Ft In Depth Research Articles

Hydrogeochemical characterization of the groundwater of Lahore region using supervised machine learning technique.

The cationic and anionic composition in groundwater can be better understood by identifying the type of hydrogeochemical processes influencing groundwater chemistry. This research deals with the characterization of groundwater samples by considering the likely role of hydrogeochemical processes and the factors responsible for the weathering process. The study applies statistical methods and supervised machine learning algorithm (i.e., logistic regression model) on the large data set of 1300 water samples from the Lahore district of Punjab, Pakistan. All the water samples were collected by the local authorities from a deep unconfined aquifer (> 350 ft in depth) for the years of 2005 to 2016. The characterization of groundwater quality parameters includes pH, total dissolved solids (TDS), electrical conductivity (EC), total hardness (TH), calcium (Ca2+), magnesium (Mg2+), sodium (Na+), potassium (K+), chloride (Cl-), bicarbonate (HCO3-), nitrate (NO3-), and sulfate (SO42-). The results show the sequence of the major ion in the following order: Na+ > Ca2+ > Mg+ > K+ and HCO32- > SO42- > Cl- > NO3-. The ionic ratios and Gibb's plot revealed that the prominent hydrogeochemical facies of aquifer water is Ca-HCO3, Ca-Na-HCO3, and mixed Ca-Mg-Cl type rock-weathering process, especially carbonate and silicate weathering, as significant process controlling water chemistry. The statistical evaluation of the prepared regression model determined its prediction accuracy as 92.2%, which means the model is highly efficient and satisfies the analysis. The outcomes of this study favor the utilization of such methods for other areas with large data sets.

Underbalanced Drilling With Coiled Tubing in Marginal Shallow Wells

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 189904, “Underbalanced Drilling With Coiled Tubing: A Case Study in Marginal Shallow Wells,” by Adam Miszewski, SPE, and Toni Miszewski, SPE, AnTech, and Peter Hatgelakas, Chuck Henry Energy, prepared for the 2018 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, USA, 27–28 March. The paper has not been peer reviewed. The complete paper describes a recent directional coiled-tubing drilling (DCTD) job completed for an independent operator in the Appalachian Basin. The objective was to access target zones identified as adjacent to a recently drilled vertical well using a lateral sidetrack. The project was ultimately successful in that a dry hole was re-entered and sidetracked to create a productive well. The Economic Equation The target of the project was to define drilling efficiency in terms of cost per production rate. This measure takes the initial production into account and ties together the ability of the driller to make hole in the direction required with the ability to select a productive part of the formation. Recognizing that each stage of well construction can affect another, a multidisciplinary approach was adopted that included input from geology, geophysics, reservoir engineering, and drilling and completions engineering. Local experience with offset wells also was an important input, allowing for the fact that this experience was limited to vertical wells drilled with air or in an overbalanced condition. Well Selection The area chosen for the case study was in a well-understood area containing numerous offset wells with which to compare production and a known geology against which to plan the well. The wells typically do not exceed 2,500 ft in depth and were exclusively vertical. Four such wells had been drilled in the immediate vicinity in the previous year, three of which are currently on production at the time of writing at rates ranging from 10 to 25 B/D with varying levels of associated water production. Although one of the wells showed promise of production, the well turned out to be dry and the planned 4½-in. production casing string was not run and the well was not completed. The uncased well was chosen for the case study because it had the shortest payback period if it could be made to produce at a rate similar to those of neighboring wells. A 3D seismic survey of the area had identified a subsurface ridge that could be acting as a trap (Fig. 1). This ridge was selected as the target of the new well. A well path was planned that tracked approximately 15 ft below the top of the reservoir and along the top of the ridge, a depth low enough to access the reservoir but not so low that it might access the oil/water contact believed to be 40 ft below the reservoir top.

