bluuebunny/crossref_metadata_2025 huggingface dataset:
Oil Composition Variation in a Large Deep Water Field
Authors: de Oliveira Pádua Kleber Galvão
Published: December 2007

A new computational model for the non-isothermal gravitational compositional equilibrium is developed and presented.

The mathematical formulation is based on the works of Bedrikovetsky (gravity and temperature using irreversible thermodynamics) and Whitson (algorithm). The computational model is validated on published data and previous simplified models.

An application case is presented for a reservoir in a large deep water field in Brazil. The magnitude of the calculated oil composition variations is sufficient to explain most observed data. The results suggest that the reservoir is partially connected and that the temperature effect can be as important as the gravity effect on the oil composition variation. The changes are significant and the methodology applied is an example of the application of thermodynamic data to the evaluation of reservoir connectivity and fluid properties distribution under the conditions approaching those encountered in natural reservoirs.

Introduction

Compositional variations along the hydrocarbon column are observed in many reservoirs around the world.

They may affect reservoir/fluid characteristics considerably, such as viscosity, total hydrocarbon volume in place and the development of miscibility, leading to different field development strategies.

These variations are caused by many factors, such as gravity, temperature gradient, rock heterogeneity, and hydrocarbon genesis and accumulation processes.

In the cases where thermodynamic associated factors are dominant, the existent gravitational compositional equilibrium (GCE) models, which do not properly account for the temperature gradient effect, allow the explanation of most observed variations. However, it is noted that in some cases, the thermal effect could have the same order of magnitude as the gravity effect.

In this paper, a non-isothermal compositional gravitational model is developed and presented. The model is validated and applied to some fields in Brazil, among them a large deep water field.
High-resolution stratigraphy and geometry of lacustrine turbiditic deposits in a rift succession - Alagoas Basin, Brazil
Authors: Arienti L. M. , de Azambuja Filho N. C. , Backheuser Y.
Published: December 2007

This work deals with the Aptian rift lacustrine succession of Maceió Formation, Alagoas Basin, northeastern Brazil, comparing outcrop information with data from 16 wells of Tabuleiro dos Martins Oil Field (average distance between wells of 200m and 718 meters of cores). Detailed facies and facies associations descriptions were performed, characterizing three main types of deposits: channel/overbank turbidites (outcrops), lobes/interlobes and lacustrine deposits (wells). High-resolution stratigraphy was applied to identify the main stratigraphic sequences and to determine their lateral and vertical continuity. The succession was divided into three 4th order sequences: Alpha, Beta and Gamma. The Alpha Sequence (180 m) was divided into six 5th order sequences, the Beta Sequence (150 m) into four 5th order sequences and the Gamma Sequence (400m) into eight 5th order sequences. In cored wells, 5th order sequences were further subdivided into 6th order sequences.

Isolitic maps of 5thorder sequences were made to understand the distribution of the sandstones in the oil field (subsurface data) and a tridimensional model was constructed using the program Stratigraphic Geocellular Modelling (Landmark) to visualize the external geometry and the relationship between the sequences.

The general geometry and lateral continuity of channel and lobe deposits were compared and the internal heterogeneities, such as shale beds, were mapped to better define the geometry of sand bodies.
Development of a Dual Crosslinker Fracturing Fluid System
Authors: Yaritz Joseph , Stegent Neil , Bailey Tom , Fritcher Eddie
Published: December 2007

Studies of the production histories of wells in the Cotton Valley (CV) region of east Texas led companies to recognize the potential value of optimizing fracture design in this area. As a result, chemists developed a dual crosslink fluid (DCF) system that performs best at high temperatures and moderately high pH levels and uses guar as the gelling agent. The new system has enhanced viscosity and an adjustable crosslink rate.

Because the CV sand formation is a "tight gas sand" region, drilling companies have focused on reducing fracturing costs without hindering well production. The use of the DCF system has resulted in fewer screenouts than Zr-guar systems in the CV formation, and it is a more economical alternative to fracturing fluids that use guar derivatives, such as hydroxypropyl guar (HPG) and carboxymethyl hydroxypropyl guar (CMHPG) as the polymer.

By using a moderately high pH and combining the borate crosslinker with a zirconium (Zr) crosslinker, operators have been more successful at placing proppant in a fracture. The performance of previously used Zr-guar-based fluid systems was often unpredictable at the higher temperatures. The DCF crosslinkers have a synergistic relationship; the viscosity of the combined system is higher than the sum of the separate systems' viscosities. The new system improved operational efficiency to greater than 96% in over 85 treatments last year in the CV region. Gas production from wells treated with DCF is similar to that of the higher-priced CMHPG and HPG fluid systems that use zirconium as the crosslinker.

