bluuebunny/crossref_metadata_2025 huggingface dataset:
A Flexible Contracting Strategy Has Streamlined International Drilling Operations: A Case History
Authors: Day J. D. , Carter E. C. , Longmire R. J.
Published: December 2007

The primary goal of a drilling operation is to minimize the time and expense required to drill wells while operating in a safe, prudent manner. Minimizing drilling costs decreases the development cost per barrel threshold necessary to exploit hydrocarbon reserves. Decreasing the elapsed time between acquiring a prospect and evaluating the potential reservoir positively impacts the return on an operator's investment In order to reduce operating costs and to expedite potential production from its international prospects, Marathon Oil Company's Worldwide Drilling Group (WWD) has adopted a flexible contracting strategy. This strategy involves an appraisal of each project's objectives and potential along with the company's existing infrastructure in the area to determine the best type of contract to be employed.

This paper reviews the various contract types including conventional, incentive-based, and lump sum operating rate daywork, limited and full turnkey drilling and integrated service agreements. The contracting philosophies which were utilized offshore New Zealand, Sakhalin Island, Tunisia, Ireland, China, and Gabon, and onshore Argentina and Egypt are described. Cost normalizations, risk premium/management local tendering difficulties, and time constraints are discussed along with their effect on which contract mechanism was selected.

This paper summarizes Marathon's strategy of utilizing contracts which best fit the overall project objectives. Streamlining operations through innovative contract philosophy and economizing on local infrastructure, required personnel, and initial capital expenditures have significantly minimized drilling costs. Selected use of turnkey and limited turnkey contracts have assisted in managing risk in areas where Marathon has had limited experience. Finally, this flexible approach to selecting contract type has enhanced the company's ability to pursue high risk and marginal projects.
The SQI: A Service Quality Index to Measure and Reward Individual Companies Within a Well Construction Partnership
Authors: Sharpe P.J. , Jutten J.J.
Published: December 2007

While partnerships need to be driven by global targets, the success of a partnership is intimately linked to the quality of each partners contribution. The absence of a tool to measure the contribution of each partner led to the development of the Service Quality Index (SQI). Tangible results are described, with examples of how improvement opportunities have been identified and resulted in prioritised investment. The SQI system has enabled individual companies to continuously improve, resulting in the partnership as a whole meeting its targets and delivering wells of increasing value.

Introduction

The Nederlandse Aardolie Maatschappij B.V. (NAM) is the largest operator in the Netherlands, running a fleet of five heavy land rigs, three workover rigs and four offshore rigs. NAM had developed its operations in a traditional manner until 1993 when, in a drive to enable development of prospects that had previously been unattractive, a series of partnerships were formed. The PRO-STAR land drilling well construction partnership was formed in 1994 between NAM, Deutag, Baker Hughes INTEQ, Dowell and BPB Wireline Services.

The Partnership

One of the main foundation stones of the partnership is the Win-Win principle. As such although the partnership has a 30% well cost reduction target, cost reduction has not been achieved by squeezing the partners profit margins. Performance with respect to cost reduction targets serves as the basis for a global profit share arrangement, whereby 50% of cost savings beyond agreed targets are returned to the contractor partners. Cost over-runs are borne by the Operator with no penalties imposed. Industry benchmarking has also been undertaken to measure the performance of the team as a whole.

Each partner contributes to the success or failure of the team, and performance improvement requires each partner to strive for excellence within their own activities. The partnership performance is measured in its totality via comparison to a historical cost model. Prior to the implementation of the Service Quality Index (SQI), no mechanism existed to measure the contribution of individual Companies within the Partnership.

All radical changes result in some degree of scepticism and opposition. The restructuring of NAM's well engineering business was no different. Change has to be sold, and selling change requires hard facts and figures to combat perceptions. In the early days of the partnership the assurances of management were treated with suspicion. Even cost performance improvements and profit share payments were attributed to the vagaries of the historical cost model. Something was missing to aid in demonstrating performance improvement throughout all levels of the organisation.

P. 513^
A Deeper Understanding of Heat Checking, an Old but Frequently Overlooked Failure Mechanism, of Downhole Drilling Components
Authors: Choi H. J.
Published: December 2007

Heat checking, a quench cracking phenomena, is an old but often overlooked failure mechanism of downhole drilling assemblies such as drill collars, drill pipes, heavy weight drill pipes, cross-overs, drilling jars, hardfacings, etc. Heat checking occurs when low alloy steels which have been healed by friction against formation (side load) is rapidly quenched by cool drilling fluids. The susceptibility of drilling assemblies to heat checking increases as drilling practice becomes aggressive. The time has come to properly define heat checking and to develop an in-depth understanding of this phenomena. It has often been misquoted, misunderstood and overlooked among drillers. Heat checking promotes macro- and micro-cracks, mictrostructural changes, hardness changes, iron-oxide formation, or structural changes. To mitigate heat checking-related failure, more in-depth understanding is thus required from metallurgical engineering, mud engineering and environmentally-assisted cracking standpoints. In short, heat checking is a more man one-dimensional problem of quench cracking or drilling operations but involves multi-disciplines.
Horizontal Underbalanced Drilling of Gas Wells with Coiled Tubing Challenges and Experiences
Authors: Cox R. , Li J. , Lupick G.
Published: December 2007

