bluuebunny/crossref_metadata_2025 huggingface dataset:
Waterflood Redevelopment Prior to Future Tertiary Attempts - A Case History
Authors: Roy M.B. , Tucker C.W. , Lakey C.J. , Cloud W.B.
Published: December 2007

The Postle Field, located in the Oklahoma Panhandle, is typical of modern oil fields with waterflood programs now approaching maturity. The field appears to have all the requisites necessary for a successful tertiary recovery program except adequate crude price incentives. While adequate price incentives for a tertiary project are not yet a reality, an infill redevelopment program has been initiated. This program has profitably increased production, recovered oil from previously bypassed areas, added substantial previously bypassed areas, added substantial insight into field recovery mechanisms, and provided additional information essential for the development of a tertiary recovery program. program

Introduction

Millions of barrels of oil await recovery in existing fields beyond primary and traditional waterflood mechanisms. An approximate U. S. oil scenario is as follows: some 109 billion barrels have been produced to date, and estimates are that an additional 33 billion barrels will be recovered by primary and secondary recovery techniques, of which waterflooding is the chief method. The ultimate recovery of 142 billion barrels via primary and conventional fluid injection techniques represents 32 percent of 442 billion barrels of original oil-in-place. Therefore, the remaining 300 billion barrels offer an enormous potential for application of tertiary recovery potential for application of tertiary recovery methods. In today's state of the art, chemical flooding appears to be the most generally applicable tertiary recovery method. In spite of extensive laboratory studies and a few small-scale field tests, the commercial viability of this technique remains unproved. Today's government imposed restraints on oil prices are certainly not conducive to a badly prices are certainly not conducive to a badly needed momentum in tertiary recovery projects which require a huge front-end cost and a very high risk capital exposure. However, one thing is certain: tertiary recovery efforts must be initiated to help meet this country's energy demands — even though it may be several years from now, pending a favorable economic environment. In the meantime, a number of activities can be incorporated in current operations which will be helpful in the future when a tertiary project is initiated. The Postle Field is a case in point.

FIELD DESCRIPTION

The Postle Field is located 250 miles northwest of Oklahoma City, near the center of the Oklahoma Panhandle.
Norge Unit Plan Implemented
Authors: Jowell Jack H. , Haberthur Charles R.
Published: December 2007

PUBLICATIONS RIGHTS RESERVED PUBLICATIONS RIGHTS RESERVED Permission to include this paper in the Proceedings for the 1977 Permission to include this paper in the Proceedings for the 1977 Oklahoma City Section Regional Meeting of the Society of Petroleum Engineers, held in Oklahoma City, February 21–21, 1977, was secured from PETROLEUM ENGINEERS, where it was first published in the November, 1976 issue. Permission to copy is restricted. The paper is subject to correction.

The engineering and planning activities preceding and following unitization of the preceding and following unitization of the Norge Marchand Unit in Grady County, Okla., are described herein. The 12,000-acre, 75-tract unit was approved by the Oklahoma Corporation Commission in Feb. 1974, 3 years after the discovery of the field.

The unit area contained 75 wells developed on 160-acre spacing and producing from the Marchand sand at a depth of 10,100 to 10,800 ft. Sixty percent of the ultimate primary reserves had been produced prior to unitization.

The plan of operation was designed to maintain reservoir pressure at or near the bubble-point pressure of the reservoir fluid by water injection. The project was expected to increase recoverable reserves by 31,750,000 bbl of oil. This represents an increase in ultimate recovery from 15.7 percent of the original oil in place by primary depletion to 32.5 percent.

Reservoir pressure had declined below the bubble-point pressure of 2,826 psi to 2,405 psi when water injection commenced. Water psi when water injection commenced. Water injection volume has been equivalent to 4.6 percent of the pore volume, or 50 percent of percent of the pore volume, or 50 percent of the required fill-up volume. No severe channeling or water breakthrough has occurred. Producing GOR's have been reduced substantially Producing GOR's have been reduced substantially and reservoir pressure has increased.

The designed injection rate of 35,000 BWPD has been achieved in 23 input wells. A suitable injection to voidage ratio has been maintained throughout the field. A planned eight-well infill development program is in progress to restore some of the productive progress to restore some of the productive capacity lost by injection well conversions. An adequate water supply of desirable quality has been developed and water injectivity has matched predictions closely.

Introduction

Concentrated engineering and planning efforts by 17 oil operators, representing 60 working interest owners and 344 royalty owners, culminated in the unitization of the 12,000-acre Norge Marchand Unit in Grady County, Okla., within 3 years after discovery of the field. By order of the Oklahoma Corporation Commission dated Feb. 19, 1974, the project was authorized for the purpose of pressure maintenance by water injection, which was expected to increase the recoverable reserves by 31,750,000 bbl of oil. Sun Oil Co. was named unit operator.
Prevention and Control of Formation Damage
Authors: Hower Wayne F.
Published: December 2007

WELL COMPLETION

All wells are susceptible to formation damage at any time during the life of a well. Some damage sources are drilling fluids, cement filtrates, water and/or emulsion blocking, oil wetting of silicate surfaces, "dirty" treating fluids, and clays. Clays may be considered a major source of permeability reduction. This damage can occur when a water foreign to the formation contacts the clays, causing them to break loose and migrate with fluid loss. Subsequent bridging of clay particles at flow restrictions in the rock can then cause a decrease in permeability.