Description of the Region

Gas production from the Cotton Valley (CV) formation, which includes 14 fields in east Texas, has grown steadily since 1978. Divided into three major areas - Carthage, Oakhill, and Waskom - the depositional system is a transgressive-regressive marine sequence bounded by the Bossier shale below and the Travis Peak formation above (Fig. 1, Page 6). The formation sediments were deposited in a dominantly progradational sequence of shallow marine and fluvial-deltaic environments. The CV formation is Upper Jurassic and is about 1,200 to 1,500-ft thick at depths ranging from 8,000 to 11,000 ft. The area is divided into two major intervals: the upper Cotton Valley (UCV) and the Taylor Sand. In 1980, the low-permeability CV sandstones were classified as "tight gas sands" by the Federal Energy Regulatory Commission (FERC). Permeability of the productive CV sands is typically between 0.01 and 1.0 md. with porosities up to 15% but generally in the 6 to 8% range. Numerous depositional analogs to the CV system exist worldwide.
Integrated Study of Shale Stability in Deepwater, Brazil
Authors: Santos H. , Rego L. F. B. , da Fontoura S. A. B.
Published: December 2007

The development of the huge hydrocarbon reserves located in the deepwater portion of the Campos Basin requires hundreds of wells. In the early exploitation stage, wellbore stability problems were faced in some of the wells, leading to significant losses. In the second Deepwater Technological Program launched by Petrobras in 1992, called PROCAP 2000, one of the projects (out of 11) contemplated the study of the shale instabilities observed. This paper describes this project, the motivations to create it, and the steps to define the topics to be studied. It also describes how the team was chosen, integrating people from the different areas in the company, and from universities and service companies. The paper presents the most important results and how they are being implemented in the field in order to optimize the future wells. Finally, a field case of an extended-reach well drilled in the Campos Basin is discussed, proving the correctness of the project's conclusions.

Introduction

With the discoveries of giant oil fields in the deepwater section of the Campos Basin in the mid 80's, Petrobras was forced to develop technology not available at that time to produce those reserves. The first deepwater technological program, PROCAP 1, was successfully conducted and concluded in the beginning of the 90's. With oil reserves extending to water depths beyond 2000 m, a second program was initiated in 1992. From the experience gained in the previous program, and also from the development of some fields, 11 projects were defined. The main restrictions and difficulties were put together in these projects in all areas from drilling to production facilities.

The development of the hydrocarbon reserves requires the drilling of hundreds of wells. The original idea was to use inclined wells - extended reach and/or horizontal wells - in order to reduce the overall cost of the development stage. The increased complexity of the wells and the geological challenge imposed by the formations located in deepwater, required careful planning of the exploitation scheme, not only to reduce the risks, but also to guarantee economical success. Due to bad experiences on some vertical wells, the decision to create a project focusing on the stability and planning of the wells was strategic.

The managerial aspects of the project are emphasized in this paper. The innovative approach of conducting an integrated project, considering all the aspects that can contribute to the instabilities, turned out to be the most important factor for the success of the project. Due to its multidisciplinary characteristic, involvement of different specialities was a must, creating a challenge to the managers. The most important results are presented here, including the strategies to disseminate them among the operational people. Implementation of the new technology developed is actually the most important item of any research project and it was emphasized at all times during the course of the project.
Reservoir Studies in Fluvial Deposits: From Outcrops to Stochastic Characterization and Flow Simulation
Authors: Ballin P. R. , Faria R. T. , Becker M. R. , Carrasco B. N. , Teixeira P. W.
Published: December 2007

Traditional models for describing complex reservoir geology are not able to adequately represent the heterogeneities and, therefore, to capture most of the aspects that impact on fluid displacement. Stochastic simulations can describe the complex geological architecture, the spacial facies distributions and the significant internal variations of reservoir properties. Although, these simulated scenarios are conditioned to available data - well data - a large portion of the model still has a significant amount of uncertainty - interwell areas. To reduce this problem, the study of analog outcrops gathers a great amount of information that can be taken into account on the stochastic models, decreasing the uncertainty in the interwell scale.

The focus of this paper is on quantification, modeling and stochastic simulation of a highly heterogeneous fluvial reservoir considering the fine scale information from outcrops. Two outcrops and an oil field in the sandy braided fluvial facies of the Cretaceous Açu Formation, Potiguar Basin, NE Brazil, were used in this study. Roadcut outcrops description and the analysis of data from shallow drilling wells and from a high-resolution seismic line allowed the modeling of the surface reservoir analog based on the lithological variability at megascale (genetic units) and macroscale (lithofacies). Outcrop-based geologic model supported the geostatistical description used to stochastic simulate the petrophysical variability in the subsurface reservoir. Flow simulation studies of the reservoir were held considering the output of the geostatistical modeling and an integrated iterative approach was required.
Quick Look Method Of Log Interpretation Using Magnetic Resonance Porosity And Dielectric Porosity
Authors: Alguero A. , Glorioso J.C. , Mallaviabarrena M.A.
Published: December 2007

In the never ending search to reduce drilling cost the ability to reduce the time spent in analyzing well logs and making well completion decisions in a timely fashion is very important. The ability to make Quick Look wellsite decisions has proven elusive in the Neuquen basin due to the complex lithology encountered in the basin.

