bluuebunny/crossref_metadata_2025 huggingface dataset:
Performance of the Twofreds CO2 Injection Project
Authors: Kirkpatrick R. K. , Flanders W. A. , DePauw R. M.
Published: December 2007

The Twofreds (Delaware) Field, located in Loving, Reeves, and Ward Counties, Texas, is operated by HNG Fossil Fuels Company and has been under continuous CO2 injection since February, 1974. The field was nearing its economic limit under waterflooding when the CO2 project was initiated. In the 11 years since tertiary injection began, total field oil production has been increased from 170 bbl/D (27.0 m3/d) to over 920 bbl/D (146 m3/d). Tertiary oil recovery to date has been over 2.5 × 106 barrels (0.397 × 106 m3) of oil. This mature, commercial-scale project offers a unique opportunity for the evaluation of long-term effects of practical CO2 operations. The field currently produces 923 bbl/D (147 m3/d) of oil at a gas-oil ratio of 3,240 cu ft/bbl (577 m3/m3), 1,755 bbl/D (279 m3/d) of water, and has cumulatively produced 11.2 × 106 barrels (1.78 × 106 m3) of oil and 16.9 × 106 barrels (2.69 × 106 m3) of water since discovery in 1957.

The Twofreds (Delaware) Field produced under primary recovery from January, 1957 until January, 1963 when it became the first unitized water injection project in the Delaware Basin.1 In February, 1974, Twofreds became the first field-scale tertiary CO2 injection project in a sandstone formation in Texas. The majority of the field (98.6%) had been purchased for tertiary purposes by HNG Fossil Fuels Company, Murphy Oil USA, Inc. and RGS (Ritchie, Gerard & Stanberry). Atlantic Richfield Company (ARCO), with the remaining 1.4%, was the only original owner that elected to maintain their interest in the field, and joined in the operation. Carbon dioxide for the Twofreds Field is obtained from Intratex

Gas Company's MiVida Gas Processing Plant located 9.64 (15.5 km) miles from the field. Exhaust gas injection was initiated in October, 1980 to supplement the CO2 injection. This additional injection made possible the expansion of the project to include the entire field.
Performance Forecasting and Economic Evaluation of a Deeply Buried Coalbed Methane Reservoir in the San Juan Basin
Authors: Jones A. H. , Bush D. D. , Kelkar S. M. , Ahmed U. , Bell G. J.
Published: December 2007

A program was undertaken by Terra Tek, Inc. of Salt Lake City, Utah, in cooperation with the Tiffany Gas Company of Farmington, New Mexico, to evaluate the recovery of hydrocarbon gas from the Fruitland Formation coal within the San Juan Basin in Southwest Colorado. The target coal was distributed through six seams at depths between 3062 and 3112 feet; and net coal thickness was 25 feet.

Well tests were performed to determine total permeability for the fully saturated reservoir, skin factor and initial reservoir pressure. Core tests on coal samples determined the original adsorbed gas content, the adsorption isotherms, porosity, capillary pressure, and relative permeabilities. These parameters were used as input data to a computer code to history match the water/gas production for both the underreamed and stimulated well. Predicted productions were used in economic analysis. After the well was underreamed, gas production was uneconomic. Following hydraulic fracture stimulation, economic gas flow was achieved.
A Leading Index of Drilling Activity
Authors: Buell R. S. , Maurer R. A.
Published: December 2007

A five-component composite leading index of rotary drilling activity for the last thirty-six years is presented. Economic and technical justification are presented showing why each particular component of the leading index should be expected to lead drilling activity. The leading index has consistently led drilling cycle peaks and troughs by seven months over the thirty-six years studied.
Statistical Method for the Determination of Zone Boundaries Using Well Log Data
Authors: Dharmawardhana H. P. K. , Keller G. V.
Published: December 2007

The proposed method provides a physically meaningful solution to the division of well logs into naturally occurring zones using the variability of well log parameters. The zone boundaries are defined in such a way that the variance of the given parameters within zones is minimized and the variance of the said parameters between zones is maximized. The above criterion is in accordance with the definition of the zone and zone boundaries where homogeneity is preserved within zone and is interrupted at the boundaries. In Gill's (1970) approach, a prior knowledge of the number of zones is needed to establish the zone and zone boundaries, where as present work does not call for the same. In other words, the zone and zone boundaries are controlled automatically by the preset termination conditions. Pickett and Souder's (1972) approach consists of searching for extrema in the derivative of the amplitude with respect to depth which resulted in picking the inflection points as boundaries. Since the points of inflection are not the absolute zone boundaries, this technique over estimated the number of zones. The present work has overcome this difficulty by looking at the variability of the well log parameters.
Cement Evaluation in the Gulf of Thailand
Authors: Perry Conrad , Henry Ken
Published: December 2007

Union Oil Company of Thailand, a subsidiary of Unocal Corporation, has developed major natural gas and condensate reserves in the Gulf of Thailand, approximately 130 miles south of Bangkok. Union, as operator on behalf of its co-ventures Southeast Asia Petroleum Exploration Company and Mitsui Oil Exploration Company Limited, has developed four offshore fields which are currently capable of producing 450 million cubic feet of gas and 20,000 barrels of condensate per day. Natural gas from these fields supply 30 percent of Thailand's energy requirements.

