bluuebunny/crossref_metadata_2025 huggingface dataset:
Organosilicon Drilling Fluid System for HT Deep Gas Wells
Authors: Sun Yuxue , Zhang Yanfen , Zhao Jingyuan
Published: March 2009

Taking temperature as a dividing criterion, the investigations and applications of organosilicon drilling fluid system (ODFS) on the fifth largest gas field in China, Qingshen gas field, have experienced three phases from 180 °C, 200°C to current 220 °C. In the first two phases, ODFS has been successfully used for drilling 48 deep wells.

In the third phase, the high temperature (HT) deep gas well in Qingshen gas field, Xushen22, was drilled to 5320 m (17454 ft) with bottom hole temperature of 220 °C (428 °F). Since high temperature can cause clay dispersion and deactivation, as well as the degradation and crosslink of organic compound, the severe high temperature drilling environment posed a host of technical challenges and environmental issues. The difficulty of drilling operations was further increased by the extremely hard and brittle formation, because such formation potentially increases the risk of hole instability. Therefore, for drilling the HT deep gas well Xushen22, a new type of organosilicon drilling fluid system with improved thermal stability and hole stability was required. Based on the mechanism study on different HT additives, we formulated a high-performance ODFS-III whose properties were examined through a full-scale laboratory tests. Finally, we applied the ODFS-III on well Xushen22.

The results obtained from the field application show that ODFS-III has good thermal stability and special rheology, and also provides good shale stabilization, which meet the hydraulics and hole-cleaning demands of deep-well operations.
Development, Testing, and Field Application of a Heavy Oil Pipeline Cleaning Chemical: A Cradle to Grave Case History
Authors: Wylde Jonathan J. , Slayer Jubal J.L.
Published: March 2009

This paper details the complete evolution of a new cleaning chemical for heavy oil and gas pipelines. Information is offered regarding the reason for development, the research involved in formulation of the new product, as well as the laboratory testing. This paper concludes by giving several case histories of application in cleaning operations in Western United States and Texas.

Oil naturally contains paraffins, asphaltenes and naphthenates. During transport these hydrocarbon components can precipitate and adhere to the pipeline walls and can become associated with iron sulfide scale. Corrosion can often occur on pipeline walls under these organic deposits. Pigging operations are normally performed to remove organic and inorganic debris from the walls of a pipeline. However, these scales can become very compacted and adhere to the walls of the pipeline. It is often necessary to add surfactant based chemicals to assist in the break-up, softening, and transportation of these deposits.

A detailed literature review of the current theory in the chemistry of pipeline cleaning chemicals is presented together with a critical account of the key properties required of these chemistries: wettability alternation, solubilization efficacy of organic materials, emulsification of phases, dispersion, detergency, and defoaming.

An explanation of the laboratory development and evaluation has been given as a preamble for the case histories. One case history details how a pipeline operator unsuccessfully tried to clean a 12″ 9-mile section of pipeline with a pig. The pig was launched and became stuck along the length of the pipeline. Application of the newly developed product was able to free the stuck pig and removed significant debris. By way of conclusion the paper offers suggestions on how chemicals can be most efficiently used in conjunction with these programs.
Estimation of Geothermal Reserves in Oil and Gas Reservoirs
Authors: Zhang Lingyu , Liu Mingsheng , Li Kewen
Published: March 2009

The existing volumetric approach was honored by considering the effects of oil and gas saturations on the evaluation of geothermal resources in oil and gas reservoirs. The main reason to do so was that oil and gas phases may not be simply substituted by water because the values of the specific heat of oil and gas are smaller than that of water. We selected an oil reservoir, Hexaw, from Huabei oil field as an example to apply the method. The effects of oil and gas saturation on the geothermal reserve were investigated at different values of porosity and the results were compared to the existing approaches. It was found that the existing volumetric method tends to overestimate the geothermal reserves in oil and gas reservoirs. The greater the oil or gas saturation is, the more the overestimation of the geothermal reserve is. The results showed that it is necessary to consider the effects of oil and gas saturations on the estimation of geothermal reserve in oil and gas reservoirs.
The Future of California's Oil Supply
Authors: Croft Gregory D. , Patzek Tad W.
Published: March 2009

Once an oil exporter, California now depends on imports for more than 60% of its oil supply. This paper examines the oil production outlook for each of California's major oil sources, including California itself. Oil production trends, published geological and engineering reports, and proposed developments in California's supply area are reviewed to define supply trends, especially for the medium-to-heavy, sour crudes that are processed in California's refineries. Refinery upgrading capacity is already highly developed in California, thus it is assumed that a competitive advantage in heavy, sour crudes will continue, although refining heavy oil releases more carbon dioxide.