New generation logging tools now exist that make dependence on Archie's equations and all the variable parameters that are needed by them not a requirement in reaching sound decisions in the early step of new well completion. Through the comparison of the mineralogy free porosity provided by Nuclear Magnetic Resonance tools and the highly water filled dependent porosity available from the Dielectric tools a method has been found to make a quick look well site qualitative interpretation.

In combination with Rw and Rwa overlay methods we are able to confidently make decisions much more quickly and save considerable rig time.

The objective of this paper is to demonstrate a visual comparison of the two porosity indicators and their use to highlight probable productive zones. A Rw and Rwa overlap method is also demonstrated in confirmation of the method.

Introduction

New technology logging tools for the formation evaluation of exploratory wells, such as Nuclear Magnetic Resonance and Multiple-channel induction, has created a need to make their interpretation easily available. Western Atlas and the West Region Exploration Department of YPF SA have designed a new log presentation by combining different logs and adding "Quick-Look" processing. This helps in identifying hydrocarbons zones and facilitates the decision making process at the wellsite The reward is doubled:

- save in well completion costs and

- reduce the risk of bypassing productive zones.
Permeability from Well Logs of an Eolian and Fluvial Formation. Entre Lomas Block, Neuquen Basin, Argentina
Authors: Benito J.I. , Montagna A.O. , Wouterlood C.J.
Published: December 2007

Accurate permeability values, required in reservoir characterization, can be derived from logs using adequate petrophysical constants with their cut-off for different lithologies and environments, specially in those fields where good relationship between porosity and permeability exists. This methodology has been successfully applied in Tordillo Formation in Entre Lomas Block, in the ENE of the Neuquen Basin, Argentina.

Tordillo Formation, of 150 m thick section, is composed of sandstone and conglomerate units interbedded with siltstones layers deposited under braided fluvial and eolian environments. Taking advantage of the logs that most of the wells at any field have, many authors, mentioned in Reference 1, have given various techniques to estimate permeability. In the majority of the cases, the evaluations show erratics behaviours.

To improve the quality of the results, core data (capillary pressures, formation factor, porosity, etc.) have been used to determine the irreducible water saturation and the different petrophysical constants in order to calibrate the permeability equation. This adjusted expression yields results which have good correlation degree with those permeabilities derived from direct and indirect measurements as core data and well test analysis.

Later, numerical simulation studies have confirmed the validity of the described method.

Introduction

Study Area. Entre Lomas Block is located at the northeast of the Neuquen Basin. Oil was discovered in 1960. The Block, with an extension of 742.5 Km2, is divided by the Neuquen and Rio Negro interprovince border (Figure 1).

The stratigraphic column (Figure 2), present in Entre Lomas Block, shows the three main productive Formations: Punta Rosada (Aalenian-Bajocian), Tordillo (Kimmeridgian), the most prolific, and Quintuco-Vaca Muerta (Tithonian-Valanginian). Tordillo Formation appears productive in two main structures, Charco Bayo (CB) and Piedras Blancas (PB). They are under exploitation since the late 60's. A secondary recovery project that started in 1975 was performed in several stages. The original pattern was inverted seven spot, but later a half of those patterns have been changed into a staggered line drive system.

Both structures are not completely developed neither close to the water contact nor inside the field. The future locations should be chosen carefully due to the risk of finding a thin pay zone or hitting a secondary water bank.

Up to day almost 330 wells of the CB and PB structures have been drilled. Almost 270 were located with a well spacing of 88 acres. The rest of the wells can be defined as interspaced. Currently 205 are still on production, 80 are injectors.

By December 1996, the oil production rate of Tordillo Formation was 1,180 m3/d and the cumulative produced volume was 17,234 Mm3.
Formation Evaluation With Logs In The Deep Anadarko Basin
Authors: Peebler R.P.
Published: December 2007

This paper was prepared for the Deep Drilling and Production Symposium of the Society of Petroleum Engineers of AIME, to be held in Amarillo, Tex., Sept. 11–12, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

The complex lithology and the nature of the "measurement environment" make the "Deep -Anadarko Basin" one of the more difficult log evaluation problems facing the industry anywhere today. The paper describes methods for solving this problem.