Parametric Study of Integral Buckle Arrestors Design of Submarine Pipeline System in Masela Block

A pipe collapse or local buckling is one of catastrophic failures that might be occurred in a submarine pipeline system due to a high external hydrostatic pressure. A preliminary survey of pipeline on the selected route shows that the pipeline will pass through a 5,309ft of depth. Buckle arrestors are necessary to be installed along a critical location of pipeline to prevent buckle propagation and catastrophic failure. The purposes of this study was to examine the effect of geometry variation, such as (i) pipe thickness, (ii) ratio of buckle arrestor thickness to pipe thickness, (iii) buckle arrestor length, and (iv) pipe diameter, of the integral buckle arrestor system to a buckling load factor. The study was conducted by numerical simulations using ANSYS™. Nominal Pipe Sizes of 28”, 30” and 32” with API 5L grade X60 materials were used in the simulation. The simulation was validated using experimental data of previous study and DNV-OS-F101. Based on this study, the buckle load factor was significantly influenced by the pipe thickness and the pipe diameter. The other two factors generate a slight change on the buckle load factor. For selected NPS of 28” with 1.2” thickness of pipeline, we hypothesize that the integral buckle arrestor with 30” length and 3.6” thickness can be used to prevent buckling propagation.

Simulation of hydraulic fracturing with propane-based fluid using a fracture propagation model coupled with multiphase flow simulation in the Cooper Basin, South Australia

In many unconventional reservoirs, gas wells do not perform to their potential when water-based fracturing fluids are used for treatments. The sub-optimal fracture productivity can be attributed to many factors such as effective fracture length loss, low load fluid recovery, flowback time, and water availability. The development of unconventional reservoirs has, therefore, prompted the industry to reconsider waterless fracturing treatments as viable alternatives to water-based fracturing fluids. In this paper, a simulation approach was used by coupling a fracture propagation model with a multiphase flow model. The Toolachee Formation is a tight sand in the Cooper Basin, around 7,200 ft in depth, and has been targeted for gas production. In this study, a 3D hydraulic fracture propagation model was first developed to provide fracture dimensions and conductivity. Then, from an offset well injection fall off test, the model was tuned by using different calibration parameters such as fracture gradient and closure pressure to validate the model. Finally, fracture propagation model outputs were used as the inputs for multiphase flow reservoir simulation. A large number of cases were simulated based on different fraccing fluids and the concept of permeability jail to represent several water-induced damage effects. It was found that LPG was a successful treatment, especially in a reservoir where the authors suspected the presence of permeability jails. The authors also observed that total flowback recovery approached 76% within 60 days in the case of using gelled LPG. Modelling predictions also support the need for high-quality foam, and LPG can be expected to bring long-term productivity gains in normal tight gas relative permeability behaviour.

Design and optimisation of multi-stage hydraulic fracturing in a horizontal well in a shale gas reservoir in the Cooper Basin, South Australia

Multi-stage hydraulic fracturing in horizontal wells is a well-known technology and is a key mechanism for gas recovery from extremely low permeable shale gas reservoirs. Since Australia’s Cooper Basin has a more complex stress regime and higher temperatures when compared to US shale gas formations, the design and optimisation of this technology in the Cooper Basin has not been explored to the authors’ knowledge. The Murteree and Roseneath shale formations in the Cooper Basin are 8,500 ft in depth and have been targets for shale gas production by different oil and gas operators. Deeper zones are difficult to fracture, as fracture gradients are often above 1 psi/ft. In this study, 1D vertical mechanical earth modelling using petrophysical log data was developed. Then, the stress profile was tuned and validated using the minimum horizontal stress from a mini-frac test taken along a vertical well. A 3D hydraulic fracture simulation in a vertical well as developed as a pilot to select the best locations for horizontal drilling. The selection criteria for the best location included the stress regime, gas flow rate and fracture geometry. Then a multi-stage fracture treatment in a horizontal well was designed. A large number of cases were simulated based on different well lengths, stage spacing and the number of stages. The productivity index was selected as the objective function for the optimisation process. The best case finally was selected as the optimum multi-stage hydraulic fracturing in a horizontal well in the Cooper Basin.

Using fluorescein and bromide tracers to investigate the role of baseflow in a small suburban watershed in Iowa, USA