About a quarter of California's imports are from Alaska, the rest from foreign sources including Saudi Arabia, Ecuador and Iraq. Before foreign sources became so important, California's refining industry processed California's own crudes and Alaska's North Slope crude. Like those crudes, oil from northern Saudi Arabia, southeast Iraq, and Ecuador is also sour and medium to heavy, ranging from 16 to 35° API and from 2 to more than 3% sulfur by weight. By far the most important sour crude development in California's supply area is Saudi Arabia's 900,000 BOPD Manifa project, originally slated for completion in 2011 but now facing delays. Manifa contains oil that ranges from 26 to 31° API and from 2.8 to 3.7% sulfur. Over the longer term, Alaska will continue to play an important supply role if the Chuckchi and Beaufort Seas live up to expectations.

Middle East production is not increasing, yet oil cargoes from the Middle East have to pass growing Asian markets to reach California. Alaska and Mexico also supply oil to the Pacific Basin, but are facing production declines. The effect of rising Asian demand on Pacific Basin oil markets is already visible, with significant amounts of oil coming to California from Atlantic Basin sources such as Angola, Brazil, and Argentina.

The US West Coast pipeline system is separate from the integrated East Coast, Gulf Coast and Midwest system, so energy security issues for the West Coast may differ from those of the country as a whole. There are policy options that could affect California's oil supply security, including increased oil development in Alaska or offshore California, development of additional oil pipeline outlets on Canada's Pacific Coast or substituting natural gas for oil if possible. All of these policy options are currently the subject of political debate.
Data Processing and Interpretation of Well Test Data as a Nonparametric Regression Problem
Authors: Nomura Masahiko , Horne Roland N.
Published: March 2009

Reservoir pressure has always been the most useful type of data to obtain reservoir parameters, monitor reservoir conditions, and forecast future reservoir performances. This work investigates a nonparametric method to analyze well test and production data. We address both data processing and parameter estimation problems from a data smoothing aspect. The procedure enables us to develop an insight into the specific issues: (1) model recognition, (2) flow rate estimation, and (3) transient identification. We demonstrate the procedures on synthetic and actual field examples.
Dimensionless Characterization of Transient Pressure Volume Behaviour for Foamy Oils
Authors: Huerta M. , Andarcia L. , Jossy E.
Published: March 2009

Foamy oils are generated during the depressurization of heavy oils that contain dissolved gases. Foamy oil behaviour seems to play an important role in cold production, so the understanding of transient pressure-volume expansion behaviour of foamy oils is very important. Results of various mercury withdrawal experiments obtained at different flow rates and oil viscosities in a sand pack filled with heavy oil saturated with methane are analyzed in this work using a dimensionless characterization approach. A series of experiments with a varying fluid flow rate and a range of fluid viscosities were used. Different scaling groups based on capillary number and two different mathematical expressions that involve the initial pressure depletion rate were constructed. The initial depletion rate to the point of maximum supersaturation was used, as well as properties such as diffusion coefficient, interfacial tension, and viscosity. In the dimensionless analysis shown in this work, only the first stages of bubble nucleation and growth exhibited in the range of Sg = 0% to Sg = 8% were used. The pressure at the maximum supersaturation fits well with all dimensionless numbers tried in this work. Typically, when the experimental results were re-plotted using the dimensionless variables, the data lie mainly on a straight line. Only the experimental tests with the highest fluid rate and highest viscosity did not follow this trend. The best correlation was obtained with the dimensionless number that involved a diffusion coefficient. These preliminary results suggest that there exists a strong relationship between the foamy oil behaviour observed during gas exsolution experiments and capillary forces/diffusive mass transfer phenomena in the presence of high depletion rates. Lower diffusive mass transfer of the dissolved gas together with high interfacial tension could result in the formation of smaller gas bubbles sustained for a longer time. The discovery of the mathematical relationship shown in this work between foamy oil behaviour and a dimensionless number involving capillary forces/diffusive mass transfer, may provide the basis to forecast the range of variables at which foamy oil behaviour might be observed.
Prudhoe Bay: Rebuilding a Giant Oil and Gas Full Field Model
Authors: Ding Eric , Harrison Peter , Dozzo Joe , Lin C. Y.
Published: March 2009

The Prudhoe Bay field is the largest accumulation of oil and gas in North America. Because of the size, and the fact that it produces from multiple mechanisms including lean gas cycling, gravity drainage, pattern waterfloods, pattern MI / WAG injection and gas cap water injection for pressure maintenance, a full-field model (FFM) with a rigorous surface pipeline network and facilities model is necessary to answer many depletion planning questions and to evaluate the benefits of large-scale or field-wide projects. With additional reservoir description data and production history, the opportunity existed to use current software and hardware to build an improved model. In 2005 an effort began to build a new FFM, including both geocellular and simulation models. This paper discusses the issues addressed at the start of the rebuild in preparation for the history match, the history matching effort, and the transition to predictive runs.