The measurement environment is discussed in terms of perturbing effects on log readings. This includes a statement of what measurements are possible under various conditions of hole size, temperature, pressure, salinity, and gasified mud. The particular case of salt saturated drilling fluid, high temperatures and deep invasion is given special attention.

Application of the evaluation systems in use today to the Deep Anadarko Basin is discussed. This includes Quick-Look interpretation techniques employing the Dual Laterolog and/or the Compensated Neutron/Formation Density (Compensated) as well as the Advanced Computation System - CORIBAND.

The paper concludes that the evaluation systems available are capable of a highly consistent and reliable evaluation of this complex reservoir. However, as pointed out, cases exist where the measurements required for the evaluation system are sometimes deficient due to the harshness of the "measurement environment."

Introduction

Evaluation of the deep Anadarko Basin offers a difficult challenge: The Basin includes complex lithologies, high resistivities, variable shaliness, and both primary and secondary porosity. To find true porosity and determine lithology, both the porosity and determine lithology, both the Compensated Neutron and Formation Density logs are needed. If secondary porosity is to be identified, a Sonic log is also required. The use of these logs also offers avenues to gas identification, estimation of shaliness and advanced computer processing.

A variety of drilling fluids are in use, including fresh mud, salt muds, salt brines, and inverted emulsion muds.
Hamaca: Solution Gas Drive Recovery in a Heavy Oil Reservoir, Experimental Results
Authors: Treinen R. J. , Ring W. W. , Spence A. P. , de Mirabal M. , Huerta M.
Published: December 2007

Oil recovery greater than 10% OOIP in the Hamaca area of Venezuela's Orinoco heavy oil belt has been forecast based on field observations and experimental data.1,2 This high recovery can be modeled using drastically different mechanisms: a high critical gas saturation; a very low critical gas saturation combined with a large effective drainage area; or the formation of finely divided free gas that flows with its associated liquid. This paper details an experimental evaluation of solution gas drive recovery and the production mechanism present in the Hamaca region of the Orinoco heavy oil belt.

Critical gas saturation data were collected using a sand pack filled with live Hamaca crude oil at reservoir conditions. The sand pack was 2 inches in diameter, 12 inches in length, and had a pore volume of 200 cc. Pressure depletion of the pore fluids was achieved with a sequence of small fluid expansions. A flow rate was picked to mimic the fluid flux at 1000 ft from a vertical well. Pore fluids were allowed to reach phase equilibrium after every expansion. Pore and produced fluid compressibility, produced fluid gas oil ratio and CT scanner derived gas saturations were measured after every expansion.

As the pressure declined the produced fluid exhibited a decreasing GOR and a compressibility consistent with liquid while the sand pack fluids showed an increasing compressibility consistent with increasing gas saturation. Free gas production was observed by a simultaneous jump in the produced fluid GOR and compressibility and was also observed with CT scanner images. The CT scanner derived critical gas saturation was found to be 8.3 PV%. A material balance calculation indicated a critical gas saturation of 10.2 PV%.

CT scanner images showed free gas accumulating in gas rich regions which were generally surrounded by oil with little free gas. Gas saturation in gas rich regions could reach 70 PV%. As gas saturation increased, gas rich regions began to connect until a network of high gas saturation traversed the length of the sand pack. CT scanner images taken at the beginning of free gas flow were used to visualize this connected network of high gas saturation.

The experimental data show that the high solution gas drive recovery is the result of a high critical gas saturation. The data show that the high recovery is not associated to low critical gas saturation and a large drainage area. No finely divided foam or appreciable associated gas was observed in the produced fluid.

When a 9 PV% critical gas was combined with oil compressibility and the expected formation compressibility, field performance predictions yielded a 12.5% OOIP oil recovery estimate.
Optimal Design and Planning for Laboratory Corefloods
Authors: dos Santos Renato L.A. , Bedrikovetsky P. , Holleben Carlos R.
Published: December 2007

In the design of routine coreflood tests, it arises a number of limitations for physical similarity (capillary number, end effect) and for laboratory equipment restrictions (accuracy of measurements, pump capacities, etc.), which restrict the test plan. In the current paper these restrictions are presented in terms of dimensionless parameters. These limitations result in a system of inequalities for core length and displacement velocity. For the cases of waterflood and EOR, the sets of significant parameters have been determined. The code written in a simple spreadsheet allows to determine minimum core length which provides fulfillment of above mentioned conditions and to calculate the optimal displacement velocity.

Introduction

Relative phase permeabilities are the basic functions which determine the efficiency of the waterflooding. Hence, the accurate laboratory determination of these functions from the routine coreflood procedure is an important problem of the waterflood design and planning.

