bluuebunny/crossref_metadata_2025 huggingface dataset:
Statistically Designed Oil Dehydration Tests
Authors: Bowman R.W. , Burton W.D. , Pryor J.A.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Shell has used statistically designed bottle tests for a number of years to optimize crude oil dehydration systems. A brief review of important parimeters in crude oil dehydration is reviewed plus the statistical design method and the method of data evaluation is discussed.

Introduction

Oil production in the U.S. usually produces normal emulsions (water-in-oil) with some reverse emulsions (oil-in-water) found associate with thermal and chemical floods. In the strict thermodynamic sense, the coalescence of droplets in a stable system is accompanied by an increase in Gibbs free energy. Coalescence of a stable system will not occur spontaneously as only a decrease in free energy will occur naturally. Conversely, an unstable emulsion would separate spontaneously if given sufficient time. However this time might be weeks, so in a practical sense it will be considered as being stable. Since coalescence causes a decrease in the interfacial area and a small increase in interfacial tension which decreases the free energy, emulsions are probably never truly stable in the thermodynamic sense but east as a pseudoequilibrium. pseudoequilibrium. Droplet size of emulsions is very important in oil-water separators as stated in Stokes Law. They are also important in differentiating between an emulsion and a dispersion. Usually emulsion droplets are in the .5 to 50 micron range with an average in the 20 micron range. An arbitrary division would be to class everything above the 100–150 micron range as dispersions.

Emulsions have an emulsifying agent or surface-active agent absorbed at the oil-water interface usually oriented so a monomolecular film is formed. It is these agents which interfere in dehydration. These agents are usually indigenous to the crude oil system. The emulsifying agents include asphaltenes, resins, organic acids, heavy paraffins, various metallic salts, silts, clays, scale and bacteria wastes. Whether a normal or reverse emulsion is formed depends upon whether the agent is more water compatible (hydrophilic) or oil compatible (lipophilic or hydrophobic). According to Bancroft's rule' of thumb, the continuous phase is the one in which the emulsifier is the most soluble.
Isotope Geochemistry In Geothermal Reservoir Studies.
Authors: Truesdell A.H. , Frye G.A.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Isotope geochemistry has contributed greatly to our scientific knowledge of geothermal systems. The near identity of deuterium isotopes of thermal waters and local rain waters has shown that geothermal systems are recharged by rainwaters which circulate deeply for periods indicated by tritium analyses of more than 60 years. Isotope geothermometers utilizing the distribution of 18 between water and dissolved SO4, of 13C between CO2 and CH4, and of 34S between H2S and SO4 have indicated from surface samples temperatures at depth above the range of chemical geothermometers. Isotope studies have indicated that the source of dissolved carbon, sulfur, lead, and strontium in certain systems is rock leaching rather than magmatic contributions. Other components such as 3HE ultimately originate in the mantle, but their immediate source may also be rock leaching.

The role of isotope geochemistry in geothermal reservoir studies is still being developed but shows great promise. Oxygen-18 and tritium studies at Larderello have demonstrated that lateral recharge with young water occurs in parts of the system. Similar recharge in The Geysers has not been demonstrated. Carbon isotopes in CO2 and CH4 suggest that hotter reservoirs exist at Wairakei and Larderello with temperatures above 350 deg. C. Changes in oxygen-18, deuterium, and gas contents with flow rate of Geysers steam have shown that in unexploited parts of the field, steam and liquid water coexist near wellbottoms and most steam is produced by evaporation of liquid when pressures are reduced in exploitation. There are indications of lateral movement of steam with condensation and reevaporation from the center of the field towards the margins, Radon contents also show marked changes with flow rate but interpretation to yield reservoir properties has not been achieved. properties has not been achieved

Introduction

Geochemistry of H, O, C, and S isotopes in the H2O, SO4—, HCO3—, CO2, CH4, H2 and H S of geothermal fluids has broad applications in geothermal reservoir studies. Unlike dissolved salts and gases, oxygen and hydrogen isotopes of water are direct tracers of the water itself and may indicate its origins, movements and subsurface conditions. Isotopic tracers are especially valuable in vapor-dominated systems where salts remain in the reservoir and only steam and gases reach the surface.
Computer-Aided Analysis of Tracer Dispersion in Composite Cores: Tests of Two- and- Three Phase Flow Experiments
Authors: Alvarado V. , Manrique E. , Ponce R. , López P.
Published: December 2007