Preparation for the history match included setting the objectives for the model, the grid design, generating pseudo relative permeability curves, and implementing parallel processing. The key parameters and data used to obtain a history match are discussed, as are the issues and methodology utilized in constructing predictive cases. Some of the key interactions with the parallel geologic model construction are also discussed.

It was demonstrated that a compositional model with approximately 1 million active cells and over 650,000 non-neighbor connections associated with over 1000 structural faults could be run and history matched in a commercial parallel reservoir simulator in a reasonable time.

With approximately 25 BSTB of oil, 46 TSCF of gas in place, and over 2500 historical wells, the challenge of building a full-field model for a field the size of Prudhoe Bay was daunting. A project of this magnitude required excellent up-front preparation and cross-discipline coordination.
Pressure-Activated Sealant Economically Repairs Casing Leaks on Prudhoe Bay Wells
Authors: Chivvis R. W. , Julian J. Y. , Cary D. N.
Published: March 2009

Pressure activated sealant was used to repair casing leaks in two Prudhoe Bay, Alaska oil wells without the use of a rig workover. The significance of the treatments, development of job screening criteria, and job planning and execution are reviewed.

Production casing leaks are a frequent problem in mature oil fields, particularly where there is corrosion. Wells with casing leaks usually do not meet well operating criteria so they must be shut-in, causing a loss in valuable production. Casing leaks normally require a rig workover to repair since the tubing often has to be removed. Rig workovers are very expensive in offshore locations, remote areas, and harsh climates. Special pressure activated sealants, diagnostic tools, and treatment techniques have been developed to find and repair casing leaks without removing the tubing.

Case studies of three Prudhoe Bay production wells describe how pressure activated sealant successfully repaired the small casing leaks in two wells without removing the tubing. The third well was not treated because it did not meet the screening criteria. One case study was unusual because the sealant fixed four deep casing leaks with one treatment.

The case studies show how refinements in diagnostic techniques, candidate screening, and treatment planning and execution have resulted in the successful application of pressure activated sealant to repairing casing leaks in producing wells and in one case repaired four leaks with one treatment. Using pressure activated sealant to repair casing leaks can result in significant cost savings and return wells to production sooner. The treatment can be particularly useful in mature fields with corrosion problems and in offshore, remote, and arctic fields where rig workovers are expensive and rig availability is limited.
Isoconversional Kinetic Analysis of the Combustion of Heavy Hydrocarbons
Authors: Cinar M. , Castanier L. M. , Kovscek A. R.
Published: March 2009

One method to access unconventional, heavy-oil resources is to apply in-situ combustion (ISC) to oxidize in place a small fraction of the hydrocarbon thereby providing heat to reduce oil viscosity and pressure that enhances recovery. ISC is also attractive because it provides the opportunity to upgrade oil in-situ by increasing the API gravity and decreasing, for instance, sulfur content. Experimental analysis of crude-oil oxidation kinetics provides parameters, such as activation energy, for modeling and optimization of ISC processes. The complex nature of petroleum as a mixture and multistep character of oxidation reactions complicates substantially the kinetic analysis of crude oil. Isoconversional techniques provide model-free methods for estimating activation energy and naturally deconvolve multi-step reactions. In this sense, they are superior to the conventional methods of analysis of crude oil oxidation kinetics. Isoconversional methods are also useful as a diagnostic tool to recognize the burning characteristics of different oils. Our work shows that different phenomena, such as "cool flames", can be identified by using isoconversional analysis. The combustion kinetics of three oil samples are reported adding to the knowledge base of crude-oil combustion and the applicability of isoconversional analysis to oil oxidation is tested experimentally. In addition synthetic examples are presented to show the diagnostic characteristics of the analysis.
Coiled Tubing and a Fluidic Oscillator Used as an Aid for Selective Placement Technique to Wells in Huila, Colombia
Authors: Pinto Sandra Gonzalez , Callarotti Gian Franco , Tellez Oscar
Published: March 2009

One of the major challenges of stimulating wells in the San Francisco and Balcon fields in Colombia is adequate fluid placement. The wells in these areas have different zones open to production. Typically, these zones show severe petrophysical contrasts regarding permeability, porosity, and oil-and-water saturations. Permeability can be 25 times greater in one zone than another. Furthermore, these open zones may also have different pressures. These variations in rock and fluid properties increase the probabilities for preferential flow to the zones of less resistance. Therefore, selective stimulation techniques are commonly used to treat wells in these two fields. Single and straddle packers for bull-heading and coiled tubing with conventional nozzles are some of the commonly used techniques.