Well developed and widely spread routine unsteady state method for determination the relative permeability assumes that capillary forces are neglected, i.e. so called conditions for large scale approximation are fulfilled. This could be achieved for long cores. The major limitation for this study is the core length, which usually does not exceed 13–20 cm. The problem of designing the routine coreflood test is to find out whether the conditions of classical methods are fulfilled for a given core, and to find the displacement velocity which provides the minimum error.

Number of works propose different methods for determination of the relative permeability honouring capillary pressure. The approximate methods are reliable for limited intervals of rock and fluid parameters. Optimisation methods lead to ill-posed inverse problems. Therefore, the JBN method is still used routinely.

In the current paper we concentrate on conditions of validity for routine JBN method and on parameters for laboratory test which provide this validity.

Criteria for physical similarity for waterflooding (limited capillary number, minimum capillary-viscous ratio and delay number) were used in the work of Bedrikovetsky et alii for planning the coreflood test based on Barenblatt's non-equilibrium theory. Alternate criteria for large scale approximation are minimum sizes of stabilized capillary zone and of end effect zone which also provide minimum core length and optimal velocity.

Nevertheless, during routine tests arise operational limitations like accuracy of measurements, capacity of pumps, etc. which are to be considered with the test design.

In the current work we concentrate on design of the coreflood honouring both physical similarity criteria and operational limitations. Simple software in a spreadsheet is developed to determine minimum core length and optimal displacement velocity for waterflood and EOR.
Analysis of Flow in Spatially Correlated Systems by Applying the Percolation Theory
Authors: Salomao M.C.
Published: December 2007

The percolation theory provides universal laws which are helpful to describe geometrical and physical characteristics of a system. The present work verifies the influence of spatial correlation on percolation parameters and, as a consequence, on fluids flow properties. Monte Carlo simulation of stochastic processes was applied in association with the percolation theory of finitesized lattices, and with the invasion percolation model. In the first part, the sensibility of percolation parameters (as the percolation threshold and the connectivity function) to autocorrelation function in Gaussian process, and to attraction parameter in Markovian processes is observed. In the second part, the invasion percolation model is applied to inspect the behavior of fluids flow in pore-grain systems. The results show that spatial correlation plays an important role in the description of porous stems, strongly affecting the flow properties, the values of fluids recovery and residual saturations.

Introduction

The percolation theory, as termed by Broadbent and Hammersley in their classical work of 1957, was conceived to describe the morphology and nature of fluids transport in disordered media. It has undergone great progress, in several fields of science (physics, biology, chemistry), and has the distinguished quality to provide universal laws that describe the geometry and general properties of the tem. An important aspect concerning the percolation processes is the fact that its dynamics is ruled by the medium and not by the fluid, having outstanding importance the geometric and statistic characteristics of this medium.

Assuming initially a square grid in which the cells are conductor of energy or insulate, let us suppose that a fraction p of them is conductor and randomly located at the grid, that is, each cell has a probability p of being conductor, independent of any other cell. Supposing that the energy propagation occurs only through conductor cells having a common face, the energy imposed to the top line may be transmitted to the bottom line or not; the passage of energy between opposite bounds is called percolation. ft can be noted that the greater the proportion of conductor cells, the greater the probability of occurring percolation; in addition, percolation only occurs above a certain proportion, called critical concentration or percolation threshold - pc. This model, in which the lattice is formed of connected cells, is denominated site percolation. A similar ease, in which all the cells are active, but the connections between them, called passages or bonds, may be active or not, is denominated bond percolation. These models are used to represent binary systems as permeable rock and shale, pore-grain systems, wetting fluid and non-wetting fluid, positive and negative spins, etc.
Combined Artificial Lift System - An Innovative Approach
Authors: Saputelli L.
Published: December 2007

Artificial lift methods such as gas lift and electric submersible pump offer great advantages in improving vertical flow performance and oil well productivity. Each method has its own limitations and disadvantages as well.

A combined artificial lift system is proposed to improve oil well productivity and to overcome as many of the disadvantages as possible. The objective is to minimize total energy requirements to maximize production.

Major benefits of combined artificial lift are to reduce initial capital and operation costs, by optimizing compression gas and electricity requirements and to reduce abandonment pressure leading to higher recovery. Main applications areas include new and developing fields mature fields, fields with low gas supply, low PI and deep wells.

Introduction

Millions of barrels of oil remain virtually inaccessible in reservoirs because of the limitation on the abandonment pressures. Hopefully the new advent of technology in artificial lift mechanism will enable the production engineers to recover a part of the oil left behind by lowering the abandonment pressures.

Reservoir pressure declines with time due to net extraction of fluids. With the declining pressure, the operating artificial lift mechanism eventually fails to lift the wellbore fluids to the surface and consequently, the well dies. Therefore, it becomes necessary to switch to a more efficient lifting technology that can operate at lower pressures and thereby extend the well life. When all economic lifting methods have been tested in accordance with the availability of surface facilities, the reservoir is said to have reached the optimum abandonment pressure.