Completion techniques can vary considerably from one field to another as methods should be devised to fit particular conditions. Good completion procedures depend upon having reliable well data available, making use of past experiences, and using clean (filtered) past experiences, and using clean (filtered) an properly treated workover and stimulation fluids.

Permeability damage often occurs with the initial completion of a well. However, this damage usually exists only a short distance into the formation and can be removed with relatively small volumes of various types of acid solutions.

Where a well is to be stimulated, a better procedure can be developed if cores are procedure can be developed if cores are available for tests. The results of these tests will help develop the type of fluid to use for the treatment. Two of the tests that should be conducted are as follows.The selection of a surfactant to be added to the stimulation fluid that will help to prevent emulsion development and also provide very low interfacial tension values provide very low interfacial tension values between the fluid and hydrocarbons in the formation. The latter is essential in the recovery of the stimulation fluid (usually aqueous) from formation flow channels. The surfactant should also leave the rock water wet.The analysis of the cores to determine mineral and clay content is very important. If enough clay is present for the formation to be considered to be water sensitive, 1- to 2-percent potassium chloride or ammonium chloride can be added to the water-base stimulation fluid to minimize possible permeability damage due to clays.
Polyacrylamides Can Restrict Water, Oil and Gas Production - It's Your Choice
Authors: Sparlin Derry D.
Published: December 2007

Production of water from oil wells is becoming an increasingly serious problem each year. As oil reservoirs are produced, increasing water production results from water coning, from rising water-oil contacts, from channeling behind the casing or through high permeability streaks. Increased costs of producing and handling unwanted water are minor compared to the loss of oil production rate or loss of oil because of early abandonment of wells resulting from excessive water production.

Many good water shutoff techniques are available to the industry, but most of them shut off all production from the portion of the wellbore where they are used. Products such as cement, sodium silicate, and plastics are capable of completely sealing a well; thus, they should be selectively placed. Before such materials are used, the exact source of water production must be located and isolated so that only the water is shut off. If this is not done properly, oil production may be reduced permanently. production may be reduced permanently

Introduction

In recent years the most promising water control materials have been polyacrylamides. These water soluble polyacrylamides. These water soluble polymers are capable of greatly polymers are capable of greatly reducing the permeability of a water producing formation without significantly producing formation without significantly altering the permeability to oil in the oil zone. They do this without the need to locate the source of the water or of isolating the water source. This can result in large increases of oil production rates and reduction of water production rates and reduction of water production simply by injecting the polymer production simply by injecting the polymer solution into the well, then returning the well to production. It is postulated that the accelerated oil production that often results from this type of treatment is due to a reduced head in the wellbore as less water is being produced. It is also possible that permeabilities of portions possible that permeabilities of portions of watered out formation are reduced enough by the polyacrylamides that the natural sweep pattern into the wellbore is affected. Thus, additional oil is recovered.
Evaluation of Reservoir and Hydraulic Fracture Properties in Geopressure Reservoirs
Authors: Poe B. D.
Published: December 2007

Field production performance data and multiple pressure transient tests over a period of time for oil and gas wells in geopressured reservoirs have been found to often exhibit marked changes in reservoir effective permeability over the producing life of the wells. Similarly, the use of quantitative fractured well diagnostics to evaluate the production performance of hydraulically fractured wells have clearly shown that effective fracture half-length and conductivity can be dramatically reduced over the producing life of the wells.

This paper reports the results of the research, development, and application of production performance analysis models to directly measure the changes in the reservoir effective permeability and fracture effective conductivity of hydraulically fractured wells completed in reservoirs that are subject to stress-dependent variation of the intrinsic formation and fracture properties. The interpretation model development is documented in the Appendices of this paper. Field examples are presented which demonstrate the application of the interpretation models to both unfractured and hydraulically fractured well production performance analyses in which stress-dependence of the reservoir and fracture properties are clearly exhibited.
Analyzing Pressure Transient Test in Semi-Infinite and Finite Reservoirs Using De-Superposition Method
Authors: Zheng Shi-Yi , Stewart Ggeorge , Corbett Patrick
Published: December 2007

Conventional well test interpretation is dominated by the analysis of pressure BuildUp (BU). The method for analyzing BU is derived by the principal of superposition based on the constant terminal rate DrawDown (DD) solution of an "infinite" reservoir with uniform properties. The presentation of the diagnostic plot (log-log plot) and flow regime identification from the pressure derivative curve – in the Late Time Region (LTR), in particular, critically rely on time functioning. The most popular time functioning used for well test analysis is Horner and Agarwal equivalent time. However, these time functioning methods are not reliable for the LTR analysis. When linear (semi-infinite fluvial channel or compartmentalized systems) and pseudo-steady-state flow (finite or closed system) are present, the flow regime diagnostic at LTR using Horner or Agarwal equivalent time frequently result in a false definition of flow regime and misleads the analyst.