This paper discusses the results from using CT and a fluidic oscillator as a new alternative to place stimulation fluids. A true fluidic oscillator generates pressure waves using the Coanda effect. These low amplitude, high-frequency pressure waves enhance damage removal and fluid placement through cyclic loading. This technique has been extensively used in the San Francisco and Balcon fields for Hocol in Colombia. Three stimulations using CT and a fluidic oscillator are discussed in this paper as well as the results from this fluid placement technique with conventional placements showing how the use of CT and a fluidic oscillator can increase hydrocarbon recovery.
Expandable Tubulars Facilitate Improved Well Stimulation and Well Production
Authors: Durst Doug G. , Ruzic Neven
Published: March 2009

Growing energy demand is leading the industry to re-evaluate resources found in challenging conditions such as unconventional gas formations, re-entry wells, and/or low producing wells. Cost-effective development of these resources depends on strategic application of advancing production solution technologies. To enhance production and improve recovery processes, more efficient perforating and fracturing methods have evolved along with advancements in wellbore production hardware via use of solid expandable tubulars or combinations of solid expandable and conventional tubulars.

Expandable technology applied as a completion/production string facilitates increased fracturing rates, resulting in improved conductivity and enhanced hydrocarbon production. Expandable tubulars can be used in re-entry wells to isolate old perforations, allowing for new zones or new sections within zones to be perforated and stimulated. Either a combination tubular cladding system or a solid expandable system can provide an integral component in new wells or re-entry wells where low-permeability reservoirs, such as those characteristic of unconventional gas formations, require isolation and separation for selective or pinpoint hydraulic fracturing or re-fracturing.

Although successful stimulation is routinely attained from hydraulic fracturing, ancillary downhole tools such as conventional completion equipment often compromise results by restricting flow and affecting pressure performance. Solid expandable systems can optimize the fracturing parameters by maintaining larger diameters and providing seals for selective multi-zone or zonal isolation purposes. These production systems can consist of either solid expandable tubulars or expandable sealing sections combined with conventional tubulars using premium connections, thus providing a superior completion solution.

This paper will explain how solid expandable tubulars can be used to facilitate first-time fracturing, re-fracturing, and multi-zone fracturing, refurbishing older wells, and attaining large-diameter production/reservoir conduits. Integration and system development of this technology will be discussed. Case histories will be cited to illustrate the effectiveness of solid expandable systems in enhanced production and fracturing applications.
Synergies and Opportunities Between EGS Development and Oilfield Drilling Operations and Producers
Authors: Petty Susan , Bour Daniel Lee , Livesay Billy Joe , Baria Roy , Adair Richard
Published: March 2009

We discuss the emerging Engineered Geothermal Systems (EGS) industry, highlight its significant relationship with the oil and gas drilling industry, and describe overlapping opportunities available for the two industries. EGS refers both to the creation of geothermal reservoirs in deep hot rocks and sedimentary basins, as well as to the unconventional use of co-produced hot water from oil and gas production. It has the potential for transforming geothermal energy from a relatively minor source of baseload electricity production into a resource capable of providing 10 percent or more of domestic US energy needs within a few decades. Traditionally, geothermal has been tied to places with the relatively rare combination of plentiful hot water that is shallow. EGS reservoirs exploit the natural increase of temperature with depth nearly everywhere on Earth. The recovery of just 2 percent of the thermal energy between 3 and 10 km depth in the United States represents about 2,800 times the current domestic energy usage. A modest drilling program of 150 wells per year would provide annual increments of 1,000 to 2,000 MWe. EGS power generation is a readily available domestic source of energy that is reliable, steady, and environmentally friendly. Not only does it emit no greenhouse gases, but there is the potential for CO2 sequestration by mining the geothermal heat with CO2, rather than with water. EGS power plants would require minimal footprints, and waste hot-water from the plant can be exploited for direct-use applications such as manufacturing processes and heating buildings and greenhouses. Drilling rigs, casing, tools, and other typical oil field services have been used to drill geothermal wells. This paper will discuss the level of these services needed for EGS growth, and describe new technologies that must be developed, primarily for the creation of EGS reservoirs.
Effects of Water on Kinetics of Wet In-Situ Combustion
Authors: Lapene A. , Castanier L. M. , Debenest G. , Quintard M. , Kamp A. M. , Corre B.
Published: March 2009

Wet combustion tube runs have been performed and are compared to dry ones. In a previous study using ramp temperature oxidation (RTO), we have underlined the effects of water on heavy oil combustion through chemical interactions.

Five combustion tube experiments using heavy oil have been conducted. Two dry runs with different air fluxes and three wet combustion runs with the same air flux but various water air ratio (WAR).