Tracers are commonly used for monitoring fluid transport in oil and water reservoirs. This paper provides results on tracer dispersion experiments in the so-called composite cores. They were performed under steady-state flow of formation water at Sw = 100% and Sor, and also under conditions of multiphase flow in a water-alternating-gas process (WAG). The composite core was assembled with 6 plugs from the same sandstone formation, having similar geological characteristics. KCl was used as a passive tracer, for which the chlorine concentration was determined by means of electrical conductivity measurements and tritation of the produced water. From the concentration values at different times, breakthrough curves were obtained and analyzed. Porosity and absolute permeability were measured before packing, and a relative permeability curve for the composite core was obtained. This information was used to history match the production curves in multiphase flow experiments. For the tracer result, a commercial simulator and a 2-D stochastic simulator, developed for this purpose, were used to predict the breakthrough curves. For the latter, an estimate of the dispersivity was obtained by fitting the curve with an analytical solution of the 1-D convection-dispersion equation. Multiphase flow results are in good agreement with the mass balance. For WAG experiments, it can be shown that there is intermediate value of the water-to-oil ratio in the feed that results in an optimum in terms of recovery and economics. The analysis shows that the breakthrough curve can be predicted reasonably well for the condition of Sw = 100%. Numerical dispersion turns out to be a difficulty when running the commercial simulator that is naturally overcome in the case of the stochastic simulator. There seem to be effects of saturation on dispersivity as the predictions show.
Study and Application of Weak Gel System Prepared by Complex Polymer Used for Depth Profile Modification
Authors: Wang HongGuan , Guo WanKui , Jiang HongFu
Published: December 2007

This paper provides a weak gel system (WG) prepared by a complex polymer, an organic crosslinker and an additional agent for depth profile modification, which is different from colloidal dispersion gel (CDG) and bulk gel (BG). The gel system can be injected into depth reservoir (injection radius over 60 meters) to generate the plugging in high permeable interval, then the late injected water or polymer can be forced to convert into low permeable zone for increasing swept volume, oil displacement efficiency and oil production. From 1996 to 1999 in China, 45 wells in five polymer-flooding blocks and two water-flooding tracts had been treated by using the gel system in No.1 product, No.3 product and No.9 product of Daqing Oilfield Company. 2000~6300m3 treatment fluid had been injected per well. Average 2.2~103t/day incremental oil production and 13~43.8% decreasing overall water cut were obtained. The successful rate reached 91% and input/output ratio was 1:8. Through the evaluation of the numeral simulation method, the final recovery efficiency can be increased from 1% to 3% by using the technology recommended by this paper.

Decision-system of selecting well, job design and numerical simulation method are introduced here.
Chemical Control Techniques for the Paraffin and Asphaltene Deposition
Authors: Dong Lijian , Xie Huizhuan , Zhang Fusheng
Published: December 2007

Paraffin related problem appears through out the production process of nearly all kinds of crude oils all over the world. It also appears in the dewatering process and the long distance crude oil transportation. In Daqin Oil Field in northeastern China, 150 million RMB is spent on the cleaning up the paraffin deposition (including the total expense on cleaning up the paraffin deposition on various surfaces of production equipments by the mechanical, thermal, chemical etc. methods).

Just as the same, asphaltene deposition problem is also encountered in the oil production process. This paper focus on the discussion of paraffin deposition and its chemical control technique.

The paper introduce the latest research and development of chemical additives (DQ, KOW, AOA, ZHJ) for the control of paraffin and asphaltene and their successful application on 2000 wells in Chinese oil fields. In the oil field application, chemicals were added into the oil tube or annular space, or squeezed into the oil formation so that the deposition of paraffin and asphaltene was inhibited. Oil wells treated with DQ, KOW, AOA, ZHJ were all kept on long time normal production, the times of repairing equipment and shutting up oil wells were greatly reduced. Also the productivity was enhanced and the production cost was decreased. Annual economic benefit by using of this chemicals was about 21, million RMB.

The design of paraffin inhibitors in the paper was based on the theory of co-crystallization, the theory of surface chemistry and colloidal dispersion chemistry. DQ, KOW, AOA were thus designed and have satisfactory properties. The paper also discuss the mechanism of paraffin deposition inhibition.
Study and Application of the Viscosity Reducer Used in Production of the Viscous Crude Oil
Authors: Xie Huizhuan , Zhang Fusheng , Dong Lijian
Published: December 2007

According to the property of the viscous crude oil in China, ORV (oil-base viscosity reducer) and HEA (water-base viscosity reducer) have been developed. ORV oil-base viscosity reducer which is composed of high molecular weight polymer, surfactants and other additives etc., has a good viscosity-reducing effect for the viscous crude oil with low or medium viscosity, at the dosage of 100 to 300mg/kg, viscosity was reduced by 60% to 80%, in the same time, has a good pour point-reducing effect for high pour point crude. HEA water-base viscosity reducer which is composed of surfactants, stabilizer and other additives etc., has a very good viscosity-reducing effect for the viscous crude oil with high viscosity, at dosage of 50~200mg/kg, viscosity was reduced by above 99%. Above-mentioned two reducers have already used in Jidong, Liaohe and Shengli etc. oilfields, a better application effect and a tremendous economic benefit (according to the incomplete statistical data, that of ORV is 13.5 million yuans RMB per year, and ratio of input to output is 1:11; that of is 20 million yuans RMB per year, and ratio of input to output is 1:26.2) were abtained. And moreover, HEA viscosity reducer has a good high temperature-tolerant ability and can be used as the spearhead chemical agent for steam soak, ORV viscosity reducer has pour point-reducing and wax-inhibiting functions.
Effect of IOR/EOR Chemicals on Interfacial Rheological Properties of Crude Oil/Water Systems
Authors: Lakatos I. , Lakatos-Szabó J.
Published: December 2007