The de-superposition method can present the pressure BU in the same way as that for a DD, so the ambiguity in identifying the LTR behavior can be resolved. On the other hand, the DD LTR behavior (pressure derivative) in semi-infinite or finite reservoir systems is very valuable for the identification of the reservoir external boundary conditions (even though it is usually not good to define the radial flow region due to the rate fluctuation and often, incorrect production history input). Experience has proved that BU analysis using the de-superposition method combined with DD LTR analysis can provide much more confident well test analysis.

In this paper, two field examples conducted in the fluvial gas reservoirs in the Gulf of Thailand have been interpreted in this way. At first, one of the tests has been analyzed using the conventional method by ignoring the DD. Then, the examination of DD LTR and the analysis of pressure BU using de-superposition method have been conducted to show where analysis was wrong in the first approach. Following the same procedures, the second test has been interpreted to further demonstrate the value of de-superposition method in analyzing test conducted in reservoirs with limited extent.
The Price Mechanism of Natural Gas and Its Relative Environment Condition
Authors: Ma Songping , Ma Xin
Published: December 2007

The natural gas market has its own characteristics that are distinguished from other common energy markets. It is presented that two kinds of establishing mechanism in natural gas prices are discussed and the development trend of the natural gas market in China is proposed, i.e. from regulation to deregulation. The related environment conditions on the market deregulation are divided into hard and soft ones. The hard environment conditions are as follows: establishing a competitive supply market structure; the transportation and distribution pipeline network for natural gas developed in a certain degree of scale, on which a competitive market is depended; continuous reorganization of gas production enterprises, establishing independent business for transportation and distribution services of natural gas, nondiscrimination services and rigorous government regulation; increasing the requirement level on natural gas through economic development, and rising gas supply capacity by domestic development and opening up in China’s natural gas industry. The soft environment condition is to build up more complete legal systems for the natural gas market. The time progressing of the gas market deregulation depended on the perfect processing of hard and soft environment conditions. It is maybe required about ten years in China.
Asphaltenes Deposition Control in Lake Maracaibo Crude Oil Production
Authors: García María del Carmen , Chiaravallo Nicolás
Published: December 2007

Asphaltene deposition in oil production constitutes a critical and difficult to control problem, in terms of productivity and production operation costs, going from the reservoir to surface facilities. This phenomenon causes severe plugging and flow reduction due to phase changes in the crude oil through its production. When pressure declines in the reservoir, due to its exploitation, the single phase system may undergo asphaltenes precipitation and deposition, specially near the bubble point, where their solubility reaches a minimum. Severe formation damages occur when this pressure reduction takes place within the reservoir, and asphaltenes deposit in the porous media. The magnitude of the asphaltene precipitation tendency is strongly related with the crude oil characteristics, considering the asphaltene particles stabilization by other components of the oil. Prevention methods oriented to the asphaltenes deposition control include chemical additives injection. These products have the particularity of disperse or inhibit the asphaltenes aggregation, avoiding the formation of precipitates that eventually deposit on metal or mineral surfaces, causing a severe flow reduction. The main purpose of this work is to show an experimental methodology oriented to the selection of appropriated asphaltene inhibitors to be applied under surface, production and reservoir conditions. Dead oils characterization, along with several commercial additives effectiveness evaluation at surface conditions, followed by PVT studies on bottomhole crude oil samples, allowed to design adequate asphaltene prevention treatments for every particular case. Dead oil studies included SARA characterization and asphaltenes precipitation trends. Live oils analysis were performed by means of asphaltenes dispersion vs. pressure curves, asphaltenes flocculation onsets under isothermal pressure depletion, and a selected inhibitor evaluation. Examples from operations carried out in western Venezuelan facilities, illustrate the benefits derived from this methodology.
A Streamline Approach for Integrating Transient Pressure Data into High Resolution Reservoir Models
Authors: Kulkarni Kari Nordaas , Datta-Gupta Akhil , Vasco D. W.
Published: December 2007

Streamline models have shown significant potential in integrating dynamic data into high-resolution reservoir models in a computationally efficient manner. However, previous efforts towards production data integration using streamline models have been limited to tracer data and multiphase production history such as water-cut at the wells. In this paper we generalize the streamline approach to transient pressure applications by introducing a ‘diffusive’ time of flight along streamlines. We show that the ‘diffusive’ time of flight allows us to define drainage areas or volumes associated with primary recovery and compressible flow under the most general conditions. We then utilize developments in seismic tomography and waveform imaging to formulate an efficient approach to integrating transient pressure data into high-resolution reservoir models.