We have tried to link past observations concerning differences between dry and wet combustion, such as changes in oil recovery, observed in our experiments and those which have been underlined in the study of reaction kinetics via RTO.
Polymer Gel Water-Shutoff Applications Combined With Stimulation Increase Oil Production and Life of Wells in the Monterey Formation Offshore California
Authors: Turner B. , Zahner B.
Published: March 2009

Excessive water production from the Monterey Formation of the Sockeye Field offshore Santa Barbara, California led the operator to consider polymer gel water shutoff treatments. Field water rates were approaching the limit of the platform water handling capacity and threatened to curtail future development and/or require a multi-million dollar facility expansion. By utilizing chromium crosslinked polyacrylamide gel technology, the operator significantly reduced the water production. However, after gel treatments were injected and the wells were returned to service, both water and oil production were significantly lower. The operator subsequently stimulated the wells with acid and saw significant increases in oil rates while maintaining a reduction in water production.

The result of combining the water shutoff treatments with the stimulation was a lowered water production rate and increased oil rate that neither technique would have yielded on its own. At this time, four wells have been treated with both gel and acid and one has been treated with gel alone. Of the four treated with gel and acid, three had reduced water rates and three had increased oil rates. Moreover, all gel treatments were pumped down production tubing without the need of a rig, using the vendor's self-contained trailer that included all mixing and pumping equipment. While not specifically designed for offshore use, this equipment greatly simplified logistics and the total cost was low enough that the economics could be based solely on savings in water handling costs.
Establishing Injector/Producer Connectivity Before Breakthrough During Fluid Injection
Authors: Izgec O. , Kabir C. S.
Published: March 2009

Interwell connectivity is a key issue in any field development planning, especially when secondary and tertiary recovery methods are contemplated. Stakes are particularly high in deepwater and other costly environments where the well count largely dictates project economics. Traditional approaches to discerning reservoir compartments include fluid PVT properties, geochemical fingerprints, tracer testing, and transient-pressure testing. While fluids may provide clues about reservoir connectivity or lack thereof, they cannot tell us about the degree of connectivity between wells. In contrast, pulse testing may provide the necessary information, but the interwell permeability so estimated is skewed toward the observation well, and therefore may not be entirely satisfactory. This study presents an alternative method for establishing interwell connectivity involving production and injection wells.

We show that capacitance-resistive modeling (CRM) is a viable alternative to solving transient-flow problems. Equivalence of streamline simulations and CRM is established for fractional flow directed at each producer. We also showed that one can discern connectivity between the injector and producers in an inverted-five-spot pattern and in channelized reservoirs, with limited injection in prebreakthrough scenarios. In closed systems, even low-signal quality may suffice for characterization, provided reasonable injection perturbation exists. Excessive voidage appears to be a nonissue as far as signal propagation is concerned.
Using PLT Data To Estimate the Size of Natural Fractures
Authors: Hoffman B. Todd , Narr Wayne , Li Liyong
Published: March 2009

In naturally fractured reservoirs, determining fracture properties, such as size and permeability, is difficult due to the limited data about the fractures. The primary information that is available, mainly from image logs or core, is known only at the wellbore; however, the fractures can be local to the wellbore region, or they can extend hundreds of feet from the well. If fractures can be characterized more accurately, then flow paths and flow behaviors in the reservoir can be better delineated. Thus, rates and declines in primary production and breakthrough times of injected fluids can be better estimated, and the field can be developed more efficiently. The goal of our work has been to combine dynamic data with static data to better characterize fracture properties, especially the size of fractures away from the wellbore.

PLT information can be used in conjunction with static data to more accurately define fracture properties such as size and permeability. A single-well single-phase flow-simulation model is constructed with discrete fractures at each location where wellbore inflow is observed with a PLT. A program has been created to automatically perturb the lengths and heights of model fractures until their flow response matches the actual measured response (i.e. history matching PLT data by changing fracture properties). This program is designed for wells that intersect multiple fractures.

The tool has been used on a number of different examples, and matches are achieved in all cases. Fracture lengths range from a few feet to thousands of feet. The optimization is efficient as it generally finds solutions after iterating through only about 20 flow simulations. To demonstrate the various capabilities of the program, different options are used in different cases. One example is matched with six different models to provide a range of uncertainty for the fracture sizes.
Improvements in Capacitance-Resistive Modeling and Optimization of Large Scale Reservoirs
Authors: Weber Daniel , Edgar Thomas F. , Lake Larry W. , Lasdon Leon , Kawas Sami , Sayarpour Morteza
Published: March 2009

Oil production strategies traditionally attempt to combine and balance complex geophysical, petrophysical, thermodynamic and economic factors to determine an optimal method to recover hydrocarbons from a given reservoir. Reservoir simulators have traditionally been too large and run times too long to allow for rigorous solution in conjunction with an optimization algorithm. It has also proven very difficult to marry an optimizer with the large set of nonlinear partial differential equations required for accurate reservoir simulation.