Coiled tubing drilling technology is gaining popularity and momentum as a significant and reliable method of drilling horizontal underbalanced wells, and is quickly moving into new frontiers. To this point, most efforts in the Western Canadian Basin have been focused towards sweet oil reservoirs in the 900 – 1300 metre (3000 – 4300 feet) true vertical depth range, however there is an ever-increasing interest in gas-producing formations. Figure 1 shows a composite vertical section of the horizontal or directional underbalanced wells drilled with coiled tubing in Canada, and also highlights the aforementioned trend towards oil over gas. Significant design challenges on both conventional and coiled tubing drilling operations are imposed when attempting to drill these formations underbalanced.

Coiled tubing is an ideal technology for underbalanced drilling due to its absence of drillstring connections resulting in continuous underbalanced capabilities, as well as its suitability for sour well drilling and live well intervention without surface releases of reservoir gas. Through the use of pressure deployment procedures it is possible to complete the drilling operation without need to kill the well, thereby maintaining underbalanced conditions right through to the production phase. The use of coiled tubing also provides the means for continuous wireline communication with downhole steering, logging and pressure recording devices.

Coiled tubing drilling rigs currently exist in several different forms and setups, but generally consist of a drilling coil, injector to feed the tubing into or out of the well, BOP system for well control and return fluid path, and a control cab and power unit. The coiled tubing drilling equipment used to drill the case studies presented later in this paper consisted of either 60.3mm or 73.0mm (2.375 or 2.875 inch) coiled tubing and injector with a hydraulic power unit with control cabin and accumulator. A coiled tubing hybrid mast unit and substructure complete with V-door, catwalk and pipe racks was used. Pumping equipment included a fluid pumper capable of liquid rates of 0.10-1.5 m3/min (0.6 – 10 barrels per minute), nitrogen pumper capable of 10-120 m3/min (350 – 4250 standard cubic feet per minute), and a nitrogen bulk storage unit of 50,000 m3 (1.8 million standard cubic feet) capacity. When drilling sour gas formations, a chemical injection pump for corrosion inhibition may be used.
Reservoir Engineering Applications to Control Excess Water and Gas Production
Authors: Azari Mehdi , Soliman Mohamed , Gazi Naz
Published: December 2007

Conformance control is defined as any action taken to improve the injection or production profile of a well. It encompasses procedures that enhance recovery efficiency, improve wellbore/casing integrity, and satisfy environmental regulations. Unwanted fluid production in oil- and gas-producing wells is a factor that limits the productive life of a well. The cost of produced water disposal in an environmentally non-threatening fashion may be a major concern for many producers. In addition, control of excess water and gas production improves profitability by allowing additional oil to be produced.

Application of water control technology assists in minimizing water production and maintaining the oil flow rate of a well. Reservoir engineering and well testing play essential roles in characterizing and detecting the problems associated with producing formations and wells.

This paper starts with problem identification in both producing and injection wells. It then covers the behavior and control of several types of reservoirs with different drive mechanisms. Applications of reservoir simulation and well testing in the control of water and gas coning, determination of the amount and the best appropriate treatment application, effect of formation layering, control of relative permeability to water, application of permeability blocking agents, water channeling, secondary recovery, viscous fingering, and polymer flooding are detailed in this paper. In addition several techniques to evaluate the overall success of a conformance control procedure are presented.

Introduction

The purpose of this paper is to identify reservoirs associated with excessive gas or water production and to recommend the proper remediation. Conformance control begins with identifying the source of problem. This requires a thorough investigation of all aspects of well and reservoir parameters. The following is a list of some of the parameters required for identification of reservoir performance problems.–Reservoir permeability and porosity–Relative permeability to oil, water, and gas–Connate water and irreducible oil and gas saturations–Net formation height–Recovery mechanism–Reservoir dip–Oil, gas, and water production rates versus time–Original water-oil contact–Length of time before water production began–Location of all perforations–Fraction of the productive interval completed–Identification of fluid entry locations and the type of fluid entering wellbore (production logging)–Location and continuity of any shale layers–Identification of cement to casing bonding (bond log)

This review is divided into the following four main sections: P. 413
Strategies for Fasttracking Exploration and Development of the Elli/Tau Prospects
Authors: Barstad B. E. , Akers T. J.
Published: December 2007

Esso Norge AS and its partner Enterprise Oil Norge Ltd aggressively pursued fasttracking strategies to allow flexibility and control of the drilling rig in an increasingly tight Mobile Offshore Drilling Unit (MODU) market. In 1995, Esso contracted the semi-submersible drilling rig Vildkat Explorer for four firm and five optional wells, primarily to explore the Greater Balder Area. The longer term contract with the Vildkat Explorer fulfilled several objectives. It ensured the availability of a rig in a tightening rig market; the rig could be farmed out as required giving time to incorporate lessons learned into the planning of the next well to be drilled; and it ensured continuity with the drilling contractor. Esso was also able to drill multiple appraisal locations from a single surface location as needed to assess the size, extent, and quality of the reservoirs.