The Gulf of Thailand provides a challenging environment for primary cementing and cement evaluation. Most wells are directionally drilled, deviated up to 60°, with an average total depth of 10,500', and have a bottom hole temperature of 320° F or greater. Oil base mud is used routinely for drilling, and requires consideration when planning the cementing operation. Evaluation of the cementing operation is critical, as zones to be perforated are always in close proximity to water, either as gas water contacts or permeable water sands.

In order to obtain a good evaluation of cement quality and distribution, the Cement Evaluation Tool (CET) has been used on over 30 wells to complement and improve the information obtained from the conventional Cement Bond Log (CBL). This paper shows examples of both CBL and CET on several wells in the Gulf of Thailand. Recently, the CET and CBL have been recorded simultaneously on one trip in the well, enabling a special presentation which displays the data on one film.

These practical examples show how gas migration and channelling can be identified, in addition to the effects of casing centralization. The accuracy and resolution of the CET acoustic caliper for use in casing inspection is shown. Examples show the importance of the total circumferential cement distribution data provided by the CET in determination of zone isolation. The lack of microannulus effect on the CET is presented, along with recommendations on how to obtain good quality log data.
Well Test Interpretation in Faulted Reservoirs
Authors: Kabir C S , Kucuk F , Gomez-Angulo J
Published: December 2007

Well test analysis for a well adjacent to a no-flow boundary or a fault presents a significant interpretation challenge. The interpretation difficulty stems from the fact that early-time skin- and storage-dominated period and the subsequent boundary-dominated period obscure the middle-time data. Consequently, conventional semilog or type-curve analyses are difficult to perform. Because of dominating influence of inner and outer boundary conditions, an appropriate interpretation model is necessary for the estimation of reservoir parameters.

This work presents analytical models to analyze data for a well located at various distances from a fault, having wellbore storage and skin effects. The models are cast in the familiar graphical format with dimensionless variables – known as type curves. These type curves exhibit a different character than those of Gringarten et al for an infinite-acting reservoir. Both constant wellbore storage and exponential decline storage cases are considered in this work. The new type curves offer the potential for reservoir parameter estimation of permeability, skin and wellbore storage coefficient. Additionally, the distance to a fault could be estimated.

Application of the new type curves, using an automated matching technique, is demonstrated through field examples. Data from several wells located in highly faulted off-shore gas and oil reservoirs in south-east Asia are used for the purpose. Difficulty of analyzing the data using conventional semilog analysis is also shown in this work. This study further shows that only the very early-time data (<10 minutes) that are affected by the wellbore storage effect are amenable to pressure-rate-time or convolution analysis, obeying the radial-cylindrical flow model.
Hydrocarbon Miscible Flood: Field Facility Design
Authors: Verma K. , Giesbrecht P.
Published: December 2007

This paper summarizes the design, selection, installation and operational aspects of hydrocarbon miscible flood field facilities. Field facilities discussed include solvent and gas, fresh and produced water injection pipelines, double block and bleed system, and injection wellhead. The piping design for high pressure injection system is described to explain the economics of selection of high grade pipe.

In a cyclic miscible injection system, hydrate formation is the main operational problem. This paper presents the rationale for selection of the unique design of double block and bleed system. The simplicity of this design has reduced operating costs. The techniques involved in switching the cycles from solvent injection to water and vice versa are described.

Field facilities pressure testing has always been an outstanding question, especially for miscible injection lines. Water, gas and methanol as test media are evaluated.
ESP Cable Insulation: Selection for Performance
Authors: Schultz R. E. , MacKenzie B. T. , Marefat K.
Published: December 2007

Electrical cable for submersible pumping systems must be of high quality and reliability. Because of this, careful selection must be made of materials which will optimize performance in a wet electrically stressed environment. Polypropylene is the insulation used in lower temperature cables which is a major part of this cable market. Over the past eight years a major engineering effort has been placed on the evaluation of polypropylene resins and their wet electrical properties. Test methods were selected which distinguish between resins based on long term electrical stability. Properties of most extrusion grade resins available together with some experimental resins will be reviewed. Dielectric breakdown, insulation resistance, dielectric constant and power factor all versus time will be presented. The data will demonstrate the need for long term evaluations prior to the selection of a polypropylene insulation for ESP cable applications.
Jackup Drilling Unit, Substructure Skid-Off System for Fixed Platforms
Authors: Cochran T. J.
Published: December 2007

One of the perennial problems for operators of fixed offshore production platforms has been the consider-expense involved in the drilling of additional wells or working over wells that are out of the thirty-five to forty-five foot reach of "standard" cantilever jackup rigs.

