, will initially deliver 1 bcfd for processing on the new Cassia ‘B’ Central Processing Unit (CPU), prior to delivery into the 48in Bombax pipeline and transportation to the Trinidad mainland. The Cassia ‘B’ CPU will have the capability of processing 1.6 bcfd of gas, 50 Mstbd of crude/condensate and 25 Mstbd of water from the existing Cassia, Immortelle and Flamboyant fields, as well as from Kapok and any future developments in the area. The CPU will be one of the largest offshore processing units in the world. With the Kapok platform and the Cassia Hub, BP is working to promote overall safety and environmental standards within Trinidad, with re-injection of produced water and drill cuttings disposal forming part of the enhanced environmental measures.
Advanced Large-Scale Coalbed Methane Modelling Using a Conventional Reservoir Simulator
Authors: Tan Thomas
Published: December 2007

A conventional reservoir simulator was modified to model coalbed methane reservoirs using the approach presented by Siedle where an immobile oil phase is used to represent the bulk coal and the gas volume adsorped on the coal's surfaces is computed as solution gas-oil ratio. The simulator was validated against published results from coalbed methane models. The speed of the model was tested for a large problem with 120,000 cells. A dual grid system to model gas desorption, flow through low permeability matrix to high permeability fracture cleats in the coal seam was shown to more accurately reproduce initial delay in gas production while dewatering. Enhanced recovery using N2 and CO2 injection was simulated using single grid and dual grid systems. Expected incremental recovery of methane was obtained using the single grid system. However no additional recovery was obtained using the dual grid system due to extensive bypassing of the injected gas in the fracture grid system. This indicates additional physical mechanisms are at work.
Hydrocarbons Injection to Improve Recovery from Gas Condensate Reservoirs: A Simulation Approach
Authors: Harouaka A. S. , Al-Hashim H. S.
Published: December 2007

Hydrocarbons injection has been reported, in the open literature, to improve both gas and condensate recovery from gas condensate reservoirs. The injection process is considered once a liquid ring builds up around the well bore thereby reducing drastically gas delivery. Actual reservoir and fluids data from a deep gas condensate well, completed in five distinct layers, were used as input to a compositional reservoir simulator to assess the following:

1) Evaluation of various (four) injection fluids; 2) impact of shut in and injection as well as shut in alone; 3) Impact of minimum flowing bottom hole pressure constraints; 4) evaluation of a single layer model equivalent to the original multi layer well; 5) impact of shut in and injection on the equivalent single layer model; 6) impact of shut in alone on the equivalent single layer model and 7) evaluation of a binary system (77% C1 and 23% nC4) at a relatively low pressure and temperature.

From the four tested injection fluids the C4-C5 mixture gave the best results for productivity restoration. The injected C4-C5 mixture, at the high dew point considered in this work, creates, through miscibility, a single liquid phase around the well bore.

At the trailing edge of the liquid-phase around the well bore the capillary number increases sharply indicating a sharp drop in IFT. Hence the gas coming in towards the well bore is just like the liquids fully miscible with the liquid phase around the well bore.

Simulation runs done on a binary system, at a low dew point pressure indicate the miscible process will also work but the single phase around the well bore will be a vapor phase.
Increasing Well Productivity in the Wilcox Lobo Trend
Authors: Schubarth S. K. , Bazan L. W. , Becnel J. L. , Wagner A. L. , Manrique J. E.
Published: December 2007

The Wilcox Lobo Trend of south Texas contains vast quantities of natural gas in low permeability formations. Economic production from low permeability gas sands is possible through the use of hydraulic fracturing. Through the years, varying hydraulic fracturing techniques have been used to recover the gas from this trend. The success of fracturing techniques varies and depends on many factors. Several authors have demonstrated the importance of propped fracture conductivity in the production enhancement process. Without sufficient conductivity in the proppant pack, fracture fluid cleanup and adequate hydrocarbon production are difficult to achieve. The work presented in this paper will show the evaluation of these different completion techniques and products used in the Wilcox Lobo Trend by the authors. The work demonstrates the importance of fracture conductivity, supports previous work in other producing regions and presents some additional methods for achieving increased conductivity. The techniques, products and evaluation methods used in this paper can be used to benefit other operators in the Wilcox Lobo Trend as well as those working in other low permeability gas formations.
Field Study on the Use of Cement Pulsation to Control Gas Migration
Authors: Dusterhoft Dale , Wilson Greg , Newman Ken
Published: December 2007