Upon the start of the drilling program, it was realized that the planned wells presented neither particularly technically challenging or very long wells. The opportunity to save time and money by drilling these wells in an innovative, creative and dramatically different way than the ordinary was seen as remote. Instead, a determined effort was made to exploit the small opportunities for saving time and cost through the mobilization and operation of the rig.

Well 25/8-8S, discovering the "Tau" Field in September 1995, will serve as an example of the operational steps implemented in the pursuit of efficiency.

The commercial development of the "Tau" and nearby "Elli" discoveries, now renamed the Jotun Field, is currently being pursued by Esso and its partners. The selected development concept, with a wellhead platform as opposed to a subsea development, is largely influenced by the current and anticipated future tight MODU market. The manifestation of this tight market is not only in the initial capital drilling costs but also in the subsequent well intervention costs and service unit availability during the life of the field. The decision eliminates the uncertainty of development drilling costs created by the MODU market and allows a greater variety of options for future well interventions.

A project team is currently working towards filing a "Plan for Development and Operation" (PDO) for the Jotun Field early 1997, targeting first oil in second quarter 1999, only some 5 years after the initial discovery.
Analyzing a Multi-Lateral Well Failure in the East Wilmington Field of California
Authors: Brister A. Ray
Published: December 2007

Introduction

As the industry pursues optimum cost drilling techniques, more focus is being applied to multi-lateral technology. The presently available literature invariably focuses on the cost and efficiency benefits of drilling multi-lateral wells. What is missing in the media, however, are the benefits associated with publication of the negative aspects or costly failures of higher-technology multiple-lateral projects that require a mechanical tie-back or pressure seal at the junction of the laterals (i.e. Class 3 or 4 type multi-lateral wells, respectively). This paper is a case study of a Class 4 multilateral well attempted by Thums Long Beach Company in the East Wilmington Field of California. To date, this case study represents the only detailed analysis of an unsuccessful attempt to drill a Class 4 multi-lateral well. Starting with a field and well profile, this case study explores Well B743A in the Long Beach Unit of the East Wilmington Field of California. The discussion progresses from the original proposal through the drilling and completion of the lower lateral to the drilling of the upper lateral, and then to the plugging and abandonment both laterals. Finally, the analysis provides an examination of six critical problem areas encountered during the drilling of Well B743A: hole cleaning, cementing and junction stability, whipstock orientation, tubular size, re-entry, and risk management. These are areas that are problematic for most operators and contractors struggling with multi-lateral technology, especially the drilling of Class 3 or Class 4 multi-lateral wells.

Field and Well Profile

The Long Beach Unit of the East Wilmington Oil Field is located just offshore at the southwestern extension of the Los Angeles Basin of California (Fig. 1).

The field produces from three major zones, the Ranger, Terminal, and Union Pacific-Ford zones (Fig. 2). Individual sand units are continuous and can be correlated over the Long Beach Unit and beyond. The structural setting is an asymmetrical northwest to southeasterly trending, faulted anticline.

P. 169^
New Analytic Techniques for Petroleum Fluid Characterization Using Molar Refraction
Authors: Touba Hassan , Mansoori G. Ali , Sarem Amir M. Sam
Published: December 2007

Molar refraction of pure hydrocarbons, petroleum fractions, and other compounds present in petroleum are shown to represent well the asymmetry of such fluids. Molar refraction is used to correlate density, parachor, and other properties of hydrocarbons with an accuracy that was not achieved before. Various calculations are made to demonstrate the accuracy of the proposed new analytic techniques for various reservoir fluids characterizing properties. Molar refraction characterizes the pure as well as the complex hydrocarbon mixtures and can be measured directly and accurately. It is shown that molar refraction is a more appropriate property to correlate the asymmetry of hydrocarbon fractions than the other existing methods. Plenty of the molar refraction data have been reported in the API Data Book for all the hydrocarbons and non-hydrocarbon compounds making it possible to extend the applicability of the proposed technique to high molecular weight ranges.

Introduction

The molar refraction which can be measured in the laboratory is a direct measure of the London dispersion forces which affect the PVT behavior of pure fluids and mixtures. The molar refraction, R, is defined by the following equation: (1)

where n is the index of refraction and v is the molar volume. The molar refraction of a substance can also be expressed in terms of the polarizability by using Clausius-Mosotti equation.