These jobs usually require the use of self contained platform drilling rigs.

The installation of a platform rig becomes quite expensive when the costs for deck barges, tugs, derrick barges and "rig up/rig down" time are all considered. In fact, the costs are great enough that many operators will forego or delay the drilling of an additional well or performing well maintenance because of the initial expenses involved in using a platform rig.
Conducting Effective Drills on MODU's
Authors: Taft D. G. , Carroll K. L. , Major R. A. , Marucci T. F.
Published: December 2007

Several of the recent MODU accident investigations have identified a need to improve emergency drills on mobile rigs. Conducting effective drills can be an important part of a training program to teach crews to deal with emergency situations. The authors have identified several key elements that appear to contribute to effective drills based on their observation of drills on many (about 40) MODUs. These elements are planning, conducting and reviewing a drill. Management must take an active role in these areas if the onboard drills are to be effective. Planning includes selecting appropriate drill topics for fire and abandon rig drills to ensure the crew gets as much benefit as possible out of drills. This paper discusses several ways to get the crew and management actively involved in planning and reviewing the weekly fire and abandon rig drills as well as other types of emergency drills.

Almost every rig surveyed by the authors could have benefited from improved fire and abandon rig drills. In actual emergencies, crews that have been trained through the use of realistic drills have responded better than crews that participated in cursory drills. Improving drill performance will assist virtually any MODU crew if it should ever encounter an emergency situation.
Case History: Designing and Implementing the Operations for Drilling in the Navarin Basin, Alaskan Bering Sea
Authors: Zaremba H. B. , Millheim K. K. , Boykin G. F.
Published: December 2007

The Navarin Basin, located in the Alaskan Bering Sea, is the approximate size of the state of Louisiana. In 1984, industry paid over $681 million for leases in the Navarin Basin. Amoco Production Company, along with two other companies, decided to explore parts of the Basin in 1985 to evaluate its hydrocarbon potential.

Because of ice encroachment and associated environmental concerns, the drilling window for most of the Navarin Basin is between June and December. Amoco's strategy was to drill four to six wells starting in June (historically the time the ice regresses).

This paper presents how a systems-oriented approach was used to plan, prepare for drilling and drill five wells by mid-November 1985. This paper will show how the project objectives and environment led to the design of the "wareship concept" to support the drilling of five wells without one day being lost waiting on materials or personnel. The paper will present the first major use of Amoco's "Critical drilling Facility" concept to plan, prepare and drill the Navarin wells.

The paper will show how two drilling rigs, a wareship, tanker, four workboats, two standby boats, three helicopters, a staging base in St. Paul and a secondary support base in Dutch Harbor was controlled by the Anchorage Navarin Operations Center using the Tulsa-based Critical Drilling Facility. This was all made possible by the advanced systems technology, including a sophisticated satellite communications system and a project-oriented methodology.

This paper will present the drilling system design, implementation, and results. This includes the design and use of a potassium lime mud system and the optimization of the solids control system on each drilling machine. Included results will show that the designed drilling system achieved all drilling objectives and had a significant impact on the success of the Navarin project.
Turbine Performance in Texas Offshore Waters
Authors: Bethke M. E.
Published: December 2007

The paper highlights twenty turbine/diamond bit runs attempted recently in Texas Federal Offshore waters. The runs were attempted most often in directional wells in the Mustang Island Area. The concept has been applied in 12-1/4″, 10-5/8″, 8-1/2″, and 6-1/2″ holes. Successful results have been obtained in 10-5/8″ hole and smaller, when bit design and turbine performance is optimized with proper advance planning and area experience.

Equipment descriptions, performance, and directional results using conventional and "steerable" turbines will be reviewed. Field data will be presented and compared with offset conventional rotary bit runs.
Automation of Solids Control Systems
Authors: Ardrey W. E. , Nix G. L. , Wright J. P.
Published: December 2007

Data acquisition of well/rig data during the drilling operation has evolved from simple mechanical devices to sophisticated microprocessor driven devices. Instrumentation in the form of computerized data acquisition in the oil field have historically been used to archive drilling parameters and mud data. An indication of the current or real time condition of drilling rig parameters is generally displayed as well.

Likewise, solids control equipment found on drilling operations has been commonplace for decades. Generally the interpretation of solids equipment efficiency and operation is left to the crew or operator. The cost savings derived by proper use of solids control equipment is directly affected by its proper utilization.1,2

The scope of this paper is to illustrate that continuous surveillance of the solids control equipment by a data acquisition system can provide the most effective utilization of that equipment and thus affect (and help reduce) operational costs.
A Method of Modeling the Directional Behavior of Bottomhole Assemblies Including Those With Bent Subs and Downhole Motors
Authors: Brett J. F. , Gray J. A. , Bell R. K. , Dunbar M. E.
Published: December 2007

This paper presents an analytical model that has successfully predicted the inclination directional behavior of rotary drilling bottomhole assemblies, including assemblies that contain bent subs and downhole motors. The model has been installed as part of the Engineering Simulator for Drilling (ESD), and combines the effects on directional behavior of bottomhole assembly configuration, hole geometry, rock drillability, bit type and operating parameters such as bit hydraulics, weight-on-bit and rotary speed. The model combines previous work dealing with bottomhole assembly analysis and bit mechanics (including side-cutting behavior), with original work defining the manner by which bits directionally penetrate.