A simple capacitance-resistive model that characterizes the connectivity between injection and production wells can determine an injection scheme that maximizes the value of the reservoir asset. Model parameters are identified using linear and nonlinear regression. The model is then used together with a nonlinear optimization algorithm to compute a set of future injection rates which maximize discounted net profit. Research previously conducted has shown that this simple dynamic model provides an excellent match to historic data. Based on a number of simulated and two actual fields, the optimal injection schemes based on the capacitance-resistive model yield a predicted increase in hydrocarbon recovery of up to 60% over the extrapolated historic decline.

An advantage of using a simple model is its ability to describe large scale systems in a straightforward way with computation times that are short to moderate. However, applying the capacitance-resistive model to large reservoirs with many wells presents several new challenges. Reservoirs with hundreds of wells have longer production histories that often represent a variety of different reservoir conditions. New wells are created, wells are shut in for varying periods of time and production wells are converted to injection wells. Additionally, history matching large reservoirs by nonlinear regression is more likely to produce parameters that are statistically insignificant, resulting in a parameter dense model that does not accurately reflect the physical properties of the reservoir. Several modeling techniques and heuristics are presented that provide a simple, accurate reservoir model that can be used to optimize the value of the reservoir over future time periods.
Field Applications of a Semianalytical Model of Multilateral Wells in Multilayer Reservoirs
Authors: Pan Yan , Kamal Medhat M. , Kikani Jitendra
Published: March 2009

Advanced drilling technology has been widely and successfully applied to construct multilateral wells in reservoirs. This paper presents several field applications of the modeling of complex well architectures. A generalized semi-analytical segmented model, accounting for multilateral well systems in commingled layered reservoirs was used in several field applications. Cases include evaluating the flow efficiency of different configurations of wells with multiple laterals, analyzing an interference test between three horizontal wells in Al Rayyan oil field offshore Qatar, and analyzing a well test in a commingled multilateral well in a multilayer reservoir in the Dos Cuadras field offshore California.

The model can predict the production performance under either constant-rate or constant-pressure conditions of a well system with any number of arbitrarily oriented laterals of any length and nonuniform formation damage. The reservoir layers, with different porosities, anisotropic permeabilities and drainage areas, are non-communicating except through the wellbore. The solution is valid for large reservoirs and when no-flow or constant-pressure boundaries affect the pressure behavior.

Results of applying this method in the field cases showed that the model enabled us to predict multilateral well performance, to obtain information about reservoir connectivity, and to estimate well and reservoir properties in a multilayer system. Uncertainty, due to the large number of unknown parameters in such a complex system, represents the main challenge in using this method. It is recommended to use other means (e.g. production logging and PNC log) together with pressure transient data to reduce the uncertainty. Whenever possible, each lateral should be tested individually to provide more reliable estimates of reservoir and well properties.

The presented model and the lessons learned from the field applications provide engineers a tool to use transient data collected from multilateral wells in multilayer systems for reservoir characterization and performance forecast.
Operational Energy Savings through the use of Continuous Sucker Rods with Progressing-Cavity Pumps
Authors: Hopkins Nicholas L.
Published: March 2009

This work analyzes the difference in energy requirements between using continuous sucker rods and using conventional jointed sucker rods in Oilwell Progressing-Cavity Pumping (PCP) systems, with an emphasis on how each rod type is affected by well depth and fluid content. PCP is a rotational pumping application; these pumps transfer fluids through internal cavities by rotating a rotor inside of a stator. Calculations for this study are performed with a computer spreadsheet to illustrate potential energy savings achieved with continuous rod applications. This work expands on previous research addressing continuous sucker rods by observing how changing viscosity (with increasing well depth) can affect pump operation. The focus is on production in the San Joaquin Valley, which typically has high water-to-oil ratios; the properties of brine water and 14° API crude oil are used in the calculations.

Oilfield operators planning to install PCP systems can use data acquired from this work to estimate the influence of several factors on pump operational energy costs. Results can be iterated from this study to estimate different operating situations depending on the particular well conditions. This study is also an attempt to understand anecdotal evidence found in existing wells with PCP and continuous sucker rods already installed

Using a continuous rod results in operational energy savings over conventional rod strings, the magnitude of which depends on well depth and fluid content. The author concluded that the increased energy savings were a result of omitting couplings and guides from the rod string. Couplings and guides decrease the annulus area for the working fluid to flow through, which increases pump pressure requirements. Greater savings are observed in deeper wells because the rod string is longer, which requires more couplings and guides on a conventional rod string.