(2)

where N0 is the Avogadro number and is the polarizability. If a substance has a permanent dipole moment, then the polarizability is the sum of two terms:

(3)

where 0 is the distortion polarizability related to the displacement of the electronic cloud of a molecule with no permanent dipole moment in an electrical field and is the orientation polarizability which arises from the tendency of the permanent dipole moment to be oriented in the direction of the applied field. The orientation polarizability, , is related to the dipole moment and is inversely proportional to the absolute temperature.

(4)

In this equation, k is Boltzmann constant and T is the absolute temperature.

Substituting Eqns. (3) and (4) into Eq. (2), we get the following equation for the molar refraction.

(5)

We may assume methane as a reference substance for which the dipole moment is zero (= 0), and obtain the molar refraction of other substances with respect to methane.

P. 507^
Large Scale Application of Acid Stimulation - Tulare Zone, South Belridge Field, Kern County California
Authors: Dean Gregory D. , Giunta Rick L. , Baggs Donald T.
Published: December 2007

Extreme near well-bore acid stimulations have successfully helped to maintain production in the Tulare Zone of the South Belridge Field. An economical alternative to redrilling wells was a driving force behind this program. Since 1991 over 600 of these treatments have been performed while monitoring and employing quality improvements and system optimization. After the initial successful treatments were performed, the following treatments were continuously monitored and databased. Due to the lack of a good statistical number of wells, many early attempts at optimizing the treatments were tried with little engineering justification. Subsequently, these attempts fell short of truly optimizing the treatments. In 1993 a full scale engineering study was implemented to help understand the mechanism for success. The study included the construction of a slotted liner acidizing test apparatus, detailed analysis of the crude, core analysis, and construction of a treatment database. Details of the study are shown in the paper along with the resulting three year production data.

Reservoir Geology

The South Belridge Field is located in the southwestern San Joaquin Valley, about 40 miles west of Bakersfield, CA. The northwest to southeast trending anticline structure stretches nearly 9 miles across the San Joaquin Valley Floor and is just under 2 miles across at the widest point. Structural dip is approximately 4 degrees to the southwest. Production occurs from several different horizons which vary in continuity across the field. The reservoirs range in geologic age from Miocene to Pleistocene. The trap dimensions are controlled by both the overall structure and stratigraphy of the individual sand bodies. The Tulare can be divided into several flow units separated by clay boundaries. These are the Upper Tulare (Zones A, B, and C) and the Lower Tulare (Zones D and E). Acid stimulation treatments detailed in this study were all performed in the Pleistocene Tulare formation in sections 3 and 4 which are located in the southern portion of the field. The stimulation program occurred over a 3 year period from 1993 to 1995 and consisted of over 550 acid treatments.

Reservoir Description

The Tulare is a heavy oil reservoir with unconsolidated, loose and grain supported sands. Reservoir properties are listed in Table 1. Primary production occurred in the Tulare from 1917 to 1963 at which time steamflooding was introduced. Steamflooding today is still the primary method of enhanced recovery in the South Belridge Field. Peak production of 50,000 BOPD was achieved in 1995 from over 600 wells.

Well Description

Wells are typically completed on 5 acre spacing. All of the wells stimulated are completed with an openhole gravel pack and 16–30 or 12–20 mesh sand. P. 619^
Field Test of Produced Water Treatment With Polymer Modified Bentonite
Authors: Doyle D.H. , Brown A.B.
Published: December 2007

The combination of ET Ventures' ET #1 and granular activated carbon consistently and effectively removed hydrocarbons from Tensleep formation produced water in a 24-hour test at Teapot Dome oil field. Specific findings are that ET #1:–Reduced Total Petroleum Hydrocarbon (EPA Method 418.1) to non-detectable levels.–Reduced Oil and Grease (EPA Method 413.2) to non-detectable levels.–Reduced soluble hydrocarbons: Benzene, Ethylbenzene Toluene, and Xylene (BTEX-EPA method 8020) to barely detectable levels.

BTEX was below detectable limits after the combination of ET #1 and granular activated carbon.

Introduction

This report describes the results of a test conducted at the Rocky Mountain Oilfield Testing Center (RMOTC) of a product manufactured and marketed by ET Ventures, L.L.C. This product, ET #1, is designed to adsorb hydrocarbons from wastewater. The test conducted at RMOTC was intended to document the ability of ET #1 to:–Adsorb a relatively large quantity of hydrocarbons from oilfield produced waters carrying a free oil sheen.–Tolerate the wide variations in hydrocarbon concentrations typical of oilfield operations.–Adsorb soluble hydrocarbons in the BTEX family under these same circumstances.