The model's computation scheme depends on a microcoded version of a finite element bottomhole assembly behavior program running on an array processor. The system provides solutions of the finite element routine every one to six seconds. Solutions are required at this frequency in order to obtain stable directional predictions at 30 times faster than real time.

The paper also shows that comparisons of the model results with field data are good in areas where formation affects are benign. Comparisons of model predictions with field results in areas of significant formation directional affects are also shown. These comparisons are useful in quantifying the effect of the dip and strike on directional behavior, and in defining areas where future work is needed.
API's Q1 and 6A Initiative: Critical Issues, From a Manufacturer's Viewpoint
Authors: Holm R. A.
Published: December 2007

This paper discusses critical issues regarding API's recent Q1 and 6A initiative. It presents a manufacturer's viewpoint on the current efforts of API, producers, and manufacturers to self-regulate design and quality in our industry. FMC encourages adoption of these practical consensus standards to better assure the safety and reliability of wellhead equipment.
A Technique for Accurate Bit Programming and Drilling Performance Optimization
Authors: Simmons E. L.
Published: December 2007

The dilemma of improving drilling rate and efficiency through the use of various optimization techniques has been the center of research and debate for many years. Both the well planner and the drilling supervisor in the field are acutely aware of the positive affects of optimized drilling on wellbore stability, the reduction in overall drilling costs, and the ultimate usefulness or production of the well.

The purpose of this paper is to illustrate a technique for synergistically coupling several optimization parameters, namely optimum hydraulics, weight on the bit and bit rotation, in order to achieve a higher degree of drilling efficiency. Formation drillability and bit type selection are brought out and integrated with a generally accepted drilling rate equation.

The result, is a technique that provides the engineer involved in well planning, with a reasonable procedure for analyzing previous offset operations and subsequently predicting, with reasonable reliability, those parameters and their magnitudes required for drilling optimization on the well he is planning. Also, by employing a modification this technique during drilling operations, the supervisor on location can constantly be "fine tuning" certain drilling parameters in order to achieve optimum drilling performance.

Fundamentally the technique involves generally accepted procedures which are merely coupled to form a synergistic system. It is simple enough to be employed in the field and yet can be thorough and detailed enough to provide the engineer in the office with the tools to perform accurate and timely well planning, based upon reliable offset well data.
Comparison of Environmentally Acceptable Materials with Diesel Oil for Drilling Mud Lubricity and Spotting Fluid Formulations
Authors: Kercheville J. D. , Hinds A. A. , Clements W. R.
Published: December 2007

A contemporary state of the arts study is presented comparing environmentally acceptable lubricants with diesel oil-based products for water based drilling fluids. Diesel oil has been the base that has served the industry so well for many years. Its use is now severely limited in many areas if not completely banned.

Functions of a lubricant in drilling mud are to lubricate the drill string and prevent differential sticking. These laboratory studies show a range of lubricity values for various drilling mud compositions which demonstrate the ability of the fluid to wet or lubricate the drill string. They also show the ability of compositions formulated as spotting fluids to release stuck pipe in lab simulated sticking situations. Different types of lab-prepared and field muds were selected for the tests.

Lubricity coefficients were used to measure the lubricating properties of the fluids. The coefficients are on a scale of 0.0 to 0.50 and most drilling fluids containing diesel oil or environmentally acceptable oils were found to vary no more than about 15 to 20%.

The studies point out that there are environmentally safe materials that can be effectively used in place of diesel oil for lubricity and spotting fluid formulations. Some of these blends disperse more readily in muds than diesel oil thereby imparting better lubricating qualities and more resistance to sticking.
The Effect of Various Polymers and Salts on Borehole and Cutting Stability in Water-Base Shale Drilling Fluids
Authors: Bol G. M.
Published: December 2007

Shale hydration tests have been carried out at confining pressures, ranging from 0 to 350 bar. The results show a high swelling pressure, without significant expansion, at high confining pressure and a large expansion without swelling pressure in the unconfined situation. It is also shown that different salts have different effects on swelling and that the effect of mud additives other than salts is negligible. The test results indicate that, for the shales tested, water structure modification and not ion exchange is principally responsible for the inhibitive effect of salts.