Our proposed approach exploits an analogy between a propagating wave and a propagating ‘pressure front’. In particular, we adopt a high frequency asymptotic solution to the transient pressure equation to compute travel times associated with a propagating ‘pressure front’. The asymptotic approach has been widely used in modeling wave propagation phenomena. A key advantage of the asymptotic approach is that parameter sensitivities required for solving inverse problems related to production data integration can be obtained analytically using a single streamline simulation. Thus, the approach can be orders of magnitude faster than current techniques that can require multiple flow simulations.

We have applied our proposed approach to both synthetic and field examples. The synthetic example utilizes transient pressure response from an interference test in a nine-spot pattern. The spatial distribution of permeability is estimated by matching arrival times of the ‘pressure front’ in each of the observation wells. The field example is from the Conoco Borehole Test Facility in Kay County, Oklahoma. A series of pressure interference tests were performed in a skewed five-spot pattern to identify the distribution and orientation of the natural fracture system at the Fort Riley formation. We have inverted the pressure drawdowns at the observation wells to create a conceptual model for the Fort Riley formation. The predominant fracture patterns emerging from the inversion are shown to be consistent with outcrop mapping and crosswell seismic imaging.
Sequential Neural Simulation: A New Approach for Stochastic Reservoir Modelling
Authors: Niu Y. , Wong P. M. , Chen L.
Published: December 2007

This paper proposes a new and practical neural network for stochastic reservoir modelling. The new approach known as sequential neural simulation (SNS) is developed based on the use of an ensemble of supervised neural networks within the conventional sequential simulation framework. Compared to the sequential Gaussian simulation (SGS), SNS uses a data-driven conditional distribution and can handle multivariate inputs and non-linearity. It does not require any (cross) variogram models and does not use a parametric function for simulation. The formulation of the algorithm however does not guarantee the reproduction of the desired statistics. The methodology is demonstrated in a fluvial-deltaic reservoir in China. Porosity is simulated using different number of inputs followed by oil in place estimation. The study shows the simplicity of the methodology for the incorporation of multiple soft information.
Optimising Performance of Mature Reservoir: An Innovative Use of Coiled Tubing Drilling Technology to Tap Unswept Reserves, Alwyn North UKCS
Authors: Lheure S , Müller S , Kimber R. , Holehouse S. G.
Published: December 2007

This paper describes the rationale, the planning and the preliminary results of the first Coiled Tubing Drilling (CTD) experience for TotalFina. The objective was to enhance production from a high water-cut oil well producing under unstable conditions and located in an area of possible upsides. This well was drilled in 1990 on the edge of a fault-scarp degradation complex in the Brent East panel of the Alwyn Field. The geological uncertainties in this complex area needed to be reduced and it was necessary to reassess seismic, core and reservoir data to progress the current knowledge base. Analytical calculations supported 3D reservoir modelling techniques to constrain some of the uncertainties.

Drilled in 1999, well 3/9a-N30Y was the first coiled tubing sidetrack from a producing well on Alwyn. The motherbore, 3/9a-N30, was still producing around 380 stb/d, although production had recently become intermittent.

The well path presented a challenging trajectory due to the location of the unswept area in relation to the direction of the motherbore. After drilling 240m a series of operational issues arose, necessitating the drilling of the world's deepest open hole sidetrack with coiled tubing, but ultimately the BHA was left in hole. The coiled tubing was then utilised as an uncemented liner, perforations using slim guns were added along the liner, and the well was brought onto production. The CTD drain alone produced at an initial rate of 2900 stb/d, which stabilised out at 1200 stb/d after an initial rise in water cut.

The successful outcome of 3/9a-N30, which was drilled in a complex offshore environment, confirmed the viability of CTD as a technique for accessing smaller pockets of remaining oil, whilst some of the operational difficulties encountered highlighted the need to simplify future trajectories to maximize the chance of success. With the possibility of drilling future CTD wells, further increases in productivity and reserves will be achieved at a significantly lower cost compared to conventional drilling.
Advanced Sensor Infrastructure for Real Time Reservoir Monitoring
Authors: Kluth E. L. E. , Varnham M. P. , Clowes J. R. , Kutlik R. L. , Crawley C. M. , Heming R. F.
Published: December 2007

Over the past ten years Chevron and SensorDynamics have partnered in developing a practical approach to intensive surveillance of remote downhole oil and gas wells and related production infrastructure.

The work has resulted in a unique family of slim-line fiber optic sensors, along with a simple method of deploying these sensors remotely in oil and gas wells, using conventional hydraulic control lines as pathways into the heart of the reservoir. Most importantly the program has also produced coating technology that stabilizes the fiber optic sensors and cables in the high-temperature, high-pressure environments of deep wells.