Interfacial rheological properties of different Hungarian crude oil/water systems were determined in wide temperature and shear rate range and in the presence of inorganic electrolytes, water-soluble polymers, non-ionic tensides and alkaline materials. The detailed laboratory study definitely proved that the interfacial rheological properties are extremely sensitive parameters towards the chemical composition of immiscible formation liquids. Therefore, comparison and interpretation of the interfacial rheological properties may contribute significantly to extension of the weaponry of the reservoir characterization, better understanding of displacement mechanism, development of more profitable EOR/IOR methods, intensification of surface technologies, optimization of pipe line transportation and improvement of refinery operations. It was evidenced that the interfacial rheology is an efficient and powerful detection and differentiation technique, which may enhance our knowledge on formation, structure, properties and behavior of interfacial layers. Thus, it will probably accelerate significantly the progress not only in oil recovery but also in all areas of colloid science and technology.
Effect of Brine Composition and Alkaline Fluid on the Permeability Damage of Limestone Reservoirs
Authors: Bagci Suat , Kok Mustafa V. , Turksoy Ulas
Published: December 2007

Secondary and tertiary recovery processes can lead to severe and permenant reductions in permeability because of interactions between injected fluids and the reservoir rock. Permeability damage was suspected as a factor contributing to post completion production declines observed during waterflooding of an unconsolidated limestone.

This study summarizes the laboratory studies undertaken to evaluate and understand permeability damage in limestone reservoirs. The influence of brine composition, salinity of alkaline fluid and injection rate on permeability damage were evaluated in consolidated and unconsolidated cores. Effluent pH and Cl concentrations were measured at the outlet of the porous medium. Brines were prepared with sodium, calcium and potassium salts (NaCl, CaCl2, KCl). High pH values in produced water caused the permeability reduction and consequently the pores were plugged and formation damage was observed.

In alkaline flooding experiments, permeability reduction was observed as a result of high pH alkaline fluids (NaOH, NaSiO4). The permeability reduction was decreased using NaCl, CaCl2 and KCl mixtures and high oil recoveries were obtained. Suspended solid particles were released and moved with injection water as a result of Cl concentration below the critical salt concentration caused the permeability reduction and the formation damage was occurred.
Compositional Dependence of Reservoir Wettability
Authors: Muhammad Z. , Rao D. N.
Published: December 2007

The purpose of this work is to carry out a systematic study of the effects of crude oil, brine and rock compositions on formation wettability. Degree of wetting depends on the dynamic contact angle measured in a mode that enables movements of the three-phase contact line.

Knowledge of formation wettability is important in primary, secondary, and enhanced oil recovery operations. By varying compositions of crude oil and brine, and using crystal surfaces of different mineralogy and roughness, we can get a better understanding of the rock-fluid interactions in reservoirs.

The Wilhelmy Plate technique is being used in this study to measure adhesion tension (which is the product of interfacial tension and cosine of the contact angle) at the solid-liquid interface; a microbalance is connected to a computer which detects the change in force as the solid surface travels through oil and brine interfaces in advancing and receding modes. The water-advancing and water-receding contact angles can then be calculated from the adhesion tensions by making independent measurements of the fluid-fluid interfacial tensions.

The method is used to study pure hydrocarbons and synthetic brines of different concentrations and the wetting behavior is used to study Yates field crude oil, brine and rock interactions. Polished surfaces of glass slides and dolomite are used to simulate the reservoir rock surface. An ethoxy alcohol surfactant, which is being used in the field for enhancing oil recovery, was used to quantify its wettability effects.

The results of the systematic experimental investigation of the effects of practical variables on wettability are presented. It is found that interactions between surface active agents at the interface of two fluids have an effect on wettability alteration. The composition and concentrations of different organic and inorganic chemical species have a major effect in making a reservoir oil-wet or water-wet.
Cost Saving Benefits of Using a fully Bi-directional Tractor System
Authors: Henderson Bruce , Hopwood Chris , Hamilton Cameron , Garies Jim
Published: December 2007

A new wireline tractor system has been developed that is the first to be fully bi-directional in both speed and pulling force. It was used on a number of high angle wells in Alberta and Saskatchewan and delivered both cost saving and risk saving benefits to the operator.
Comparison of Chemical Steam Floods through Vertical and Horizontal Wells
Authors: Shedid Shedid A. , Abbas Al-Abbas A.
Published: December 2007

Laboratory investigations and field applications have proved steam drive to be an effective enhanced oil recovery method for reservoirs of moderate and heavy oil viscosity. This experimental study was undertaken to investigate, combine and compare the performance and productivity of water, steam, alkaline steam, surfactant steam, and surfactant alkaline steam floods through vertical and horizontal wells. To achieve the objectives of the study, two experimental models (vertical and horizontal) are designed and built. Identical porous media, reservoir fluids (crude oil and formation water), steam, chemicals, and injection/production conditions are used and/or applied.