In addition, borehole erosion and cutting disintegration tests have been carried out. The results of these tests show a significant effect of various polymeric mud additives in terms of cohesion.
Enhanced Oil Recovery and Domestic Oil Reserves 10 Years Later
Authors: Doscher T. M. , Kostura J. A.
Published: December 2007

Domestic crude oil reserves and productive capacity were maintained during the past two decades by a mix of fortuitous events – primarily the discovery of the North Slope. Waterflooding and infill drilling succeeded in boosting national oil supplies in the past, but "new EOR" technology has not similarly succeeded and doesn't promise to do so without new invention. The current engineered fall in prices beclouds the ultimate threat to our nation's competitiveness and survival: that it will not have ready suitable alternate energy supplies when domestic oil production dries up before the turn of the century.
Application of Steam Foam in the Tia Juana Field, Venezuela: Laboratory Tests and Field Results
Authors: Keijzer P. P. M. , Muijs H. M. , Janssen-van R. Rosmalen , Teeuw D. , Pino H. , Avila J. , Rondon L.
Published: December 2007

Laboratory research on the steam-foam process as a means of reducing steam mobility in steam-injection projects indicates that steam-foam formulations, which are effective in pilot tests at low steam temperatures, are not necessarily effective at temperatures over 200°C.

However, long-chain alkylaryl sulphonates exhibit an excellent capability for reducing steam mobility at elevated temperature; furthermore, this class of surfactants is thermally stable. The performance of steam foam with these surfactants has been studied in core-flow experiments at steam-injection temperatures representative of steam operations in the Tia Juana field, Venezuela and as a function of the following parameters: surfactant molecular weight and concentration, the presence of an electrolyte, the addition of small amounts of a non-condensable gas, and steam quality. The surfactant molecular weight and concentration appear to be the main parameters for reducing steam mobility.

The laboratory research was followed by a pilot test, operated by Maraven, in the Tia Juana field, in an attempt to improve the injection profile in steam-soak wells.

The results obtained so far indicate the feasibility of:

reducing the effective steam permeability, • plugging the most depleted layers, diverting the injected steam to non-producing sands, enhancing oil production.

Based on the test results and operational conditions, the possibility of optimising steam-soak operations under Bolivar coast conditions has been established.
Field Evaluation of Interfacial Spreading Agent Using Cyclic Decline Curves
Authors: Blair C. M.
Published: December 2007

A new, organic, interfacial spreading agent was injected during at least one steaming cycle in each of a group of wells producing from Miocene sand. For all treated cycles the average rate of oil produced per unit of thermal energy injected was 67% greater than the rate predicted from cycle-to-cycle decline curves derived from steam-only cycles. In addition, the productivity of all cycles immediately following a treated cycle was 49% greater than predicted from the decline curves.

Application of Darcy's radial flow equation to the field results discloses mean increases in effective permeability to oil of more than 100% in both treated cycles and first posttreatment cycles.
A Laboratory Study of Thermal Oil Recovery Using Horizontal Wells
Authors: Joshi S. D.
Published: December 2007

This paper reports laboratory experimental results of steam-assisted gravity drainage using horizontal wells. The results were obtained for 17°API heavy oil and light refined oil. The oil steam ratios and percentage recovery of original oil in place were measured for two different well configurations, injection well completions, and shale barrier configurations. In addition, the effect of limited steam entry was also studied using a light refined oil.

The experiments were conducted in a box-shaped sand pack with five sides of steel and one side of transparent polycarbonate material to facilitate flow visualization. The results indicate that steam-assisted gravity drainage not only gives a high sweep efficiency but also gives oil steam ratios of about 0.7, indicating a high thermal efficiency for producing heavy oils. Steam-assisted gravity drainage produces heavy oil at a rate approximately three times faster than that obtained with cold oil gravity drainage.

In a uniform permeability pack, initial oil production rates using horizontal injection and production wells are higher than those obtained using a vertical injector and a horizontal producer. For a vertical injector, steam injection near the pack top gave higher and faster oil recovery than steam injection near the sand pack bottom.

In the case of shale barriers, a vertical injection and horizontal production scheme gives faster and higher oil recovery as compared to that obtained using a horizontal injection and production well scheme. A light refined oil was used to obtain limited entry results, where steam injection was confined to 5 to 10% of the length of a horizontal injector. This occurs when a vertically fractured zone intersects a horizontal injection well at 90°. The results indicate that limited entry does not affect total oil recovery. On the contrary, it enhances initial oil production rates.