A 24-hour test was designed in which produced water from the Tensleep formation was flowed through a three-stage treatment system composed of two stages containing ET #1 and a final polishing stage containing granular activated carbon (GAC).

Product Description

ET #1 is a product generally referred to as a polymer modified bentonite or an organoclay. This group of materials is manufactured by binding an amine polymer onto bentonite clay and drying it in a granular form. The polymer binds to the bentonite's ionic surfaces and converts the clay from a hydratable form to an oil-wet, hydrocarbon adsorbent material. Other clays are also used for the manufacture of organoclay, depending on the application and location of mineral deposits.

Organoclay is commonly used in the upstream sector of the petroleum industry for removing hydrocarbons from refinery process water, but it has seen little use in petroleum production. Many other industries also use it, including shipping and dockside servicing, carwashes, and others dealing with an oily wastewater stream.

Organoclays have also been tested for treating ground and surface water for other organic chemicals such as PCBs and pesticides.

Present and Future Constraints on Oilfield Produced Water. Oilfield produced water is an important source of surface water in the arid western U.S. The discharge of produced water is permitted under the National Pollutant Discharge Elimination System (NPDES), which may be administered by the U.S. E.P.A. or by a state program. In addition, other state and federal programs come into play to generally prohibit the presence of a free oil sheen or staining of the shoreline of surface impoundments. Netting may also be required over surface impoundments in order to protect migratory birds from hydrocarbon contamination.

P. 137^
Current Practices in the Tip Screenout Fracturing of High Permeability Reservoirs in the Gulf of Mexico
Authors: Morales R.H. , Norman W.D. , Price P.A. , Stewart B.R. , Works-Minter A.M. , Ali Syed A.
Published: December 2007

This paper summarizes practical experiences gained in several aspects related to the tip screenout fracturing of high permeability formations in the Gulf of Mexico (GOM). In particular the paper discusses current practices related to the:evaluation of mechanical properties of the reservoir;selection of the fluid and proppant;design and analysis of the calibration treatment;design of the main fracturing treatment;placement of the treatment;post fracturing analysis, andperforation of the reservoir.

P. 147
Six Months in the Arctic
Authors: Wassel Gordon C.
Published: December 2007

This paper will present a brief outline and description of the Gas Arctic Systems Study Group's program in the Alaska and Canadian Arctic. Gas Arctic Systems is proposing a 48-inch gas pipeline from Prudhoe Bay, Alaska through a portion of Alaska, into Canadian Yukon territories, Northwest territories, and Alberta Province where the line would connect to existing Alberta Gas Trunk Line facilities to the Canadian-U. S. border or other Canadian pipeline facilities. A project of this magnitude requires extensive-research and planning before implementation.

Introduction

For about two years, Northern Natural Gas Company has been a member of a consortium of six major U. S. and Canadian companies. This consortium, consisting of four U. S. companies: Northern Natural Gas Company; Texas Eastern Transmission Corporation; Columbia Gas Systems, Inc.; Pacific Lighting; and two Canadian companies, Alberta Gas Trunk Line; Canadian National Railway Company; is actively studying and developing a gas pipeline project to bring Alaska and Northern Canadian Gas to markets in project to bring Alaska and Northern Canadian Gas to markets in Canada and the lower 48 states. These activities have resulted in the formation of the Gas Arctic Systems Study Group who have undertaken development, research and feasibility studies resulting in expenditures of seven million dollars in 1971, with a similar level of studies planned for 1972.
Operating Curves for Single and Multistage Reciprocating Compressor
Authors: Sparta David P. , Kuss Ronald H.
Published: December 2007

This paper discusses a computer program that develops operating curves for single and multi-stage reciprocating compressors. The operating curves, which show horsepower requirements as a function of pressure, are used as an aid in operating compressors.

The series-parallel flow of the gas in a staged unit sets up interrelationships between the stages and also between the cylinders of each stage. At constant horsepower, small suction pressure changes cause large changes in the discharge pressure. The interrelationships and the suction pressure sensitivity cause convergence problems in modeling staged compressors. The convergence problem becomes more pronounced as the number of stages increases.

The first part of the paper discusses a technique that solves the convergence problems in modeling staged units. The technique is discussed along with the results of a computer program written to test the modeling techniques. program written to test the modeling techniques. The second part of the paper discusses how this test model is built into a production computer program that develops and plots operating curves. This program automatically produces the curves using the compressor's data (bore, stroke, clearance, etc.)

Text

Northern Natural Gas Co. uses operating curves as an aid in operating reciprocating compressors. These curves show horsepower and volume as a function of suction and discharge pressure for a given cylinder clearance; a pressure for a given cylinder clearance; a separate plot is used each clearance configuration. Figs. 1 and 2 show typical curves for single and multistage compressors. The operating curves are generated by a compressor model.