Sensors cover a wide range of parameters, including distributed temperature, pressure, acoustic sensors and acoustic sensor arrays for in-reservoir imaging of formation, fluid front movements and seismic relaxation.

The result of this long-term partnership has been an integrated solution that forms a credible basis for permanent and intensive surveillance of oil and gas reservoirs, a solution that ensures availability of dynamic downhole data over the life of a reservoir. It has the additional advantage of allowing sensor up-grade, sensor replacement and the addition of new sensor types as these become available – without interruption of normal production and at minimal incremental cost.

We report on a system that can address EOR applications, intelligent well monitoring and that we believe offers a basis for instrumenting deep and hot sub-sea reservoirs and sub-sea production infrastructure.

We report some of the key issues in deploying sensors in hydraulic control lines in oil wells, in protecting sensors in harsh downhole environments (250deg C, 600 bar) and sensor performance results, from laboratory and field test work. We also offer some views on the implications to the future of real-time integrated reservoir management, where availability of downhole information has important value in all phases of the life of a field – from cradle to grave.
Interfacial Instabilities In Porous Media
Authors: Castor T.P. , Somerton W.H.
Published: December 2007

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

Spontaneous emulsification at liquid-liquid interfaces and Haines' jump phenomenon at liquid-gas interfaces may be explained in terms of classical fluid mechanics, mass and energy diffusion and surface thermodynamics. These phenomena are examined in this paper in terns of an interaction between Marangoni effects and capillary forces. Marangoni effects refer to the motion of an interface due to gradients in interfacial tension.

The porous medium used to study these effects is described geometrically as an interconnected network of converging-diverging channels. The flow of two immiscible fluids in these channels is described by the Navier-Stokes equations at very low Reynolds numbers. Differences in the potential (temperature and/or concentration) of potential (temperature and/or concentration) of these fluid phases will induce mechanical movement of the interface.

The resultant unsteady motion is modelled as a classical Rayleigh flow or suddenly accelerated plane flow. This motion will initiate disruption plane flow. This motion will initiate disruption of the interface if the pressure drop due to shear forces is greater than the pressure drop due to normal forces.

Analytical expressions developed in this work suggest parametric dependence of interfacial unstabilities in porous media on (i) differences in the kinematic and absolute viscosity (ii) the magnitude and direction of the interfacial tension gradient due to temperature and/or concentration differences (iii) absolute magnitude of the interfacial tension (iv) wettability of the porous matrix and (v) a geometric factor which is porous matrix and (v) a geometric factor which is characteristic of the microscopic structure of the porous medium. The influence of these parameters is supported by experimental data from the parameters is supported by experimental data from the literature.

Introduction

Additional chemical and/or thermal energy is required to overcome the capillary forces which entrap large quantities of residual oil in depleted petroleum reservoirs. Removal or reduction of interfacial forces with or without the reduction of viscous forces will allow the mobilization of isolated droplets and ganglias of oil and the subsequent formation of local regions of high oil saturation. The reservoir mechanics of tertiary floods will thus have to consider a microscopic mobilization efficiency in addition to the macroscopic displacement and areal sweep efficiencies. Physical and mathematical conceptions of the isolation and mobilization mechanisms will be necessary for the quantifying of microscopic efficiencies.
Improved Oil Recovery Based On Optimal Waterflood Pressure
Authors: Kolbikov S. V. , Vaughn H. F. , Usmanov A. A. , Chalov S. E.
Published: December 2007

The paper reviews oil recovery improvement for black oil fields with low bubble point pressure, which are developed under waterflood. The Kogalym field, located in Western Siberia, is approximately 2,400 meters true vertical depth, and produces from Cretaceous and Jurassic sand deposits. The black oil system has a bubble point pressure of 8.5 Mpa, less than 35 % of the initial reservoir pressure of 123.7 MPa. The optimal development strategy of such reservoir depends on selecting water flood elements, well pattern and flood pressure. The focus of this work is to justify an optimal waterflood pressure. In 1997-98 numerical simulation was performed on a separate waterflood pattern. A representative geological model of the pattern was constructed on the basis of comprehensive core analysis data from the well # 1037. Several development strategies were tested on the ECLIPSE model for various waterflood pressures: 24, 19 and 15 MPa. The maximum oil recovery factor (ORF) was obtained with a waterflood pressure of 15 MPa. The most economic case was with a waterflood pressure of 19 MPa. This pressure of 19 MPa is the optimal value of waterflood pressure, which is 75% of the initial reservoir pressure and exceeds the bubble point by more than 10 MPa. The analysis of the Kogalym field development for the last four years confirms these conclusions.
Generation of Fractal Porosity and Permeability Fields Conditioned to Well-Test Pressure and Geostatistical Data
Authors: Zeybek Ayse Donmez , Onur Mustafa
Published: December 2007

In recent years, it is shown that the inverse problem theory based on Bayesian estimation provides a powerful methodology not only to generate rock property fields conditioned to both static and dynamic data, but also to assess the uncertainty in performance predictions. To date, standard applications of inverse problem theory given in the literature assume that rock property fields obey multinormal distribution and are second order stationary. In this work, we extend the inverse problem theory to cases where rock property fields (only porosity and permeability fields are considered) can be characterized by fractal distributions. Fractional Gaussian noise (fGn) and fractional Brownian motion (fBm) are considered. To the authors' knowledge, there exists no study in the literature considering generation of fractal rock property fields conditioned to dynamic data; particularly to well-test pressure data.