The above results indicate that steam-assisted gravity drainage is an efficient method for producing heavy oils.
Determination of Minimum Miscibility Pressure Using a High-Pressure Visual Sapphire Cell
Authors: Hagen S. , Kossack C. A.
Published: December 2007

A new high pressure visual cell made of Sapphire has been developed to determine minimum dynamic miscibility pressures (MDMP). The pressure rating of this cell is 50 MPa (7250 psia) at 420 K (300°F). The minimum dynamic miscibility pressure for the system methane-propane-n-decane has been determined using this cell. The MMP is determined by visual observations of droplets of gas passing through the reservoir fluid. By multiple contact between the injected gas and the reservoir fluid the injected gas will dissolve in the reservoir fluid at the MDMP. During the experiment the volumes and compositions of the gas and liquid phases are determined. The duration of such experiment is 2–3 hours. A comparison between the experimental phase behaviour and the calculated results using the Peng-Robinson Equation of State is given. The phase characterization of the Equation of State developed from these experiments is different from the phase match characterization developed from the usual pVT experiments. Simulations of slim tube displacements using the two different characterizations are compared. The simulation of the slim-tube displacements using the phase match based on multiple contact experiments (MDMP's from the Sapphire cell) gives the best overall match of the slim-tube displacements.
The Nature of Polymer Plugging and a Wellbore Treatment To Minimize It
Authors: Treiber L. E. , Yang S. H.
Published: December 2007

This paper presents the results of a study of the factors involved in wellbore plugging by clean polymer solutions. Plugging of injection wells can have a very detrimental effect on the economics of polymer flooding. Polymer plugging was found to be a function of the following four factors: (1) volume injected per cross-sectional area, (2) core permeability, (3) hydrodynamic size of the polymer, and (4) core mineralogy and surface state.

Most polymer flood design testing does not give an indication of plugging behavior. The throughput volumes used are relatively small because the tests are generally not scaled to near wellbore conditions. A system utilizing three-cores of different diameters placed in series was used to simulate the shear conditions at the wellbore and at two locations in the near wellbore vicinity. The results suggest the polymer plugging occurs near the wellbore and that little polymer plugging exists in situ in the reservoir.

Polymer plugging in a core is partly a mechanical filtration process which is governed by the total throughput per cross-sectional area open to flow and by the sizes of the polymer molecules and the pore throats. At the same time, the core composition and the polymer-rock interaction can influence polymer plugging significantly. Selected chemicals which alter the rock surface are effective in the laboratory and are being tested for preventing polymer plugging in the field.
U.S. Drilling: Recent History, Future Expectations
Authors: Dougherty T.
Published: December 2007

Since 1981 domestic drilling activity has declined from nearly 91,500 wells to last year's total of approximately 66,000. Oversupply of natural gas and decline in oil prices, plus political threats and the takeover and restructuring binge engineered in the financial community combined to create a severe downcycle in an industry which has been traditionally cyclical.

The percentage of exploratory success and the overall development of additional supplies of oil and gas has been encouraging. However, since 1984 the U.S. has produced 120 percent of what was found in those years.

The downturn has been accompanied by a reduction in drilling and completion costs so that the ratio between even lower prices than those existing early in 1986 is still favorable on a comparative basis.

Deep drilling has been severely impacted by reduced economics, but the proved existence of opportunity in deep horizons insures that it will increase as economics improve.

Oil prices are not likely to remain below the late-1985 level for any length of time and the rise of demand against the realities of proved reserves insures that a new resurgence fo drilling will appear in the Nineties if not before.
Legal Problems Involved in Deep Drilling: Liability of Nonoperators to Third Parties
Authors: Dancy J. R. , Dancy V. A. , Pearson C. A.
Published: December 2007

Due to falling oil and gas prices and the lack of a market for the natural gas reserves usually discovered in deeper wells, oilfield suppliers are increasingly faced with the situation where they have not been paid for the materials or labor supplied in conjunction with the drilling of a well. In many instances these suppliers are filing oil and gas liens against the well, the leasehold, and the associated equipment of machinery. Where a marginal well or a dry hole has been drilled the proceeds from the foreclosure of the oil and gas lien may not satisfy the supplier's claim, and the supplier may look to the operator or non-operator to satisfy the deficiency.

In many instances, the operator is given control of the developmental activities on the leasehold under the provisions of the Standard Form A.A.P.L. Joint Operating Agreement. The operator is therefore the working interest party which actually negotiates and executes the contracts entered into with the oilfield suppliers. When a supplier's claim has not been satisfied by the operator, and the foreclosure of the oil and gas lien does not yield sufficient funds to satisfy the supplier, the supplier may look to the non-operator for payment. The issue thus presents itself as to whether a non-operator is jointly liable for debts incurred by the operator in the development of the leasehold.
A Microcomputer Approach to Drilling Engineering Problem Solving
Authors: Simpson M. A.
Published: December 2007

A "Drilling Expert System" has been developed for the microcomputer which contains over 100 drilling engineering programs and five drilling engineering "Expert Systems." The system performs many routine drilling calculations which historically have been performed on nomographs, slide rules, hand and programmable calculators and main frame computers. Additionally, seemingly exotic drilling calculations which heretofore were seldom attempted because there was no direct mathematical solution, or calculations consumed far too much time, can now quickly, accurately and unimposingly be executed with this powerful set of drilling programs.
Influence of Reservoir Depth on Enhanced Oil Recovery by CO2 Flooding
Authors: Heller J. P. , Taber J. J.
Published: December 2007