There are convergence problems in modeling staged compressors. Fig. 3 is a schematic of a typical staged unit. The series-parallel flow of the gas sets up interrelationships between the stages and also between the cylinders of each stage. The flow distribution, for example, to a stage's cylinders may change with pressure because of different clearances. As noted in Fig. 2, small suction pressure changes at constant horsepower cause large changes in the discharge pressure. The interrelationships and pressure sensitivity cause convergence problems pressure sensitivity cause convergence problems in modeling staged compressors.

A modeling technique was developed and tested that solves the convergence problem. An ideal compressor handling an ideal gas is assumed in describing this model. The actual test model used modified equations that compensate for real compressor and gas behavior, such as compressibility, valve leakage, etc.
A Modified Muskat Analysis of a Reservoir Containing Fluids with Composition Dependent Properties
Authors: Rowe A. M. , Comer A. G.
Published: December 2007

A new method is presented that can be used to predict molal specific volumes of equilibrium states as a function of reduced pressure. The reduced pressure for pressure. The reduced pressure for multicomponent systems, in turn, is defined as the ratio of the operating pressure divided by the convergence pressure as determined by the Critical Composition Method. This technique essentially extends the law of corresponding states to include multicomponent systems that exist in a two-phase region of phase space. Published experimental data is used to justify Published experimental data is used to justify this extension.

This method was first programmed into a phase routine to determine how accurately it phase routine to determine how accurately it would predict experimentally determined liquid saturations obtained by constant volume expansion of a volatile reservoir fluid. Experimental and predicted results were found to be in very close agreement.

After this approach was verified, this technique was then incorporated into a Modified Muskat analysis to predict recovery from a volatile oil reservoir.

Introduction

The U.S. is currently faced with an energy shortage that has resulted in deep-well exploratory drilling (in excess of 30,000 ft.). At these greater depths, reservoirs are more likely to contain volatile fluids since the reservoir pressure and temperature are higher than normally encountered at more shallow depths. Therefore, due to the nature of these fluids, the ability to calculate reservoir performance and thus predict recoverable performance and thus predict recoverable reserves will require the accurate determination of their phase compositions and accurate predictions of the densities of equilibrium liquid predictions of the densities of equilibrium liquid and vapor phases. The phase composition calculation is based on mass conservation, while an accurate phase-density calculation is necessary for the conservation of pore volume.

This paper presents a method for predicting volatile oil recovery that incorporates predicting volatile oil recovery that incorporates both of these conservation principles by utilizing the thermodynamic properties correlated as a function of convergence pressure, temperature, and pressure. One of the potential advantages of such an approach lies in applications to non-equilibrium displacement of a liquid by a gas phase.
Changing Wellbore Storage Effects In Gas Well Testing
Authors: Al-Haddad S. , LeFlore M. , Lacy T.
Published: December 2007

Extended wellbore storage can be mistakenly interpreted as a reservoir response in gas well testing with surface shut-in. This interpretation usually results in false values for permeability, skin and reservoir size and shape.

This paper investigates gas cooling effects on pressure transient testing with surface shut-in in gas wells. This study was prompted by the observation, that in gas wells, many of the buildup tests obtained with surface shut-in exhibited complex reservoir model behavior with relatively low skin. These models, such as narrow channels or multiple nearby boundaries, often did not agree with the actual reservoir system thus resulting in incorrect estimations of well and reservoir parameters. This in turn may result in missed opportunities to enhance well productivity and to develop the field further.

The results presented in this paper are based on well test simulation and field data from five wells in three different fields offshore Louisiana. This work demonstrates the effect of gas cooling. in combination with gas compression. on the pressure derivative curve. Knowledge of the expected pressure derivative shape. and duration, will improve the design of buildup tests that will allow enough time for the actual reservoir response to be observed. This will result in a reliable reservoir model and correct estimation of permeability and skin factor.

Introduction

To minimize cost and operational risk, many well tests are performed with a surface shut-in with a bottom-hole pressure measurement, rather than bottom-hole shut-in and pressure measurement. However, a surface shut-in includes many factors that can effect the bottom-hole pressure value. The combined effect of these factors is usually referred to as the wellbore storage effect and period. A surface shut-in allows fluid flow from the tested formation into the wellbore for a long period of time, depending on the permeability and thickness of the formation, and the wellbore volume. Moreover, the multiphase composition of wellbore fluids results in an upward movement of the gas phase relative to the liquid phase. These changes in fluid pressure and temperature, may also result in liquid drop out or evaporation (phase changes). These factors will result in significant changes in the wellbore fluids' compressibility, density, and composition.