We show that available Bayesian estimation techniques based on the assumption of normal/second-order stationary distributions can be directly used to generate conditional fGn rock property fields to both hard and pressure data because fGn distributions are normal/second-order stationary. On the other hand, we show that because fBm is not second-order stationary, these Bayesian estimation techniques can only be used with implementation of a pseudo-covariance (generalized covariance) approach to generate conditional fBm fields to static and well-test pressure data.

Using synthetic examples generated from two and three-dimensional single-phase flow simulators, we show that the inverse problem methodology can be applied to generate realizations of conditional fBm/fGn porosity and permeability fields to well-test pressure data. We conclude by showing how one can then assess the uncertainty in reservoir performance predictions appropriately using these realizations.
A Successful In-Situ Combustion Pilot In The Midway-Sunset Field, California
Authors: Counihan Thomas M.
Published: December 2007

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

This paper presents a case history of a technically and economically successful dry in-situ combustion pilot conducted in a thick, moderately dipping, heavy oil reservoir located in the Mid-way-Sunset Field in western Kern County, California. The pilot was situated near the oil-water contact with a heterogeneously depleted area updip in the regionally extensive, homoclinal Potte Sand of Upper Miocene Age. With less than 15% of the original oil-in-place produced, reservoir and production analyses indicated the impending production analyses indicated the impending demise of economic cyclic steaming. This trend coupled with poor results from laboratory steam drive tests and minor water encroachment problems in the field led to the consideration of in-situ combustion as the most reasonable mechanism for recovery of the remaining oil reserves. Air injection into the arbitrarily delineated central Potter zone began in January 1972. Production Potter zone began in January 1972. Production analysis and an extensive coring program following 3-1/2 years of operation indicated nearly 80% of the original oil-in-place had been recovered from the initial pilot pattern. Two additional patterns were fired, one of which was a former patterns were fired, one of which was a former steam drive pilot which gives a basis for comparison of the two enhanced recovery methods in this reservoir.

Introduction

All three areally non-contiguous, inverted five-spot in-situ combustion patterns were located in the Potter Sand of the S-1/2, NW-1/4, Section 23, T31S, R22E (see Figure 1).

Development of the Potter Sand in this area of Section 23 began in 1910 by Chanslor-Western Oil and Development Company's predecessor, Chanslor-Canfield Midway Oil Company. By the advent of the cyclic steam (huff and puff) recovery method in this section in 1965, primary production had recovered less than 2% of the original oil-in-place. Cyclic steam stimulation recovered an additional 12% of the original oil-in-place by the time Well 154 began air injection in January 1972.

The Potter Sand of the portion of Section 23 discussed in this paper yields less ultimate oil recovery by the cyclic steam method than areas to the west (e.g. Section 22, T31S, R22E) with equivalent well spacing. Evidence of this can be seen in the increased rate of decline: 10–20% per year for "Section 23" versus less than 10% per year for Section 22.
Log Analysis In The Shallow Oil Sands Of The San Joaquin Valley, California
Authors: Vohs J.B.
Published: December 2007

Many fields in the San Joaquin -Valley of California produce oil from a depth of 2,500 ft or less. During the period of primary production in these fields, evaluation of potential pay intervals from logs was restricted to explanation of ES logs and correlation. With the introduction of secondary and tertiary recovery techniques the need for more and better answers, more quickly available, became apparent. However, several log-analysis problems had to be resolved. Formation evaluation using well logs was complicated by the shaliness of the sand intervals, the low and variable salinity of the formation waters, and the presence of low-pressure-gas (depleted) zones in many of the shallow sands.

Solutions to these problems have required more modern logging programs art interpretation techniques. Logs available for the evaluation programs art interpretation techniques. Logs available for the evaluation of these sands are the Dual Induction-Laterolog (DIL*), the Compensated Formation Density log (FDC*), the Compensated Neutron log (CNL*), and the Microlaterolog* or Proximity* log. With this suite of logs it is possible to determine the shale content, porosity, saturation in the possible to determine the shale content, porosity, saturation in the flushed zone, and water saturation of the sand, and to locate the low-pressure-gas sands and depleted zones. In cases where fresh water and oil are interlayered it is possible to tell which sands contain oil and which contain only water. Because a quick interpretation is required, wellsite techniques are called for. These will be described. More sophisticated computer techniques are, of course, available. These will not be covered in this paper.