The results of the study showed that horizontal wells are better candidates for waterflooding than vertical ones, when the same pore volume of water are injected in the reservoir. Steam and chemical steam (alkaline steam, surfactant steam, and surfactant alkaline steam) floods recovered more oil when applied through horizontal wells than through vertical ones. In addition, chemical steam floods recover more oil than conventional steam drive for both applications of vertical and horizontal wells. The increment of oil recovery due to application of horizontal wells instead of vertical ones may be 10.27 % IOIP for steam flood and almost 17.7 % IOIP for surfactant alkaline steam flood.

The displacement efficiency of oil recovery through horizontal wells is higher than that through vertical wells for steam flood by almost 25 %, for alkaline steam flood by almost 33 %, for surfactant steam flood by almost 37 %, and for surfactant alkaline steam flood by almost 48 %. The proposed techniques of chemical steam floods have important implications for improving oil recovery from current water flood and steam projects, since they combine the advantages of both chemical and thermal recovery methods.
Understanding Chemical-Potential-Related Transient Pore-Pressure Response To Improve Real-Time Borehole (In)Stability Predictions
Authors: Tare Uday A. , Mody Fersheed K. , Mese Ali I.
Published: December 2007

Chemical potential related borehole (in)stabilities in the field are predominantly time-dependent. With the intention of developing a real-time wellbore (in)stability modeling capability, experimental work has been undertaken to investigate the role of chemical potential of drilling fluids on transient pore pressure and time-dependent rock property alterations of shale formations. The current work presents the concept and discusses the results of these undertakings.

The experiments using a Pore Pressure Transmission Test (PPT) apparatus expose formation (shale) cores under simulated downhole conditions to various salt solutions and drilling fluids. The uniqueness of this study comes from the fact that time-dependent alterations in the pore pressure, acoustic, static properties and strength of formations subjected to compressive tri-axial stress are recorded during the PPT experiments. This eliminates the anisotropy-associated differences obtained when different samples are used to determine the relationship between these characteristic parameters of shale formations. This comprehensive testing program will enhance our understanding of the relationship between acoustical, mechanical and chemical properties of shale as a function of time when exposed to a drilling fluid.

The main objective of this effort is to translate the results of the PPT tests to actual drilling conditions. Wherein the formation-drilling fluid chemical potential model would be validated and updated in real-time to predict borehole (in)stabilities.
Christina Lake Thermal Project
Authors: Suggett Jack , Gittins Simon , Youn Sung
Published: December 2007

This paper provides a description of PanCanadian’s Christina Lake Thermal Project. PanCanadian is implementing a commercial steam assisted gravity drainage (SAGD) project to recover 7.5 to 9.0 API bitumen from the Athabasca oil sands in the McMurray Formation. The project is located in Northeast Alberta, approximately 130 km north of Lac La Biche and 170 km south of Fort McMurray, in township 76 range 6 W4M.

The project will be built in three phases for total bitumen production of 70,000 barrels of bitumen per day. Phase 1 will produce 10,000 bpd, with Phases 2 and 3 producing 30,000 bpd each. This paper will outline PanCanadian’s reasons for taking a phased approach to the Christina Lake development.

Dual well SAGD will be implemented with 500 to 750 m long horizontal well pairs. Phase 1 is expected to begin steaming operations in the fourth quarter of 2001. The timing of subsequent phases will depend on Phase 1 results, market conditions and project economics. In March, 2000 PanCanadian received Alberta Energy and Utility Board approval for the project.
Thermal-Deformation-Resistant Slotted-Liner Design for Horizontal Wells
Authors: Slack M. W. , Roggensack W. D. , Wilson G. , Lemieux R. O.
Published: December 2007

Liners for wells produced using the SAGD process (steam assisted gravity drainage) must balance sand control requirements and inflow characteristics against the structural demands of thermally induced loads. These challenging design issues require a switch from conventional load-based casing design principals to a deformation-controlled design basis. This paper first develops this design basis, describing the problem in terms of the controlling variables, then applies the results to the liner design for a specific reservoir in a reliability based context. The developed design implements innovative and recently commercially available deformation control devices to manage competing thermal and geo-mechanical loads in the intermediate casing and horizontal liner. For the candidate well, a purpose-specific slotting configuration was also defined to control inflow distribution and reduce risk of undesirable slot deformations under thermal loads. (SPE Paper 65517 describes the inflow design basis.) The resulting liner design maintains structural integrity and provides slot geometry protection to ensure effective sand control supporting the extended production life obtained through managed slot distribution.
Optimization Methodology for Cyclic Steam Injection with Horizontal Wells
Authors: Escobar E. , Valkó P. , Lee W. J. , Rodríguez M. G.
Published: December 2007

Horizontal wells are becoming a very important component in the thermal recovery of heavy oil reservoirs. The success of a cyclic steam injection project depends strongly on the selection of key parameters, such as cycle length and amount of steam injected. The numerical simulation of horizontal wells, especially under non-isothermal conditions, is computationally demanding. When optimization is combined with numerical simulation, the computing time requirement may be prohibitive and it is not guaranteed that the optimal conditions will be found.