Lee presented procedures to design well tests including after-flow conditions. He used Agarwal, Al-Hussainy, Ramey type curve empirical fit which predict the end of wellbore storage duration. In terms of equivalent shut-in times, Ate, the duration of after-flow is given by the following equation:

Hegeman, Hallford, and Joseph presented a model for analyzing increasing or decreasing wellbore storage. Their model is based on modification and extension of Fair's approach. Fair modified Van Everdingen and Hurst equation by adding a term to account for the pressure change caused by phase redistribution:

The changing storage pressure function has the following properties:

(2a)

(2b)

(2c)

P. 77^
Formation Testing While Underbalanced Drilling
Authors: Kardolus C. B. , van Kruijsdijk C. P. J. W.
Published: December 2007

Underbalanced drilling is more and more considered an option for the drilling of low-pressured reservoirs and a method to prevent formation damage, especially in the case of horizontal wells. The production rate during drilling depends on reservoir characteristics and the degree of undcrbalancc. As such it carries similar information as a pressure transient test. However, the boundary conditions for this particular situation are distinctly more complex. Underbalanced drilling results in boundary conditions which vary with time. Measurements of these boundary conditions downhole would make it possible to de-couple the wellbore physics from the formation. The significance of such measurements can be shown by simulating the formation response to the time-varying boundary conditions. In order to do this, a (semi-)analytical model has been developed. The model describes the dynamic process of producing while lengthening the wellbore. It connects pressure with rate of penetration and can be used to predict production rates as a result. In addition we developed an analytical procedure that allows direct interpretation of the rate data, yielding estimates of reservoir parameters. A Boundary Element Model (BEM) has been developed to model the rate transient response for time varying well parameters (underbalanced drilling).
Natural Gas Supply and Demand Problems
Authors: Hatamian H.
Published: December 2007

World natural gas consumption quadrupled over the 30 years from 1966 to 1996, and today it provides 22% of the total world energy demand. The security of natural gas supply is paramount and rests with the suppliers and the consumers. This paper gives an overview of world natural gas supply and demand and examines the main supply problems. The most important non predictable variables in natural gas supply are the current world-wide gas price and the current political stability, particularly in regions with high reserves. Other important considerations are the cost of development / processing and transport of the natural gas to the market: this itself can be difficult to maintain confidence if pipelines pass through areas of political instability. Another problem is that many countries lack the infrastructure and the capital needs for the effective development of their natural gas industry. Unlike oil, the cost of transportation of natural gas is very high and at present surprisingly only about 16% of the total world production is traded internationally.
How to Minimize the Flow Rate Error in a Complex Gas Network
Authors: da Mata J. D.
Published: December 2007

Petrobras owns several natural gas networks, involving production, compression, process, transport and distribution systems of this important energetic source in Brazil. This paper presents the principles of a computational system developed for the gas measuring management and for the accounting balance closure of the entire gas network. The system calculates for each measuring point an uncertainty and a quality value, based on the gas features, the equipment and the variables involved in the flow rate calculation. A mathematical programming model closes the balance, minimizing the weighed sum of the adjustments of the flow rate values, for all the gas network, allowing to locate those meters which present the biggest measurement errors.
Laboratory Evaluation of the Effect of Treating Chemicals on Scale Inhibitor Performance
Authors: Kirk Joseph W. , Sin Romony E.
Published: December 2007

In producing systems several chemicals may be injected into a common line without regard to effect of one inhibitor upon the other. This paper examines the effect of various commonly used treating chemicals upon the efficiency of four commonly used scale inhibitors.

Introduction

The generally accepted practice of chemical treatment in the oilfield is basically "use what ever materials are necessary to get the job done." Unfortunately little if any thought is given to the possible interactions between the different species of treating materials and the result of that interaction.

This paper demonstrates some of the possible results of incompatibility between scale inhibitors and other chemical treating compounds normally employed in water handling systems in the oil field.

Description of the Experiments

Testing was carried out on the tube blocking type apparatus using a 0.02" PEEK tubing one meter in length as the test coil. The coil was immersed in a constant temperature water bath at 150 F. The brines were pumped through the test coil using peristaltic type tubing pumps.

Flow through the test coil was maintained at a constant 5.0 milliliters per brine, for a 10.0 milliliter per minute total flow rate. The pressure increase on the test coil was measured with a pressure transducer and a computer program to assimilate the data and display it in graphical form.

The scale Inhibitor under evaluation was added to the anion brine in all tests. Other chemicals were added to the cation brine.

All evaluations were carried out using the synthetic brine whose composition is shown in Table 1.

Commercial finished compound blends rather than the pure base inhibitor were used in all of the testing.

When working with completely water soluble materials, the required amount of compound to be evaluated was added to the cation brine. As previously noted the scale inhibitor was added to the anion brine.

With the oil soluble materials a slightly different approach was used. An amount of hydrocarbon equal to the amount of brine was mixed with the brine. (Making a 50/50-kerosene/brine mixture). In the testing depolarized kerosene was used as the hydrocarbon.