Inflow performance (Figure 1) is proportional to drawdown pressure (P), i.e., the difference between reservoir static pressure and the flowing bottom-hole pressure (Pwf).
Updated Field Case Studies on Application and Performance of Bottom Drive Progressing Cavity Pumps
Authors: Haworth Cameron G.
Published: December 2007

Until recently, the Progressing Cavity Submergible Pumping System (PCSPS) has only been used where a conventional top drive system was prone to frequent failure. However, recent studies on PCSPS applications have provided ample evidence that the PCSPS is an excellent alternative for many slant, deviated and horizontal progressing cavity pumping applications. The PCSPS with its proven longevity may also become a viable and economic method for vertical well progressive cavity pumping applications.

Evaluation of the retrieved downhole drive system from these applications has shown the units, in most cases, were in excellent condition and with minor tune-up and testing the equipment was again ready for service.

Introduction

The progressing cavity pump made its first appearance in the Petroleum Industry in the 1970's by producing heavy crude oil with high concentrations of sand and solids. Since that time the application of the progressing cavity pump has expanded to include medium to light grade oil production as well as water source wells. In many cases the progressing cavity pump is the only viable method of lift in certain types of oil bearing reservoirs. This broader spectrum of applications and the relatively low capital cost and high system efficiency has significantly increased the use of progressing cavity pumps around the world. The increased use in a wide variety of applications has brought to light some of the deficiencies in the top drive progressing cavity pumping system. This paper will cover several field case studies illustrating the advantages of the bottom drive progressing cavity pumping system over the conventional top drive system.

Bottom Drive Progressing Cavity Pumping System - The PCSPS Progressing Cavity Submergible Pumping System (PCSPS) is a system consisting of a submergible motor rotating the progressing cavity pump from below, thereby eliminating the long failure prone sucker rod drive shaft.

There are several operational considerations in the development of the PCSPS.
The Telford Field Development
Authors: Jewell Stephen , Ward Christopher
Published: December 2007

The Telford field is an oil and gas accumulation located in the UK sector of the North Sea. As a subsea tieback to existing production infrastructure this development might at first appear to be typical of many similar projects completed in recent years. However, the Telford story is interesting for two reasons. Firstly, the individual reservoirs making up the development are very different in nature and would be uneconomic on a stand alone basis. Secondly, the rapid development of the area to ensure maximum project value was a critical success factor. Achieving this hinged on the speedy resolution of a cross boundary equity issue which subsequently led to the formation of a joint operator sub-surface team for the reservoir development.

This paper focuses on the sub-surface aspects of the development and how the application of state-of-the-art technology coupled with a phased approach has led to the development of what was previously considered to be a marginal field. The rapid commercial agreement reached to enable the development to proceed and the success of the joint sub-surface team are considered. The paper aims to demonstrate that even small, complex accumulations can be developed successfully by an experienced operator determined to overcome traditional barriers to success.

Introduction

The Telford Field is located in Blocks 15/21a and 15/22 of the United Kingdom Continental Shelf. The area is located approximately 170 km northeast of Aberdeen, 9 km south of the Scott Platform. The Telford field is an elongate structure measuring 11 km by 1 km. It comprises four separate accumulations trapped within structural compartments of late Jurassic Piper Formation sandstones. The reservoir is sealed and sourced by the overlying Kimmeridge Clay formation which is also Late Jurassic in age. The various accumulations have been named Central, West and East Telford and Marmion. Total STOIIP prior to development was estimated to be between 107 and 126 mmstb with a corresponding GIIP of 181 to 211 bcf. The location of the field and each accumulation is described in Fig. 1.

Full exploitation of the Telford area will ultimately be achieved by a two phase development. This will consist of the tie-back of sub-sea completed wells via manifolds and flowlines to the Scott Platform. The phasing of the development is to allow for processing restrictions at Scott and to permit further appraisal of the field. Phase 1 is now complete and has seen the development of the core area consisting of Central Telford and Marmion. Phase 2 will involve the appraisal and development of the West and East Telford areas and of the West Marmion prospect.