Fluorescein and bromide tracers were used to study baseflow mechanisms of a small suburban watershed in northeast Iowa, USA. The tracers were applied to ten injection holes ranging from 1.3 to 3.0 ft in depth in two phases. Separately, two PVC wells (15 and 16 ft deep) were used to investigate tracer movement in a deeper flow system. Over 30 days of phase 1, none of the tracers was detected in the creek water. In phase 2, fluorescein was irregularly detected in the creek at two sites, whereas bromide was detected at one site only. Meanwhile, soil analysis detected measurable diffusion of bromide and fluorescein at four sites. At each of these sites, the tracer was found to be diffusing toward the creek. None of the tracers applied to the deeper PVC wells showed any movement toward the creek over 1 month of continuous sampling. Isotopic composition of water samples varied spatially as well as temporally going from the deep well (δ18O = −8.89‰) to the injection holes (average δ18O = −8.42‰), to the creek (average δ18O = −7.86‰), and further to the rain samples (average δ18O = −4.68‰). The analytical error margin is ±0.09‰. Samples from the injection holes were generally heavier than the deep well sample and lighter than the creek samples, indicating that there was no significant connection between the surface and the subsurface systems. Furthermore, the sporadic appearance of bromide and fluorescein both spatially and temporally points to the fact that baseflow does not constitute a significant part of the area's stream discharge. Copyright © 2014 John Wiley & Sons, Ltd.

The Degree of Leaching of Nitrogen, Phosphorus, and Potassium into Soils and Permeability of Earthen Floors Within Turkey Barns

A study was conducted to determine the degree of leaching of N, P, and K and permeability of soils from earthen floors within several turkey barns. Two turkey growout barns and one brooder barn were sampled at specific depths. For each barn, nine 5-ft soil borings were taken from the inside and three 5-ft bores were taken from the outside. The soil borings were divided into five 1-ft bore subsamples representing the top 5 ft of depth and were sent to a private laboratory for the analysis of total Kjeldahl N (TKN), NO3-N, total P (P2), K, pH, and percentage organic matter (OM). In addition, Uhland core [1] samples at three depths (1 to 3, 5 to 7, and 9 to 11 in.) were taken to determine soil permeability.The results of this study indicated that significantly greater concentrations of total TKN were present in the first 3 ft of soil depth for the inside vs. outside (control) samples of all farms. However, no differences in total TKN concentration were found between inside and outside samples at the 4- and 5-ft depths. Similar results were found for NO3-N and K concentrations as noted for total TKN; however, total P2 concentrations were essentially the same between inside and outside samples for depths of 2 to 5 ft. This finding indicated that total P2 did not migrate in the soil. The soil permeability results indicated that lower permeability occurred for the inside vs. outside samples at 1 to 3 in. and 5 to 7 in. for all farms averaged together. Thus, this study indicated that leaching of soil nutrients essentially stopped at 4- to 5-ft within these turkey barns, and in addition, soil permeability was lowered by the presence of growing turkeys inside these facilities.

Effect of level of surface-spoiled silage on teh nutritive value of corn silage-based rations

Twelve ruminally cannulated crossbred steers were used to determine the effect of level of surface spoilage in corn silage-based rations on dry matter (DM) intake and nutrient digestibilities. Irrigated corn was harvested at the 80% milkline stage of maturity and ensiled in pilot-scale bunker silos, which were 3 ft in depth, and a 9-ft-diameter AgBag®. After 90 days, the bunkers were sealed with a single sheet of polyethylene, and this silage was designated "spoiled". The silage in the AgBag was designated "normal". The four rations contained 90% silage and 10% supplement (DM basis), and the proportions of silage in the rations were: A) 100% normal; B) 75% normal: 25% spoiled; C) 50% normal: 50% spoiled; and D) 25% normal: 75% spoiled. Dry matter intake decreased in a linear manner as the proportion of spoiled silage increased from 0 to 75%. Steers consuming the normal silage ration had higher DM, organic manner, crude protein, neutral detergent fiber, and acid detergent fiber digestibilities than those fed the three rations that contained spoiled silage. The addition of surface-spoiled silage also had negative associative effects on nutrient digestibilities, and the integrity of the forage mat in the rumen was destroyed partially by even the lowest level of spoiled silage.; Dairy Day, 2000, Kansas State University, Manhattan, KS, 2000;