Gas flow into cement is a serious problem that results in surface vent leaks and poor zonal isolation in many wells throughout Western Canada. This paper discusses the field testing and application of a new technique called cement pulsation to control this problem. Cement pulsation involves applying short, frequent 700 kPa pulses to the annulus following cement placement. These pulses reduce the gel strength of the slurry, which allows full hydrostatic pressure to be transmitted downhole across the gas zone, thus preventing gas from entering the annulus. This paper also discusses background theory, examines research on the depth to which pulses travel in the annulus, and presents a field study in which pulsation was used to control gas migration in Western Canada.
Numerical Studies of Gas Production from Methane Hydrates
Authors: Moridis G. J.
Published: December 2007

EOSHYDR2 is a new module for the TOUGH2 general-purpose simulator for multi-component, multiphase fluid and heat flow in the subsurface. By solving the coupled equations of mass and heat balance, EOSHYDR2 can model the non-isothermal gas release, phase behavior and flow of fluids and heat under conditions typical of common natural hydrate deposits (i.e., in the permafrost and in deep ocean sediments) in complex formations, and 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 and dissociated methane, a second native and dissociated hydrocarbon, salt, water-soluble inhibitors and heat). The mass components are partitioned among the phases, and their thermophysical properties 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 exploring different mechanisms and strategies for production from typical CH4-hydrate accumulations. The results of the tests tend to indicate that CH4 production from CH4-hydrate is technically feasible and has significant potential. 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.
Wildcat Hills Gas Gathering System Case Studies: An Integrated Approach From Reservoir Development Through to Sales Pipeline Delivery
Authors: Marsh Jack , Kenny Joseph
Published: December 2007

This paper presents a study of the development of the Wildcat Hills Viking gas reservoirs from the drilling of the exploration well to the complete development of the facility infrastructure, using a total systems approach. The Viking gas reservoir was initially identified in 1958 but remained undeveloped while a deeper Mississippian gas reservoir has produced for over 40 years. The shallower Viking reservoir had been by passed due to its low matrix permeability as well as the low initial reservoir pressure. These two observations made development of the Viking gas unfeasible at that time. Following up on data obtained from the deeper Mississippian gas wells, and using modern seismic interpretation and geological concepts, a trend of viable gas wells was discovered in the Viking sand. The challenges of determining the actual reserve potential, developing an efficient gas gathering and processing infrastructure leading to optimum and economical management of the Wildcat Hills project are outlined in this paper.
Roles of the Fracture System and State of Stress for Gas Production from the Basement Reservoir in Hokkaido, Japan
Authors: Kazuhiko Tezuka , Namikawa Takatoshi , Tamagawa Tetsuya , Day-Lewis Amy , Barton Colleen
Published: December 2007

Fractures in the Yufutsu reservoir may be divided into two sets based on apparent aperture measured in electrical image data. Large-scale fractures having centimeter-order apparent apertures (termed "mega"-fractures) are considered to contribute to gas production by acting as conduits, while relatively small-scale fractures contribute to gas storage and migration. The interaction between fractures and the state of stress may also control productivity. Analysis of wellbore failure revealed a NE-SW orientation of the maximum horizontal compressive stress (SHmax), with a small variation from the west (SHmax oriented N30E) to the southeast and north (SHmax oriented N60E). Modeling indicates that the general stress state is strike-slip (Shmin < Sv < SHmax). Coulomb failure analysis of natural fractures in the current strike-slip stress state reveals that steeply dipping fractures striking to the northeast-southwest are critically stressed and therefore most likely to be permeable. Wells in which this is the dominant fracture set are therefore most likely to be productive. The predictions agree closely with observed production in the wells. The results from this study are sufficient to provide guidance for future drilling and completion decisions for the Yufutsu Field.
Applied Reservoir Characterization for Maximizing Reserve Growth and Profitability in Tight Gas Sands: A Paradigm Shift in Development Strategies for Low-Permeability Gas Reservoirs
Authors: McKinney P. D. , Rushing J. A. , Sanders L. A.
Published: December 2007

This paper proposes an alternative tight gas sand reservoir development strategy that allows operators to maximize gas recovery and net present value while minimizing capital expenditures. Our approach employs a "parallel" development technique where many reservoir performance evaluation and field development activities are performed almost concurrently, thus allowing an operator to identify the optimum well spacing early in the field's life. Successful application of this "parallel" development approach requires a coordinated reservoir description and characterization plan, reservoir modeling, and reservoir monitoring and surveillance. We also illustrate the economic advantages of our strategy with examples from a hypothetical tight gas sand reservoir.
Hydraulic Fracturing: The Forgotten Key to Natural Gas Supply
Authors: Duda J. R. , Boyer C. M. , Delozier D. , Merriam G. R. , Frantz J. H. , Zuber M. D.
Published: December 2007