This paper describes the first phase of the development and the initial appraisal of West Telford. The second phase of the Telford development is expected to begin in 1998.
Stimulation Program in High Permeability Oil Sands - Case Study
Authors: Davidson B. M. , Franco V. H. , Gonzalez S. , Robinson B. M.
Published: December 2007

Argosy International operates several oil fields in southern Colombia, South America that were experiencing a significant decline in productivity. A study of numerous wells in these fields revealed the decrease in productivity was due to increasing skin damage near the wellbore. Lab tests and field observations indicated that fines migration and asphaltine deposition were the most likely causes. Several types of treatments were performed during a pilot program to overcome the near wellbore damage, including acid treatments, xylene treatments, clay stabilizer treatments, high pressure gas fracturing and hydraulic fracturing. The hydraulic fracture treatments provided the best results and justified the economics of implementing a major stimulation program. A total of 17 fracture treatments have been performed on 10 different wells. As a result, the productivity of the wells has increased by 2–3 fold, the total field production has increased substantially. As of February 1997 an additional 2,700,000 bbls of oil has been produced as a result of the fracturing program. The implementation of quality control and real-time analysis using a 3-Dimensional fracture model has allowed for on-site revisions of the fracture treatments. The amounts of pad and proppant volumes were optimized to achieve a proppant pack off in the fracture at the end of the flush.
Use of External Parallelization to Improve History Matching
Authors: Schiozer D.J. , Sousa S.H.G.
Published: December 2007

Although automatic history matching is a difficult task due to production and reservoir characterization uncertainties, it is possible to develop methodologies and computer programs to improve the matching process.

An important tool in the development of this type of methodology is the external parallelization of reservoir simulators where simulations can be divided into a network of workstations, reducing significantly the total time of the process, especially for some network types.

This work shows some applications of the use of external parallelization applied to the history matching process. Due to the high the number of simulations which are necessary, a routine was created to distribute the runs over a network of workstation. The software PVM (Parallel Virtual Machine) was used and an algorithm was developed to make the best use the target network.

There is a great number of applications of this technique in reservoir simulation. Every application which requires several simulations can be improved with external parallelization. A routine to manage all simulations is very important to make the best use of a network.

Introduction

The modeling of hydrocarbon reservoirs can be so complex that many times the only possible and reliable technique to be used is making adjustments in the reservoir model until numerical simulators results match observed production data. Such a process, known as history matching, is usually very slow due to the high number of variables and degree of uncertainty and heterogeneity of reservoir parameters.

The complexity of the process leads most people to believe that automatic history matching is neither viable nor possible. For this reason, "trial and error" procedures based on personal experience is a common practice.

However, recent hardware and software developments can be used to accelerate a history matching process, making it faster and more reliable than "trial and error" procedures. Although it is not yet possible to have the whole process automatic, the automation of several steps is both possible and necessary.

This work deals with one important tool which can be used to accelerate history matching which is external parallelization, i.e., the use of a software to efficiently distribute simulation runs that can be performed in parallel in an existing network of workstations. The software developed in this work (MPS - Multiple Parallel Simulations) is based on PVM (Parallel Virtual Machine) libraries.

The applications cited here are specifically applied to history matching but they can be used to any process that requires several simulation runs. The ultimate application of MPS is to manage all simulations on a network.
The Progressing Cavity Pump: A Cost-Effective Multiphase Transfer Solution
Authors: Mirza Kamran Z.
Published: December 2007

Based on the progressing cavity pump principle, Robbins & Myers, Inc. has developed a surface transfer system for transporting all multiphase fluids produced from the well simultaneously through a single pipeline to a central processing station. It is capable of handling a wide range of flow regimes and gas fractions up to 99%. The system's approach provides optimum pump performance under continuously changing conditions at the wellhead.

The data presented in this paper was recorded at an actual field location in Alberta, Canada. A special multiphase progressing cavity pump system was installed at the satellite and resulted in reducing the wellhead pressure. At the same time, a significant increase in overall fluid production was recorded, including a substantial increase in the oil output.

This case study describes the problem and the solution, and explains the benefits of the progressing cavity multiphase pump system. A comparative analysis is presented for the production rates before and after the installation of the multiphase pumping system. An economic analysis is also presented to demonstrate the cost-effective advantages of the progressing cavity multi-phase pump system, which offers lower capital, installation and operating costs, and an attractive return on investment.

Introduction

Progressing cavity (PC) technology and its application in a multitude of industries has evolved for well over half a century. Likewise, the concept of multiphase fluid transfer is not new nor is it considered revolutionary. However, it is a process that has inspired the development of innovative, cost-effective alternatives to traditional, ineffective methods of fluid transfer. At the heart of the multiphase fluid transfer system is a redesigned, field-proven progressing cavity pump. This paper examines the technology behind the progressing cavity pump, its capabilities and applications as they apply to multiphase fluid transfer in lowering operating and repair costs, as well as extending well production and well production life. Actual field test results are shown to confirm the benefits of multiphase pumping and illustrate its potential for the oil and gas industry.
Running, Setting and Cementing Casing in Deep Wells
Authors: DeGeer Don W.
Published: December 2007

This paper was prepared for the 1972 Deep Drilling Symposium of the Society of petroleum Engineers of AIME to be held in Amarillo, Tex., Sept. 11–12, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

A typical casing program for the latest wells drilled in the Washita Creek Field would be 20", 13 3/8" 9 5/8", 7" liner, and a tapered 7" × 4 1/2" production string.