Predicting the operational energy cost savings attained by using a continuous rod can help determine whether the capital cost of installing continuous rods will be recouped in a profitable timeframe. Calculated energy savings may also be used towards applying for energy saving incentives through California utilities customer energy efficiency programs, which can help offset the investment in energy-efficient building and design and ultimately lead to a higher return on investment.
Modeling Two-Phase Fluid and Heat Flows in Geothermal Wells
Authors: Hasan A. Rashid , Kabir C. Shah
Published: March 2009

This study presents a robust model for two-phase flow in geothermal wells using the drift-flux approach. For estimating the static head, we use a single expression for liquid holdup, with flow-pattern-dependent values for flow parameter and rise velocity that gradually changes near the transition boundaries to avoid discontinuity in the estimated gradients. Frictional and kinetic heads are estimated with the simple homogeneous modeling approach.

As the geothermal fluids ascend up the well, loss of both momentum and heat occur. The consequent pressure loss often leads to flashing and increase in steam fraction (quality) despite heat loss. Accurate estimation of heat loss, which leads to significant changes in fluid properties influencing pressure-drop is, therefore, important in modeling flow in geothermal wells. Heat transfer from the wellbore fluid to the surrounding formation is rigorously modeled by treating the wellbore as a heat sink of finite radius in an infinite-acting medium (formation) and accounting for the resistances to heat transfer offered by various elements of the wellbore.

We present a comparative study involving the new model and those that are often used for geothermal wells. These models include those of Ansari et al., Orkiszewski, Hagedorn and Brown, Beggs and Brill, and the homogeneous model. The main ingredient of this study entails the use of a small but reliable dataset. Statistical analyses suggest that all the models behave similarly, although the proposed model offers marginally greater accuracy and simplicity of use. Uncertainty of performance appears to depend upon the quality of data input, rather than the model characteristics.
Spontaneous Countercurrent Imbibition and Forced Displacement Characteristics of Low-Permeability, Siliceous Shale Rocks
Authors: Takahashi Satoru , Kovscek Anthony R.
Published: March 2009

Enhanced oil production from naturally-fractured low-permeability reservoirs is challenging. A large amount of oil is generally left behind because of heterogeneity and unfavorable rock wettability. Spontaneous countercurrent imbibition in naturally-fractured reservoirs is an important oil recovery mechanism and has been widely studied in the oil and gas industry. Nevertheless, complicated rock properties such as low permeability and other factors controlling flow mechanisms make it difficult to understand the flow characteristics and to generalize expected recovery.

Spontaneous countercurrent imbibition and forced displacement tests at reservoir temperature were completed using siliceous shale core plugs that have low permeability, relatively high porosity, and intermediate to oil-wet surfaces. Four brine formulations were examined: carbonated synthetic brine (pH of 3), acidic (pH of 3), neutral, and alkaline (pH of 12).

During spontaneous countercurrent imbibition, the oil recovery was about 10% of the oil in place (OIP) or less when the low to the neutral pH synthetic brine was used. On the other hand, with the high pH synthetic brine, the oil recovery increased to 30% of the OIP. In forced displacement after spontaneous imbibition, the final oil recovery was 65%, 70-80%, and 95% of the OIP in the neutral pH, low pH and carbonated water, and high pH brine, respectively.

The siliceous shale core used in this study is an intermediate to oil-wet rock as gauged from the oil recovery by spontaneous imbibition in the neutral pH brine. With pH-controlled synthetic brine, the final oil recovery increases; especially using high pH brine. This suggests that the wettability shifts to greater water-wet conditions and the residual oil saturation decreased by exposing high pH brine. In the simulation study, it is inferred that the oil recovery characteristics change by changing the capillary pressure characteristics and the interfacial tension.
Solutions for Better Production in Tight Gas Reservoirs Through Hydraulic Fracturing
Authors: Arukhe James , Aguilera Roberto , Harding Thomas G.
Published: March 2009

The challenge to make best producers for the least investment in tight gas reservoirs has always been with the oil and gas industry since production in many tight gas reservoirs is oftentimes marginal, at best. This paper presents solutions for better production in tight gas reservoirs through hydraulic fracturing.

Properly engineered hydraulic fracture treatments are enablers to achieve overall economies of scale with development of tight gas reservoirs. These treatments are conducted to bypass completion damage and stimulate production from low permeability reservoirs. They are designed using simulators with a range of capabilities in an effort to maximize the economic benefit of the treatment, effective fracture length, and number of zones producing, fracture conductivity, acceleration of recovery, addition of reserves, and minimize job failures and treatment costs. To accomplish these goals, substantial amount of information is required to describe reservoir flow capacity and provide the data needed to predict treatment pressure response as well as fracture geometry and conductivity. These data will determine the optimum size of the treatment, the maximum proppant concentration that can be pumped, and the expected production response to the stimulation. When sufficient input data are available to characterize the reservoir, the fracture geometry can be accurately modeled with a capable simulator, the treatment goals listed above can be realized and an optimum design can be reached.