In this research, a new methodology has been developed for optimizing the cyclic steam injection process for vertical and horizontal wells. The procedure integrates oil production characterization using numerical simulation, net present value maximization through a Quasi-Newton method, and model validation/tuning. The three-stage procedure provides the optimum number and/or duration of cycles, the optimal amounts of steam to be injected in each cycle and the optimal value of the overall economic indicator.

The optimization algorithm was successfully validated with published results obtained from the discrete maximum principle. The methodology was then applied to determine the optimal conditions of cyclic steam injection for a horizontal well located in Bachaquero field, Venezuela.
The Effect of Chain Length of Oil and Alcohol As Well as Surfactant to Alcohol Ratio on the Solubilization, Phase Behavior and Interfacial Tension of Oil/Brine/Surfactant/Alcohol Systems
Authors: Hsieh W.C. , Shah D.O.
Published: December 2007

The Effect of Chain Length of Oil and Alcohol As Well as Surfactant to Alcohol Ratio on the Solubilization, Phase Behavior and Interfacial Tension of Oil/Brine/Surfactant/Alcohol Phase Behavior and Interfacial Tension of Oil/Brine/Surfactant/Alcohol Systems

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Economical microemulsion flooding process can be achieved by optimizing the surfactant formulation for an oil reservoir. This optimization involves the tailoring of a surfactant formulation to fit the conditions for a reservoir, namely, the temperature, the salinity and composition of formation water, and the nature of the crude oil. The general method of optimization of surfactant formulations is to investigate the phase behavior and interfacial tension of surfactant systems containing brine, oil, surfactant and cosurfactant.

Solubilization of oil and brine by microemulsion phase containing petroleum sulfonate TRS 10–410 and alcohol was determined at room temperature. Interfacial tension between phases was correlated with solubilization phases was correlated with solubilization behavior of surfactant formulations. The effect of the chain length of hydrocarbon oil on the solubilization and interfacial tension behavior of surfactant formulations was investigated at a surfactant concentration of 5 wt.% and isobutanol concentration of 3 wt.%. Effect of chain length and isomeric structure of alcohols on the solubilization and interfacial tension behavior of dodecane vs. surfactant solution containing 5 wt.% TRS 10–410 and 3 wt.% alcohol was investigated and correlated with the solubility of alcohol in brine. Effect of alcohol and surfactant concentrations on the formation and volume of the middle phase was determined. Surfactant to alcohol ratio was changed in the formulation in order to determine the molecular ratio of surfactant to alcohol in the middle phase. The surfactant to alcohol ratio in the middle phase micro-emulsion was determined using high resolution NMR spectroscopy. Interfacial tension was measured as a function of surfactant concentration to find the interfacial tension concentration minima. The minimum interfacial tensions at low and high surfactant concentrations were correlated by changing salinity and hydrocarbon oil chain length in the surfactant formulation.

Introduction

Microemulsion flooding process has been widely tested in laboratory and has been applied in field tests in recent years for tertiary oil recovery. In this process, a microemulsion containing petroleum sulfonate, alcohol, oil and brine was used as an injection fluid. The interfacial tension between the microemulsion and reservoir oil or brine is as low as 10 dynes/cm or less. Under adequate conditions, the microemulsion slug is miscible with both oil and brine.
Enhanced-Oil-Recovery Injection Waters
Authors: Collins A. Gene
Published: December 2007

Publication Rights Reserved, U.S. Government Publication Rights Reserved, U.S. Government This paper was prepared for the 1977 SPE-AIME International Symposium on Oilfield and Geothermal Chemistry, held in La Jolla, California, June 27–28, 1977. Permission to copy is restricted to an abstract of not more than 300 words, Illustrations may not be copied. The abstract should contain conspicuous acknowledgement of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal, provided agreement to give proper credit is made. Discussion of this paper provided agreement to give proper credit is made. Discussion of this paper is invited.

A survey was made of the types of waters, chemicals, and water-treatment methods used in enhanced-oil-recovery operations. The study indicated that numerous types of waters, chemicals, and water-treatment methods are used. Chemical and biochemical reactions can occur when different types of waters are mixed, or when enhanced-oil-recovery chemicals are added. Stringent quality control is needed in all operational phases related to injection waters in order to produce optimum amounts of oil and to prevent irreparable damage to equipment, wells, and oil reservoirs. Standard methods are needed to assure adequate quality control.