An earlier casing program for the Washita Creek wells was 2411, 1611, 11 3/4", 9 5/8", 7" liner and a 7" tie-back production string. production string. For the latest program, included is a description of each casing job, the equipment used, and the method used to run and cement each string.

Some of the troubles which were encountered and the remedies that were effective are described.

Introduction

This paper is based on Phillips Petroleum Company's experience in the Petroleum Company's experience in the Gageby Creek and Washita Creek fields in the Texas Panhandle. As the Washita Creek wells were the latest drilled and the deepest, the data given will be from this field.

A typical well for the area was drilled and cased with the following program: program: Hole Casing Casing Size Depth Size (In.) (Ft.) (In.) Remarks

24 400 20 Conductor. Cement to surface to protectfresh water sands.

17 1/2 4,200 13 3/8 Surface. Set on or in top of Brown Dolomite. Case off unconsolidated formations prior to drilling loss circulation sections.

12 1/4 13,900 9 5/8 Intermediate. Set in top of Morrow Shale. Case off low pressure formations before drilling the high pressure Morrow.
Drilling a Record Mississippi Wildcat
Authors: Klementich E. F.
Published: December 2007

This paper discusses drilling the She Murphy USA 22-7, a 23,455-foot Jurassic wildcat located in Wayne County, Mississippi. This well is extraordinary from several standpoints:

- a new state depth record was reached;

- two very severe and nearly instantaneous kicks with a flowing capacity in excess of 70 BPM were successfully brought under control;

- 3,551 feet of 4 1/8" slim hole was drilled with ultrahigh mud weights, 19.2 to 20.3 ppg, in an underbalanced condition, and

- a flow test of a high pressure (8,300 psi shut-in) salt water zone was conducted.

This report presents a chronological history of the Shell-Murphy USA 22-7 and discusses the drilling techniques that were successfully used to bring the well to total depth. In addition, the author's thoughts will be presented on the source of the ultrahigh pressures and other phenomena peculiar to this pressures and other phenomena peculiar to this well.

Introduction

In late 1969 there were two areas in Mississippi where wells deeper than 20,000 feet were being drilled, in the central part of the state around the Jackson Dome and in southeast Mississippi in a piercement salt wall province (Fig. 1). In both areas the objectives were the Smackover and Norphlet formations (Jurassic age). To date one of the most difficult wells to drill was the Shell-Murphy USA 22-7, a Wayne County, Mississippi wildcat located in the salt wall area.

Deep, high pressure sour gas wells are in themselves unique but do not individually deserve special reports. General drilling and completion practices for such wells were outlined in a previous reported However, this well is extraordinary from several standpoints:

- a new state depth record, 23,455', was reached;

- two severe and nearly instantaneous kicks (3,700 and 2,400 psi shut-in drill pipe pressure) with a flowing capacity greater than 70 pressure) with a flowing capacity greater than 70 BPM were successfully brought under control;

- 3,551' of 4 1/8" hole was drilled with ultrahigh mud weights (19.2 to 20.3 ppg) in an under-balanced condition; and

- a flow test of a high pressure zone was conducted.

This paper presents a chronological history of the USA 22-7 and outlines the drilling techniques that were successfully used to bring the well to total depth. In addition, various thoughts are presented on the possible source of the ultrahigh pressures and other phenomena peculiar to this well. peculiar to this well.
Deliverability Enhancement and Well Testing of Two Gas Storage Fields in Mt. Simon Formation – Case History
Authors: Azari Mehdi , Guoynes John , Soliman Mohamed , Fugate Mike
Published: December 2007

A pilot study was conducted in two aquifer gas storage fields completed in Mt. Simon formation located in North Central Illinois to select candidate wells for deliverability improvements.

Eleven wells were selected to evaluate their responses to several different stimulation technique. High pressure perforation washing. Re-perforating with high density charges, extreme overbalance surging (EOBS)1-3, selective injection packer acidizing (SIP), and coiled tubing acid injection were all used to reduce the near-wellbore pressure losses

Each well was tested before and after every treatment to select treatment types and to compare the improvement techniques. The results and the responses of the wells to these treatments will be documented for further deliverability improvements in these two fields.

Significant improvements were achieved with EOBS and SIP acidizing techniques. The techniques and the procedures used to improve the deliverability in these two gas storage fields are presented in this paper. The procedure and the well test analyses used in the four wells detailed in this paper represent the three main treatment techniques of EOBS, SIP acidizing, and coiled tubing acidizing.