Introduction

Oil has been produced since early in the century in the San Joaquin Valley of California, indicated as the circled area on the map of Fig. 1.

P. 1
Wellsite Formation Analysis Using The Ddl Computer
Authors: Head Mickey P. , Gearhart Marvin
Published: December 2007

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

The Direct Digital Logging System, first introduced in 1975 as a new concept in well logging, has proven the feasibility of digital systems for recording logs. The surface equipment necessary to produce logs includes a mini-computer and laser recorder, along with other input/output devices and is well sected for wellsite formation analysis. Log signals are sampled four times per foot and are recorded in engineering units on per foot and are recorded in engineering units on magnetic tape cartridges.

Depth shifting required to match subsequent logs to the base log is performed through a calculator type keyboard, with the data interpolated between the depth shift points. Interpolation is possible because of the three inch depth increments. The advantage of interpolation in depth shifting is that no data is lost or created at the depth shift points.

Environmental corrections are applied to the log trace data to remove borehole effects. Computer performed corrections such as borehole correction to the performed corrections such as borehole correction to the Induction Log and mud cake correction to the Sidewall Neutron Porosity Log removes the need for departure charts and hand calculations.

With the digital system, wellsite quick look calculations are performed after the logs are recorded and environmentally corrected, all the data is studied, appropriate parameters are selected, and the program is executed. The digital system is an improvement over existing analog systems because the digital system does not require parameter selection before the logs are run, and the computing is not performed as the well is logged. Digital quick look techniques presently available are logarithmic F overlays and R with porosity.

More detailed evaluation can be performed at wellsite, going beyond the quick look methods. For example, the Induction Electrical Log (IEL) and the Compensated Density Log (CDL) can be combined and solve for volume of shale, shale corrected porosity, and water saturation. Also the Sidewall Neutron Porosity Log (SNP) and the Compensated Density Log (CDL) combination will resolve cross-plot porosity and apparent matrix density, which combined with resistivity often provide good results in complex lithology. provide good results in complex lithology. The new concept of wellsite Direct Digital Logging and computed formation analysis opens a new era in log evaluation. The opportunity to obtain computed logs has been moved to the wellsite, and the applications are just being realized.
Probabilistic Evaluation of Horizontal Wells in Stochastic Naturally Fractured Gas Reservoirs
Authors: Hatzignatiou D. G. , McKoy M. L.
Published: December 2007

The existence of natural fractures in hydrocarbon bearing formations may significantly enhance hydrocarbon production rates and recovery factors. Horizontal wells or drainholes drilled in these types of reservoirs (especially tight gas reservoirs) increase the possibilities of intersecting discrete natural fracture systems in ways that render high well productivity indexes and higher recovery factors than vertical wells, thus enhancing field developmental opportunities.

The performance of horizontal wells in naturally fractured formations and their ability of draining the formation effectively depend on a number of well and formation parameters. Simulation results clearly illustrate that the well location within the flow region, degree of fracture clustering, fracture density, fracture aperture distribution, along with the degree of fracture interconnectedness can govern gas production rates, ultimate gas recovery and reservoir drainage patterns (Hatzignatiou, 1999). Therefore, gas recovery factors for tight fractured reservoirs may differ significantly from those of homogeneous reservoirs with large formation permeability.

This work demonstrates a means of estimating well recovery factors in single-phase gas naturally fractured reservoirs. Uncertainties in these estimates due to network heterogeneity and variability in the connection between the well and the network are quantified in the form of probability-based recovery factors. Emphasis is placed on horizontal wells because these wells are commonly used in developing and producing tight fractured reservoirs.
Application of Azimuthal Density While Drilling Images for Dips, Facies and Reservoir Characterization – Niger/Delta Experience
Authors: Akinsanmi O. B. , Anwasi L. E , Ogundana M. A. , Aibangbe O. , Kienitz C.
Published: December 2007

With the introduction of azimuthal density while drilling tool into the stream of LWD technology in the last decade, a new frontier in understanding and evaluating lateral composition and architectural variability in most reservoirs has been made possible, by the utilisation of this tool in the drilling of high angle wells in the Niger delta. The availability of imaging technology from this tool and the resultant imaging answer product has been used for detailed structural and sedimentological analysis in characterizing reservoirs beyond the resolution of surface seismic. Determination of reservoir properties based on genetic units and identification of flow zones that could potentially contribute to production were derived to enhance the reservoir models for such reservoirs and improve reservoir management.