Introduction

In this report, enhanced oil recovery is defined as the additional production of oil resulting from the introduction of artificial energy into the reservoir. Primary oil recovery is defined as the oil and gas produced by natural reservoir energy or forces. Therefore, by this definition enhanced recovery includes waterflooding, gas injection, and other operations involving fluid or gas injection whether for secondary or tertiary oil recovery. Tertiary recovery is any enhanced-recovery operation applied after secondary recovery. The ERDA research program on enhanced oil recovery does not include waterflooding.

Enhanced recovery is applied to an oil-containing subsurface reservoir for the purpose of dislodging oil from the reservoir rock pores and moving it to a production well. Many subsurface petroleum reservoirs contain sufficient energy because of internal pressures to push oil and gas to the surface when first penetrated by a drill bit. However, as the penetrated by a drill bit. However, as the internal pressures become low because of the removal or production of oil, gas, and water at the wellhead, the residual oil in the reservoir cannot be recovered without the application of external or artificial force.

Secondary recovery is any enhanced-recovery operation first applied to a reservoir. Often it follows primary recovery, but it can be conducted simultaneously with primary recovery. The most common secondary-recovery process is waterflooding.
Experience in Scale Control With East Mesa Geothermal Brine
Authors: Lindemuth T.E. , Houle E.H. , Suemoto S.H. , Van Der Mast V.C.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

The East Mesa Geothermal Test Site, near Holtville, California, established by the Bureau of Reclamation, has been involved with studies of resource development and geothermal desalination since 1972. At present, there are five geothermal wells on the East Mesa Anomaly, operated by the government, as well as five others, developed by private interests.

The major program at the site has been investigation of the feasibility of producing pure water from geothermal brines, using producing pure water from geothermal brines, using desalination techniques. Pilot plants installed and operated included two distillation units and a high temperature electro-dialysis unit.

Throughout the last 4 years of investigation, a variety of scaling problems have been encountered. Plugging and fouling of downhole well piping, surface piping, and process units primarily with calcium process units primarily with calcium carbonate, barium sulfate, and silica have been noted.

This paper discusses the conditions under which these observations have been made, including brine chemistry, brine temperature, well flow, and other process conditions. Success has been noted in the use of several scale inhibitor additives, especially in the control of calcium carbonate and barium sulfate scale.

The scale inhibition techniques described in this paper should have applicability in operation of geothermal systems for both power and water production, as well as in the reinjection of waste brine.

Introduction

Since 1972, the U. S. Bureau of Reclamation has been operating a geothermal test facility on the East Mesa, near Holtville, California. The purpose of activities there has been to determine the feasibility of providing a source of augmentation flow for providing a source of augmentation flow for the Lower Colorado River by the desalination of geothermal brines. A unique aspect of this program is the fact that the geothermal brine provides both the source of water and heat to operate the process.
Using Well Windows in Full Field Reservoir Simulation
Authors: Mlacnik M. J. , Heinemann Z. E.
Published: December 2007

The windowing technique, introduced by Deimbacher and Heinemann (Ref. 3), allows a time-dependent replacement of grids for a defined area during a simulation run. A window can represent any kind of well with a gridded wellbore and an appropriate grid pattern around the well. Such an approach makes the generally used Peaceman well model superfluous. As the gridded wellbore and the grid blocks around it are small (some cu-ft) the computational stability requires small timesteps and a greater number of Newton-Raphson iterations. It is obvious that this is not feasible if the solution for the full-scale model and the well windows must be performed simultaneously. Therefore in a first step the fully implicit solution for the full-scale model will be calculated but the inner blocks of the windows are solved for the pressure only, without updating the saturations and mole fractions. This solution provides the boundary influx for the windows. In a second step the windows are calculated for the same overall time step with up to 1000 small local steps.

This paper presents the general and practical applicability of this method. Windows, constructed by the PEBI (k-PEBI) method, are introduced automatically for all of the wells (vertical, horizontal and slanted).

For testing purposes a real case field model was used. It will be shown that the quality of the results obtained for the model calculated with integrated radial grids around the wells and small overall timesteps are equal to those obtained for the same model using the windowing and local timestepping technique.

Further it will be shown that solving the window model with large timestep lengths for the first and small lengths for the second solution step results in equal or smaller CPU times and less NR iterations in comparison to the conventional model.
Emergency Shutdown Systems-Evolution And Status
Authors: Oubre Harold J. , Thurman R. , Vallee J.C.
Published: December 2007

Beginning in the early 1930's the development of downhole and surface safety equipment has followed a logical evolution, through the close cooperation between the operating companies and manufacturers. The separate developments of downhole and surface safety devices were joined with the introduction of the surface controlled sub surface safety valves in the late 1950's. For the first time, truly integrated systems could then be designed for offshore installations instead of the previously available separate safety devices. Safety systems are now in use all over the world that provide safe, reliable emergency shutdown protection against almost any predictable situation.
New Centralizers Improve Horizontal Well Cementing by 100% Over Conventional Centralizers in the Niger Delta Basin
Authors: Peckins Osazuwa , Akhideno Mathias , Faugeras Herve
Published: December 2007

Statistics of cementing highly deviated wells in the Niger Delta (50 deg or more) show that only about 33% are successful and do not require an elaborate squeeze cementing operation. Two out of every six wells drilled in the past had good primary cement bond logs less than an average of 15mv.