This paper describes a procedure for evaluation of an important aspect of the suitability of a reservoir for CO2 flooding. The concern addressed is whether the attainable injection pressure will be sufficient to compress the CO2 to the density required for efficient carbon dioxide flooding. The relevant factors--the required mimimum miscibility pressure (MMP), and the regional geothermal and fracture gradients--are reviewed briefly. Available data are fit to simple equations, and a formula is given which permits computation of the estimated pressure margin in CO2 floods. This is the excess of the attainable bottomhole injection pressure over the MMP, and it can be used as a figure of merit for this aspect of flood design. A reasonably high value of the pressure margin would need to be combined with other favorable factors to indicate that prospects were good for a successful CO2 flood. Since the fracture pressure increases with depth faster than the required miscibility pressure, the operating pressure margin normally increases with depth. Graphical correlations are presented to permit a quick estimate of the potential for CO2 flooding if only the reservoir depth and API gravity of the oil are known.
Fluid Dynamics of Wellbore Bottomhole Cleaning
Authors: Bizanti M. S. , Blick E. F.
Published: December 2007

Bottom-hole cleaning is a major factor affecting the rate of penetration. At the bit face, fluid flows through the nozzles, across the bottom, and back to the surface through the annulus. The resultant friction and turbulence of mixing causes a great loss of energy. Efficient bottom-hole cleaning must accomplish at least three basic functions: Washing at the mud-rock interfaceControlling "crossflow" and avoiding the regrinding of cuttingsFast-lifting of cuttings around the bit face

The objective of this laboratory student is to investigate the main parameters that control or effect bottom-hole cleaning, which is closely related to the rate of penetration and to point out how each parameter is related to bottom-hole cleaning. In this study the fluid dynamic forces on the cuttings were investigated in the vicinity of the bit.

A better understanding of bottom-hole cleaning should allow an engineer to improve the rate of penetration and minimize drilling costs per foot.
Numerical Simulation of the HASDrive Process
Authors: Hsueh L.
Published: December 2007

HASDrive (Heated Annulus Steam Drive) is an in-situ thermal process for recovering bitumen from tar sands. This paper presents the results of a numerical simulation of the HASDrive process in repeated, elongated well patterns. Results show that the process can effectively recover bitumen from tar sands. In a basic configuration, the cumulative recovery in ten years is predicted to be high, but the rate of production is low during the early steam-injection period. Several well configurations and operating procedures were investigated to accelerate the early year production. The recovery mechanisms and the sensitivity of the process to various parameters are also discussed in this paper.
Reservoir Simulation With Block Gathering
Authors: Heinemann Z. , Munka M.
Published: December 2007

For the history matching of large reservoirs it is necessary to change local parameters after successful global matching. These modifications have to be made only in a relatively small part of the reservoir, but the influence of the whole reservoir has to be taken into account, too.

The new technique "gathering" enables to combine blocks outside the focused area. This not only reduces costs but also increases the chances of success.

Comparative simulations with full and gathered block systems show extensive agreement of the results for the focused area.
A Unique Computer Simulation Model Well Drilling: Part I—The Reza Drilling Model
Authors: Reza M. R. , Alcocer C. F.
Published: December 2007

A new non-linear multidimensional, dimensionless mathematical drilling model for deep well applications, utilizing the Buckingham Pi theorem dimensional analysis technique, has been developed. The parameters included in the three equations of penetration rate, rate of bit dulling and rate of bearing wear are: the weight on bit, the rotary speed, the drilling fluid volumetric flow rate, the bit diameter, the bit nozzle diameter, the bearing diameter, the drilling fluid kinematic viscosity, the differential pressure, the temperature, and the heat transfer coefficient.

The unknown exponents and proportionality constants were determined by using the statistical regressional curve fitting method utilizing actual field data from a 21,000 foot well within the Anadarko Basin located in Caddo County, Oklahoma.

To generalize the model, a parametric study was performed for each of the exponents in each of the drilling equations. Also, a comparison between the derived model and the previously developed model which has been widely used by the industry was done.

It was concluded that the derived model yields more realistic results in terms of factors affecting the deep well drilling process than the model compared in this study. This paper is only concerned with the development of the model and the determination or proportionality constants and unknown exponents. The remaining material will be presented in Part II of this series of two papers.
Temporary Liners - A Method of Excluding Fluid Injectivity or Fluid Production
Authors: Gore George L.
Published: December 2007

A new-type, temporary, down-hole liner is made of heavy-gauge rubber hose of greater diameter than the well casing, or open hole. It is stretched lengthwise on a special setting tool, which reduces the liner diameter sufficiently so that it may be lowered by wire line to the proper depth. There, the liner is released, returns to its normal diameter, the resulting pressure-fit sealing off that particular section of formation so that fluids cannot penetrate from the wellbore. A special hydraulic setting-retrieving tool, for use in conjunction with this liner, is also described.