Kerosene and brine were added to a separatory funnel to which the required amount of scale inhibitor and other test material was also added. The separatory funnel was shaken vigorously by hand for one minute to assure intimate mixing. The fluids were then allowed to stand undisturbed for a period of one hour to allow the layers to separate. Water was then drawn off and used for the actual test procedure. The presence and amount of any emulsion layer was noted and recorded.

This hydrocarbon extraction procedure was used only with the oil soluble materials.

P. 501^
Sand Erosion Control by Using Chokes in Series in Deep, High Pressure Oil Producing Wells in North of Monagas, Venezuela
Authors: Ali J.
Published: December 2007

A design of chokes in series has been carried out in order to minimize sand erosion in choke boxes and beams. A multiphase flow simulation program was developed to determine the size of the choke orifices and the sequence of installation. Previous field experience determined beneficial effect of using chokes coated in their internal area from end to end with tungsten carbide.

Failures in choke boxes and beams have been occurring in about 59 out of the 222 production strings in the North of Monagas area in Venezuela to the present time. In fact, 139 failures due to sand erosion occurred during 1996 causing repair costs of about $339000.

The installation of a design consisting of chokes in series at the well head, drastically minimizes sand erosion, reducing production losses, oil leaks, maintenance costs and unsafe operations.

The multiphase flow simulation program based design resulted in the installation of three chokes in series protecting them from sand erosion in the two wells evaluated. During five (5) months, the pre-established period of time for analysis, well No. 1 kept producing continuously. Visual inspection confirmed that no sand erosion had occurred in any of the chokes.

Introduction

High gas and oil rates associated to sand production with high well head pressures passing through one choke box with conventional material usually causes erosion of the beam and its choke box; the severity of the erosion process may deteriorate them completely, giving place to leaks. Sand production erodes the internal parts of a well head including wing valves, tees, subsurface safety valves, choke boxes and beams affecting the well safety system and production operations. These accessories are inspected periodically, and frequently, they have to be repaired or replaced. This type of failure causes deferred production and dedication of production crews to correct erosion problems affecting operational costs.

Research has been carried out on the erosive processes in materials with and without the presence of sand. In the oil industry, an API formula has been developed to predict the limit velocity for flow of fluids, above which an erosive process, in non corrosive environments and without the presence of solid particles, can be initiated. Deffenbaugh showed results on the erosion velocity for carbon steels excluding its application for flow restrictions as chokes. Likewise, Deffenbaugh proposed a formula to predict erosion velocity in the presence of sand. Sontvedt reported the limit velocities for erosion for carbon steels in the absence of corrosive fluids based upon studies of materials for chokes, and also for other special materials resistant to erosion. P. 987^
The impact of reservoir characterization on oil exploitation from the Namorado Sandstone, Albacora Field, Campos Basin, Offshore Brazil
Authors: Barroso A. S. , Bruhn C. H. L. , Lopes M. R. F. , Beer R. , Sombra C. L. , Romeu R. K. , Mihaguti M. , Neto G. S.
Published: December 2007

PRAVAP 2 (Petrobras’ strategic project for reservoir characterization) aims mainly technology acquisition and development in reservoir characterization. The project is based on a multidisciplinary approach, and the synergism between operational and research teams. New technologies are put together with others already consolidated. This paper presents some of the developments acquired and how they impact the field development and oil production.
Gas Zones Detection Using the Dual-Spaced Neutron Tool Responses
Authors: Quintero Luis F. , Bassiouni Zaki
Published: December 2007

Gas zones are routinely identified with the neutron-density crossover. Many a times however, this crossover is not present or misleading because the lithology used in the tool's calibration is not representative of the formation of interest. Also the crossover could be completely obliterated by the shale effect. Furthermore, in cases where the well has been cased before logging only the neutron tool can be run.

We have developed a simple algorithm that determines three apparent neutron porosities. The porosities derived from the raw counts of the dual-spaced neutron tool have three different radii of investigation. All three neutron porosities read the true porosity in water-bearing zones. In gas-bearing zones the mud filtrate invasion profile will cause the three apparent neutron porosities to be different. The resulting neutron porosities crossover can be used in a way similar to the neutron-density response in detecting the presence of gas.

The validity of the algorithm has been tested using a numerical model and field examples.

Introduction

The detection of gas zones using the density-neutron crossover relies on the assumption that the lithology selected to calibrate the tool is representative of the lithology of the formation of interest. The absence of this condition leads to a complex interpretation problem as the neutron-density combination must be used to both determine the lithology and to detect the presence of gas.

The shaliness of the formation can also obliterate the neutron-density crossover, since shale and gas have the opposite effect on these logging tools. The presence of gas may be overlooked in cases where the shale effect offsets the gas effect.

In highly rugose boreholes, the reading of the density tool is much more affected than that of the compensated neutron. In these conditions, the crossover pattern may be misleading. Also, being a padded device, the density tool cannot be run through casing. In these scenarios the only porosity indicator is the dual-spaced neutron sonde.