The design process, including selection of proppants and fluids, pumping schedule, injected proppant concentrations, total job size, pump rate, and other parameters requires an idea of the desired outcome of the job: required fracture length, possible pack concentration and clean-up time. Critical measurements from testing of actual cores has allowed to sift through the chaff to find those "gems" in hydraulic fracturing that materially improve the completion efficiency in tight gas reservoirs.
Numerical Reservoir-Wellbore-Pipeline Simulation Model of The Geysers Geothermal Field, California, USA
Authors: Butler Steven J. , Enedy Steven L.
Published: March 2009

The Geysers geothermal field, located in Lake, Sonoma, and Mendocino Counties, California is the largest developed geothermal system in the world. Electric power generation started at The Geysers in 1960 with a 12 MW (gross) plant. The total installed capacity in the field peaked in 1989 at 2,043 MW. As more and more power plants were built during the 1980s and net mass withdrawals increased, reservoir pressures at The Geysers declined, eventually resulting in steam shortfalls and declining generation levels. This net withdraw is due to the fact that geothermal power plants at The Geysers typically lose about 70 to 80% of produced mass to evaporation in cooling towers, with the balance of mass being returned to the reservoir through injection of steam condensate.

In response to this decline, field operators made modifications to the pipelines and turbines to be able to operate more efficiently at lower system pressures. Based on studies funded by the California Energy Commission that showed that injection of water from outside sources was the most effective method of managing the long-term decline in the resource, a program of augmented injection, using large volumes of treated sewage effluent, was started in the late 1990s.

This program of augmented injection has brought mass injected, more or less, into parity with mass produced, and the rate of reservoir pressure decline has been significantly reduced. Still, optimizing the distribution of augmented injection throughout the field and making corresponding adjustments to plant and pipeline facilities is a complicated process, with many interdependencies.

To aid in ongoing optimization of the field, an integrated model has been developed for the Northern California Power Agency (NCPA) that combines reservoir simulation with mathematical modeling of the wellbores, the pipelines, and the power plants. This integrated model, funded in part by the California Energy Commission, has proven very useful for evaluating the most cost-effective improvements to the combination of wells and surface facilities, and to study the benefit of increasing the volume of augmented injection.
A New Method for Continual Forecasting of Interwell Connectivity in Waterfloods Using an Extended Kalman Filter
Authors: Zhai Daoyuan , Mendel Jerry M. , Liu Feilong
Published: March 2009

This paper is based on a relatively simple parametric model that characterizes the system function between a specific producer and each of its contributing injectors. The model has only two parameters for each producer-injector pair; so, if N injectors are assumed to contribute to a producer, there will be 2N unknown parameters. An adaptive strategy, using an Extended Kalman Filter (EKF), is used to estimate the 2N parameters, which are then used to generate N numeric Injector-Producer-Relationship (IPR) values for the N producer-injector pairs. The IPR values allow one to assess how well an injector influences the producer.

This same model and an EKF were first used in Liu, et al [5]. The modified EKF used in this paper avoids problems that can arise when processing real data and provides additional information that is useful for future research. Our modified EKF is applied to real data from a section of an oil field. A validation strategy for the estimated IPR values is developed in terms of "prediction errors." A strategy is also presented for choosing an optimal set of injectors that affect a producer. Finally, a simple method is presented for converting producer-centric IPR values to injector-centric IPR values so that reservoir engineers can easily see which producers are being affected by a specific injector.
A Mutual Information-Based Metric for Identification of Nonlinear Injector Producer Relationships in Waterfloods
Authors: Khodaei A. , Lee Hyokyeong , Banaei-Kashani F. , Shahabi C. , Ershaghi I.
Published: March 2009

In this paper we introduce a new analytical approach for management of waterfloods in heterogeneous reservoirs. The main contribution is the development of a process and metric to evaluate the pair-wise injector-producer (IP) relationships, i.e., to quantify the impact of any injection well on the neighboring producing wells. The proposed metric is particularly designed to consider the non-linearity of the IP relationship between the injection and production rates by using the Mutual Information (MI) data mining tool. Non-linearity of the IP relationship is the main challenge in quantifying this relationship and, to the best of our knowledge, this is the first time that MI is used in the petroleum literature for IP relationship identification. In addition to MI that captures the non-linear correlation in the IP relationship, our metric considers other parameters such as the distance between the IP pair as well as their relative injection and production rates, respectively. Leveraging our proposed metric, we propose a system, for optimal waterflooding with which a field engineer can automatically: Identify the under-performing producers based on their performance characteristics such as wateroil ratio, gas oil ratio, and oil production rate;Rank all injectors based on their impact on the under-performing producers using our proposed IP relationship identification metric;Decide on optimal injection volumes for individual injectors that have the most impact on the under-performing producers and maximize the recovery factor.

The proposed technique can significantly reduce the decision-making time for the effective management of complex waterflood.