Introduction

A recent innovation in down-hole equipment is a temporary linear which can be set in casing or open hole, to seal off perforations or permeable zones, and later can be retrieved when no longer needed. This liner is simple in construction, economical in cost and efficient in operation.

Essentially, the temporary liner consists of a length of large diameter rubber hose and operates on the principle that, if such a hose is stretched lengthwise, the cross-sectional diameter is reduced. Likewise, when the tension is released and the hose is allowed to return to its original length, the original diameter is restored also. If the diameter of the hose is greater than the casing in which it is released, a tight-pressure fit is obtained, holding the liner in place and sealing off any fluid flow into the adjacent formation [Fig. 1].

Liner Construction

The liner is constructed of special four-ply, nylon-cord-reinforced rubber hose and is available in two standard diameters - one for 5-in. casing and the other for 7-in. casing [as shown in Fig. 2]. Any desired diameter can be made on special order. The hose diameter is slightly larger than the casing in which it will be used, a 5 3/8-in. OD size being used in 5-in. ID casing. The liner length varies, ranging from 10 to 50 ft, as each liner is prepared to match specific well requirements.

The ends of the liner are tapered down to a smaller diameter, the 5 3/8-in. hose being reduced to 4 9/16-in. at the ends. A short, drillable brass sleeve is riveted into either for gripping and stretching the hose. Fig. 5 is a cross-sectional end view of a liner, showing the nylon ribbing in the hose and the internal brass sleeve.
Experimental and Theoretical Considerations for Diverter Evaluation and Design
Authors: Beck F. E. , Langlinais J. P. , Bourgoyne A. T.
Published: December 2007

Until sufficient casing can be set to allow a well to be shut-in during a threatened blowout, diverter systems are used as a means of well control. Diverters permit flow to be directed away from the rig and rig personnel while minimizing pressures in the well. If the well were to be shut in prior to setting sufficient casing, contained pressures could fracture the formations at the conductor shoe and possibly broach to the surface.

Diverter systems must be designed to provide backpressures which will not result in fracture at the conductor shoe. Current diverter sizing calculations often assume atmospheric pressure at the diverter exit and assume that the component of the pressure gradient due to fluid acceleration effects is negligible. This study has shown experimentally that these assumptions introduce large errors into the calculation of backpressures. Experiments were carried out in model diverter systems for a wide range of critical flow rates for both gases and gas-liquid mixtures. Improved pressure loss calculation procedures were developed which gave acceptable agreement to the experimental results.
Green's Functions for Solving Unsteady Fluid Flow Problems in Naturally Fractured Reservoirs with Arbitrary Fracture Connectivity: Part II—Applications
Authors: Wijesinghe A. M. , Kececioglu I.
Published: December 2007

A general theory of Green's functions for solving unsteady fluid flow problems in naturally fractured reservoirs was presented in Part I of this paper. The governing equations for the fracture and pore system pressures are two linear parabolic partial differential equations which are coupled by a pressure-history dependent interporosity fluid transfer term. This model allows for the connectivity and permeability of both the fracture and pore systems over macroscopic distances and incorporates an improved unsteady interporosity flow model that is valid for general fracture configurations.

In this paper, we present a simple technique for deriving the Green's functions and source solutions required to solve unsteady flow problems by the theory developed in Part I. The technique is based on the solution of the eigenvalue problem for the Laplace operator and can be applied to solve a class of problems in which the boundary conditions for the fracture and pore system pressures are uncoupled and have the same functional form. Tables of Green's functions and source functions are presented for layered and rectangular reservoir configurations in bounded and unbounded domains.
Development Model for Geothermal Reservoirs
Authors: Marcou J. A. , Gudmundsson J. S.
Published: December 2007

The deliverability of liquid-dominated geothermal reservoirs is presented in terms of reservoir performance, inflow performance, and wellbore performance. Water influx modeling is used to match the performance of Wairakei in New Zealand, and Ahuachapan in El Salvador. The inflow performance is given in terms of a linear productivity index for liquid-only flow, and a solution-gas drive relationship for two-phase flow. A 9-5/8 in. production well is assumed, flowing 250°C water from 900 m depth, and with a wellhead pressure of 100 psia. A geothermal development model that couples reservoir deliverability and power plant performance is used to illustrate how the development cost of geothermal electric power projects can be estimated.
Power Averaging for Block Effective Permeability
Authors: Journel A. G. , Deutsch C. , Desbarats A. J.
Published: December 2007

A binary type permeability distribution with spatial autocorrelation is introduced to model the transition between shales and sand in a reservoir. The contrast between the two modal permeability values can be made realistically high, and the autocorrelation ranges can be made realistically large and anisotropic. A steady state, single phase flow simulation is run over a network whose block grids are informed from the previous permeability distribution. The resulting network effective permeabilities are plotted vs. the shale proportion and show that a power averaging process would yield a good estimate much more accurate than either the arithmetic average (power 1) or geometric average (power 0) traditionally used. Connections with percolation theory results are indicated.