Soil sampling and analysis for volatile organic compounds

Concerns over data quality have raised many questions related to sampling soils for volatile organic compounds (VOCs). This paper was prepared in response to some of these questions and concerns expressed by Remedial Project Managers (RPMs) and On-Scene Coordinators (OSCs). The following questions are frequently asked: 1. Is there a specific device suggested for sampling soils for VOCs? 2. Are there significant losses of VOCs when transferring a soil sample from a sampling device (e.g., split spoon) into the sample container? 3. What is the best method for getting the sample from the split spoon (or other device) into the sample container? 4. Are there smaller devices such as subcore samplers available for collecting aliquots from the larger core and efficiently transferring the sample into the sample container? 5. Are certain containers better than others for shipping and storing soil samples for VOC analysis? 6. Are there any reliable preservation procedures for reducing VOC losses from soil samples and for extending holding times? Guidance is provided for selecting the most effective sampling device for collecting samples from soil matrices. The techniques for sample collection, sample handling, containerizing, shipment, and storage described in this paper reduce VOC losses and generally provide more representative samples for volatile organic analyses (VOA) than techniques in current use. For a discussion on the proper use of sampling equipment the reader should refer to other sources (Acker, 1974; U.S. EPA, 1983; U.S. EPA, 1986a).Soil, as referred to in this report, encompasses the mass (surface and subsurface) of unconsolidated mantle of weathered rock and loose material lying above solid rock. Further, a distinction must be made as to what fraction of the unconsolidated material is soil and what fraction is not. The soil component here is defined as all mineral and naturally occurring organic material that is 2 mm or less in size. This is the size normally used to differentiate between soils (consisting of sands, silts, and clays) and gravels.Although numerous sampling situations may be encountered, this paper focuses on three broad categories of sites that might be sampled for VOCs: 1. Open test pit or trench. 2. Surface soils (<5 ft in depth). 3. Subsurface soils (>5 ft in depth).

Compliance with California Title 23 and SWAT in an Arid Environment: Use of Oil-Well Data to Minimize On-Site Investigations

California Title 23 and the Solid Waste Assessment Test (SWAT) program, as administered by the Regional Water Quality Control Boards (RWQCB), require extensive characterization and monitoring of waste disposal sites. Typical SWAT/Title 23 investigations require multiple characterization boreholes in addition to groundwater and unsaturated zone monitoring. In an arid environment such as the southwestern San Joaquin Valley, many of these requirements become impracticable. Regions such as these are often characterized by extreme depths to groundwater, non-potable groundwater, and moisture deficient and hydrocompacted soils. Through the use of oil-field data, an accurate portrayal of subsurface conditions at a SWAT-ranked site was possible. Because of the extensive background material available and the relatively benign nature of the site, a single borehole was deemed by the REQCB to be an acceptable characterization of the site. As predicted from the background data review, this borehole was drilled to 1,000 ft in depth without encountering a water-saturated interval capable of yielding a sample. In addition, oil-saturated intervals were encountered beneath the site as predicted.

Evaluation of Waterflood Operations at Iatan East Howard Field, Mitchell County, Texas: ABSTRACT

Mobil Exploration and Producing US Inc. completed a reservoir description study on Iatan East Howard field in Mitchell County, Texas, in 1984. The application of study results has improved subsequent development drilling and waterflood operations. Lease production has doubled within two years with the drilling of 40 producers and 13 injection wells. The field produces from thin (2 to 40 ft) porosity stringers in fractured Permian age San Angelo and Clearfork dolomites at 2300 to 3200 ft in depth. Reservoirs are areally discontinuous due to original depositional controls on porosity develoment and distribution. Pay zone reservoir parameters such as porosity and permeability vary from 4 to 17% and 0.1 to 120 md, respectively. The presence of a fracture orientation at N60/degree/E to N85/degree/E has caused producing wells to experience early breakthrough of injection water when in line with injectors and the fracture direction. Waterflows have also occurred in drilling wells when similarly aligned. Recognition of this fracture overprint has dictated the use of a staggered line drive injection pattern parallel to the fracture trend to improve sweep efficiency.

Exploration Concepts and Methodology for Deep Medina Sandstone Reservoirs in Northwestern Pennsylvania: ABSTRACT