By most accounts, natural gas demand in the United States (U.S.) is expected to significantly increase during the next two decades, from 23 trillion ft3 in 2000 to over 33 Tcf in 2020. The Energy Information Administration projects that 22,000 gas wells will have to be drilled in 2020 to meet this demand - up substantially from the 15,200 wells successfully drilled and completed in 2000. Further, a significant portion of the U.S. future supply of natural gas is expected to be produced from these unconventional sources - formations that typically require hydraulic fracturing to produce at economical rates. Given this forecasted scenario, a critical and comprehensive assessment of the role that hydraulic fracturing plays in supplying natural gas in the U.S. has been initiated.
Permeability, Pore Pressure, and Leakoff-Type Distributions in Rocky Mountain Basins
Authors: Craig David P. , Eberhard Mike J. , Odegard Chad E. , Ramurthy Muthukumarappan , Mullen Rebekah
Published: December 2007

The permeability, pore pressure, and leakoff-type interpreted from more than 1,200 diagnostic fracture-injection/falloff tests were collected in a database and statistically evaluated for four Rocky Mountain basins. The statistical analysis includes the range of observed permeability and pore pressure and the fracture leakoff-type distribution.

Specially designed "mini-frac" or diagnostic fracture-injection/falloff tests were routinely implemented throughout Rocky Mountain basins beginning in late 1998 for the sole purpose of estimating reservoir-engineering parameters. Using three recently developed analysis methodologies, more than 1,200 tests have been analyzed to determine permeability, pore pressure, and leakoff type.

The analysis reveals that pressure-dependent leakoff, fracture-tip extension during shut-in, and fracture height-recession during shut-in are the most common leakoff types. Overall, pressure-dependent leakoff, which can be indicative of highly productive fractured reservoirs, is the most common leakoff type in all Rocky Mountain basins. The analysis also shows order-of-magnitude variation in gas permeability within all basins with observed gas permeability ranging from less than 0.001 md to greater than 0.10 md.
Evaluation of a Statistical Infill Candidate Selection Technique
Authors: Guan L. , McVay D. A. , Jensen J. L. , Voneiff G. W.
Published: December 2007

Quantifying the drilling or recompletion potential in producing gas basins is often a challenging problem, due to large variability in rock quality, well spacing, and well completion practices, and the large number of wells involved. Complete integrated reservoir studies to determine infill potential are often too time-consuming and costly for many producing gas basins. In this work we evaluate the accuracy of a statistical moving window technique that has been used in tight gas formations to assess infill and recompletion potential. The primary advantages of the technique are its speed and its reliance upon well location and production data only.

The statistical method was used to analyze simulated low-permeability production data sets; moving window infill well predictions were then compared to those from reservoir simulation. Results indicate that moving window infill predictions for individual wells can be off by more than 50%; however, the technique accurately predicts the combined infill production estimate from a group of infill candidates, often to within 10%. The accuracy of predicted infill performance decreases as heterogeneity increases and increases with the number of wells in the project. Cases evaluated in this study included realistic well spacings and production rates and a significant amount of depletion at the infill locations. Due to its speed, accuracy and reliance upon readily available data, the moving window technique can be a useful screening tool for large infill development projects.
Case Study: Including the Effects of Stagnant Water in Gas Gathering System Modeling
Authors: Young James , McNeil Ralph , Knibbs Jeffrey
Published: December 2007

This case study outlines and details the steps taken in constructing a gas gathering system model of the Pendor field in south-eastern Alberta.

The challenge was to identify and model the effects of stagnant water in the pipelines and wellbores, and then quantify the deliverability potential resulting from the removal of said liquids.

Also included are the methods used to calibrate the gathering lines, calibrate the well deliverability at sandface and wellhead, history match to verify reserve data, and the importance of first hand verification of pressure anomalies and their causes.
Productivity of Horizontal Wells Completed with Screens
Authors: Yildiz Turhan
Published: December 2007

An integrated flow model is developed to simulate the flow into horizontal wells with screens. The model is composed of a multi-segment horizontal well model and a near-wellbore model. The multi-segment horizontal well model predicts the pressure losses in a bounded reservoir. The near-wellbore model simulates the fluid flow through the damaged/collapsed zone around the wellbore, mud-cake, wellbore/screen interface, gravel-packed annulus and screen itself.

Using the model, we investigated the effects of degree of screen damage, non-uniform damage removal, mud cake properties, and blank pipe insertion on horizontal well productivity. We examined and compared the long-term horizontal well performance in terms of rate decline and cumulative production as a function of time.