In most cases, the optimal placement of high angle wells using the conventional well to well correlation techniques have often proved unreliable, due to unexpected lateral discontinuity in the reservoir quality. These occurrence in many reservoirs have been associated with varying sedimentary structures, micro-faulting and unexpected changes in environment of deposition, as evident in Niger delta depobelts. Resulting production from high angle drain holes has been seen to be greatly influenced by the positioning of the well bore relative to structural and formation dip, apart from other completion related problems. Formation dip and structural features have historically been acquired from wire-line logging tools. However, electric logging in high angle wells presents operational difficulties which does not encourage the use of wireline logging.. Images acquired while drilling by the azimuthal density tool provide a method of resolving the correlation uncertainties, and allow quantification of the structural and sedimentological interpretation and the subsequent production pattern across the lateral wellbores. Two field examples where azimuthal density data were acquired and utilized are analyzed. From the data analysis an extra opportunity in terms of reserves were identified.
A Comparative Study of Hydraulic Models for Foam Drilling
Authors: Ozbayoglu M. Evren , Kuru Ergun , Miska Stefan , Takach Nicholas
Published: December 2007

Compared to conventional (incompressible) drilling fluids, relatively little is known about the hydraulic and rheological properties of foamed drilling fluids. The complex flow mechanisms involved in compressible drilling fluid circulation make determination of the optimum combination of liquid and gas injection rates very difficult. Modeling of foam rheology is the key issue in hydraulic design in order to predict the bottom-hole pressure accurately and to optimize different controllable variables for effective cutting transport performance.

The University of Tulsa’s low-pressure ambient temperature flow loop has been recently modified to accommodate foam flow. The flow loop permits foam flow through 2", 3", 4" diameter pipes and an 8" by 4 1/2" annular section. Preliminary experiments have been conducted in which pressure losses were measured for different foam qualities. Measured parameters were gas/liquid flow rates, pressure, differential pressure loss, and temperature.

Statistical analysis was carried out to see the degree of fit provided by Bingham plastic, power law, and yield power law models for the generalized foam flow curve data.

A comparative study was conducted to investigate the predictive ability of the available foam hydraulic models. Models presented by Beyer et al. (1972), Blauer et al. (1974), Reidenbach et al. (1986), Sanghani and Ikoku (1983), Gardiner et al. (1988) and Valko and Economides (1992) were used to estimate the frictional pressure losses during the flow of foam in horizontal pipes. Comparison of the model predictions with experimental pressure loss values show that model predictions of frictional pressure losses can be different from the actual values by 2 to 250 %.
Simulation of Gas Production in SAGD
Authors: Gillis K. A. , Palmgren Claes , Thimm H. F.
Published: December 2007

In a previous paper, a general theory for gas production during Steam-Assisted Gravity Drainage (SAGD) has been presented1. The main gases formed during "aquathermolysis" reactions, carbon dioxide and hydrogen sulphide, tend to be produced primarily via the produced water.

The present paper reports a numerical analysis of the theory, and provides the results of a first simulation that describe the gas production history during SAGD. The numerical analysis includes hydrogen sulphide, carbon dioxide, and methane solution gas.

Gases were included in the numerical analysis by using K-values derived from new theory. This theory accounts for the asymptotic behaviour of gases in solution as the critical point of water is approached.

Simulation results corroborate the initial simple analysis, and agree with field observation. Minor differences are discussed.
A Multiple Fractured-Horizontal Well Case Study
Authors: Cvetkovic’ Branimir , Halvorsen Gotskalk , Sagen Jan
Published: December 2007

A series of solutions corresponding to various conditions are given in a multiple-fractured-horizontal well model. We were able to develop a fast, robust and easy to use software program, a screening-tool product, we hope will be of significant benefit to companies in the petroleum industry. A practising engineer should be able to predict an optimum number of induced fractures in a horizontal well. Some existing analytical approaches are recognised to be inefficient and solutions should be compared to new solutions and new modelling techniques. Extension of the existing single phase oil flow SLAB model to a BOX model improves well production optimisation of a horizontal well with induced fractures; particularly prognosis and diagnosis features. The bringing together of rate-time and pressure-time analysis provides a total package to better characterise horizontal well with induced fractures behaviour. The tendency to over- or under-estimate the oil production needs to be corrected. Inclusion of a restart option is demonstrated in a real case study. This analytical screening-tool is useful for prognosis, diagnosis and improved modelling of oil production from horizontal or near-horizontal well with induced fractures.
Fast-SAGD: Half the Wells and 30% Less Steam
Authors: Polikar M. , Cyr T. J. , Coates R. M.
Published: December 2007

Numerical simulation that provides history match of a SAGD pilot in a Cold Lake type reservoir may be expanded to include steaming of an offset well. In this theoretical configuration, the offset well is equidepth and parallel to, but 50 metres away, from the SAGD producer. After three years of SAGD operation, steam stimulation of the offset well with concomitant increased steaming of the SAGD injector provides early steam communication between the SAGD steam chest and the offset well. The result is markedly increased rate of production of bitumen and reduced steam-oil ratio. Mindful of such results, laboratory work is being undertaken to verify, and understand these results. We also encourage field-pilot testing of this process.