The remedial squeeze operations are expensive requiring such operations as perforation of casing which often times reduces the intergrity of this pressure vessels, putting the existing bond at risk and finally the drill out testing of the squeezed casinf intervals. This entire remedial operation is non-productive rig time resulting in increased well cost.

Analysis has traced this poor primary casing cementation history to a number of deficiences (1) Improperly designed cement recipes (2) Poor hole geometry (3) Bad cementing or placement techniques (4) poor casing string centralisation resulting in channelling.

The effect of each of this factor is amplified due to the fact that the Niger delta is characterised by sand /shale sequence which contributes to hole washouts or even caving resulting in hole sizes that are much larger than the bit size.

In the Niger delta, poor casing centralization contributes over 50% of the poor primary cement job. Even good cement recipes and good cementing practices are jeopardised by flow pattern resulting from poor casing centralization.

Operator experience had indicated that the use of conventional spring / rigid type centralizers for casing centralisation in the Niger Delta had not been successful in correcting this deficiency in highly deviated wells.

A new centralizing package has been introduced and successfully used in the cementing of horizontal and multilateral wells.

To authenticate the result from the use of this new package, a study was implemented in the Imo River field of the Niger Delta. The results obtained so far from the cementation of three horizontal wells and the two multilateral wells in the Niger Delta totaling seven horizontal wells, indicates that there is a 100% improvement in primary cementing and zonal isolation. CBL/VDL was logged on all wells, giving excellent results in the profile of 5millivolt with no need for expensive remedial squeeze cementing. (Fig 2).

Actual well candidate selection criteria, technical and economic performance evaluations on the application of this new centralizer package are included in this paper.
Prevention of Corrosion in a Harsh Environment Using Zinc Primer
Authors: Muntasser Z. M. , Al-Darbi M. M. , Paez J. E. , Vaziri H. H. , Islam M. R.
Published: December 2007

Harsh environmental conditions prevail in most petroleum pipelines as well as downhole tubulars. Under these conditions, corrosion can have adevastating effect on both petroleum production and transportation. The petroleum industry has been using inorganic zinc coating as a primer coating that can withstand prolonged services. It is well known that zinc reacts with steel to form a very strong bond that is not easily broken when subjected to HARSH CONDITIONS. However, several areas of weakness persist. There is no existing method to select the most effective primer among many that are available commercially. The current methods do not optimize the thickness of the primer and the mechanisms of corrosion prevention in the presence of abrasive materials are not well understood. This paper addresses these shortcomings of the past and proposes a comprehensive technique for corrosion prevention in harsh environmental conditions.

In a series of experiments, corrosion (both onset and growth) is observed in various pH conditions using various thicknesses of zinc primers. In order to simulate solid/solid interaction (e.g. pipeline in an environment where sands and dusts prevail), sand blasting is performed for a predetermined period. In this, the time of sand blasting was considered to be crucial since the time in the laboratory must be scaled down to model field conditions. For different cases, the nature of corrosion and the extent of growth were observed both in the presence and absence of top coatings. The extent of corrosion under sand abrasion was also observed. A procedure is recommended for determining optimum thickness of zinc primers under various environmental conditions (e.g. pH, sand erosion). Top coatings were found to be necessary for several of the conditions. Fundamental chemistry as well as fractal modeling is used to define the kinetics of corrosion growth. The role of zinc primer in developing a barrier is incorporated. The study results compare favorably with the experimental results
Rotaflex Efficiency and Balancing
Authors: McCoy J. N. , Podio A. L. , Rowlan Lynn
Published: December 2007

The unique geometry of the RotaFlex pumping unit results in a constant torque arm (or torque factor) on most of the upstroke and downstroke. The geometry promotes high electrical efficiencies. These electrical efficiencies can be measured by comparing the work required to raise the produced liquids from the net liquid level depth to the work input to the system as electrical power. Also favorable for high electrical efficiencies is the minimized electrical generation of the RotaFlex pumping unit, when compared to conventional beam pump units. RotaFlex balancing can be performed using electrical power measurements, and the amount of counterweight that must be added or removed from the counterweight box to balance the unit can be calculated directly by software using the power measurements and RotaFlex data. Therefore, power balancing does not require knowledge of the weight of the counterweight box and the auxiliary weights as is required with conventional mechanical balancing. To describe and explain the proper procedure for determining electrical efficiency and balanced torque, an example of electrically balancing a RotaFlex pumping unit to the optimum efficiency is presented.
Determining Frac Effectiveness from Production: Case History
Authors: Rietman Noel D.
Published: December 2007

Thirty-two tight gas wells completed in the Cleveland Formation in Lipscomb County, Texas were analyzed to determine the effectiveness of using production rates to evaluate completion techniques. Production rate tools tested were rate-versus-time, cumulative-versus-time and rate-versus-cumulative graphs of the first six months, twelve months and twenty-four months of production. The standard used to measure the validity of conclusions from the production curves was the frac length of each well as determined by inverted decline curve analysis. Comparisons between offset wells and also between groups of wells (using frac lengths to group the wells into quartiles) resulted in the wrong conclusion about half of the time. In other words, flipping a coin to determine the best frac treatment would have been just as effective as comparing production rates. The most likely reasons for this failure of production rate evaluation techniques are lack of uniformity of reservoir characteristics and boundaries to the drainage area.

The conclusion is that, at least for the wells studied, some analytical method of determining treatment effectiveness such as Fetkovich curves, inverted decline curve analysis or buildup analysis should be used to evaluate various types and sizes of frac treatments. Production comparisons can be misleading if they are not validated by analytical methods.
Corrosion Inhibition/Foamer Combination Treatment to Enhance Gas Production
Authors: Campbell Samuel , Ramachandran Sunder , Bartrip Keith
Published: December 2007

Liquid holdup may decrease the productivity of gas producing wells. The use of foaming agents is a popular method of reducing fluid levels and increasing well production. However, corrosion rates may still be excessive in these cases requiring a mitigation strategy. The use of chemicals that act as foaming agents and corrosion inhibitors have great utility in gas wells with excessive water holdup. The underlying physical principles and measurable parameters include dynamic interfacial tension, foaming ability, and corrosion inhibition. A mechanistic description to predict the performance of chemical foamers is developed based upon measurable parameters demonstrating that the dominant factor is foam density. In addition, the effectiveness of a chemical program to unload a well and inhibit corrosion is demonstrated.
The Effects of Formation Hardness, Abrasiveness, Heterogeneity and Hole Size on PDC Bit Performance
Authors: Mensa-Wilmot Graham , Fear Martyn J.
Published: December 2007

Improvements in drilling efficiency and economics are continuously being achieved with PDC bits, specifically in medium-hard and non-abrasive formations – normal drilling. These gains have been aided by advancements in PDC bit technology, their selection practices and BHA design.

However, PDC bit performance in harsh environments – hard, abrasive and heterogeneous formations – still lacks consistency and predictability. The problems associated with these applications are amplified when large hole sizes (diameters greater than 12") are drilled. Performance qualifiers such as footage, and especially rate of penetration (ROP), tend to be considerably lower in such instances. Considering the depths at which small hole sizes (diameters less than 9") are usually drilled, the likelihood of such hole sizes being drilled in harsh environments tends to be very high. It is evident that huge operational savings will be achieved if the performances of PDC bits are improved.

This paper will discuss the effects formation hardness, abrasiveness and heterogeneity have on PDC bit performance. In addition, it will establish the influences different hole sizes have on PDC bits, especially in harsh environments. Drilling efficiency will be discussed in terms of operational parameters, vibrational behavior, durability equivalency (DEQ) and lithology differences. An engineered approach to PDC bit development and selection, that enhances performance in harsh environments and in large hole sizes, will be discussed.
Intensive Evaluation of a Rig's Fluid Handling System Shown to Dramatically Improve Efficiency, Lower Costs
Authors: MacEachern D. P. , Hudson C. E. , Toups B.
Published: December 2007

A comprehensive and quantitative evaluation of the mud mixing, solids control and waste management systems on rigs prior to the commencement of a drilling operation has been shown to dramatically improve operational efficiency and ultimate fluid-related costs.

This paper discusses the evaluation process, which includes an audit of the total fluids system, aimed at assuring that the solids control, fluids handling and mixing systems are functioning to specifications and configured properly for the well objectives. The authors will examine in detail the various components of an intensive rig evaluation, which include everything from the condition and configuration of the shakers to the dimension of the mud pits and their fittingness for treating and processing the specific mud volumes required for a given project. In addition, the evaluation includes a safety audit of all areas where fluid engineers will be working, such as the pit room and shaker house.

In demonstrating the effectiveness of such an evaluation, the authors will consider specific examples, including audits conducted on newbuilds, rigs undergoing refurbishment and even to improve the solids control and waste management efficiency of units while a well was in progress. The authors will discuss the results of an evaluation of an entire fleet of deepwater rigs with emphasis on the subsequent recommendations. On one deepwater rig in the Gulf of Mexico, the operator saved $48,000 in fluid-related costs when the evaluation revealed that the solids control equipment was not operating at peak efficiencies. Many existing rigs are found to require only a minimum amount of repair or adjustments to show improvements. On most occasions, the evaluation can be used to construct more efficient solids processing and waste management plans.