The blanket, deltaic sandstones of the Lower Silurian Medina Group have been commercially exploited in Pennsylvania since 1947. Rapid escalation of gas prices in the late 1970s triggered a drilling boom for the Medina Group sandstones which shows little signs of abating. Prior to this recent escalation, most Medina activity was concentrated in Crawford and Erie Counties, Pennsylvania, where the Medina is relatively shallow, ranging from 3,000 to 4,000 ft in depth. Since the late 1970s, interest in Pennsylvania's deep medina targets has increased dramatically and several major field complexes have been established. Analysis of various log, completion, and production data and comparison of the Medina play of northwestern Pennsylvania to other tight sand basins of North America reveal that these deeper (5,000-6,000 ft) Medina targets are largely diagenetic in origin and thus are controlled by widely dissimilar processes than their shallower counterparts. Detailed analysis of resistivity logs, production tests, and pressure data indicates a basin-center trapping mechanism for the deeper Medina sandstone reservoirs, similar to the Elmworth field of the Canadian Deep Basin. The local and regional trapping mechanisms of the deeper Medina reservoirs can be identified in the subsurface and closely resemble other major tight-sand basins, providing effectivemore » exploration models. Failure to identify properly the trapping conditions present in site-specific areas can result in inadequate exploration models with associated poor success ratios and inferior per-well recoveries.« less

Palo Pinto (Missourian) Algal Limestone Buildups as Hydrocarbon Reservoirs, Conley Field, Hardeman County, Texas: ABSTRACT

Mississippian and Pennsylvanian carbonates are important hydrocarbon reservoirs in the Hardeman basin of north Texas. The basin axis extends northeast-southwest, and stratigraphy at Conley field indicates that the area was structurally high during both the Mississippian and Pennsylvanian. The Palo Pinto Formation at Conley field is composed mainly of platy algal packstones with subordinate fossiliferous shales. The algal limestones thicken over the crest of the ancient structural high, where the low lime-mud content and the abundance of platy algae indicate that the depositional environment for the Palo Pinto was shallow (less than 100 ft in depth) and current-swept marine in character. Local thickening of the Palo Pinto can be explained as growth of platy algal bafflestones which nucleated on the crests of paleostructural highs. The shales indicate periodic inundation accompanied by renewed terrigenous clastic influx. The highest parts of the carbonate buildups were altered by freshwater diagenesis during episodic periods of emergence. Dissolution of metastable allochems led to the formation of moldic porosity. Subsequently, during burial diagenesis, occlusion of pore space by calcspar cements, neomorphism, pressure solution, and some replacements occurred. The best porosity and permeability occur in packstone and grainstone facies, indicating that the reservoir mainly is controlled bymore » depositional processes and only altered to an extent by diagenesis. Fracture porosity is not a major factor in this reservoir.« less

Dobson Butte Field, Williston Basin, Stark County, North Dakota: Nontypical Oil Production: ABSTRACT

The Dobson Butte field (T139N, R96W), Stark County, North Dakota, was discovered in 1982 following a detailed seismic program. Production is primarily from a structural trap in the Interlake Formation of Silurian age. Three oil wells are presently producing from a dolomite reservoir at about 11,000 ft in depth. Primary recoverable reserves of these three producing wells is calculated to be about 2 million bbl of oil. Additional reserves will come from further development of the Interlake reservoir as well as from the deeper Red River (Ordovician) Formation. The Dobson Butte field is a nontypical oil field within the Williston basin as to its high pour point oil (90/sup 0/F), high production water cuts (85-95%), lack of good oil shows in samples, unpredictable noncontinuous oil-producing reservoirs throughout the entire 600-ft Interlake Formation, difficulty in log interpretations, and difficulty in determining the source bed. The interpretation of these nontypical characteristics of Interlake oil production in the Dobson Butte field compared to other Interlake oil production within the Williston basin will have a profound effect upon future Interlake exploration.

Response of Submarine Power Cables During Laying Operations in Deep Waters

This paper reports the results of an analytical study performed for the Hawaii Deep Water Cable Program to determine the feasibility of transmitting electric power via cable in waters up to 7000 ft in depth and over a distance greater than 150 miles. The computer-aided methodology described herein sought principally to determine the cable loads and motions as functions of environmental, vessel and cable parameters.

Conodonts of the Bakken Formation (Devonian and Mississippian), Williston Basin, North Dakota

The Bakken Formation consists of two, mostly non-calcareous, grayish-black to brownish-black shales separated by light to dark gray, calcareous and dolomitic siltstone and fine-grained sandstone. The carbonaceous, black shales of the Bakken Formation are major source rocks for hydrocarbons and a distinctive fog marker in the Williston Basin. Samples were selectively collected from Bakken cores from 17 wells in northwestern North Dakota in an effort to determine the age and thermal maturity of the formation using conodonts. A diverse conodont collection of more than 650, mostly fragmentary, elements was obtained by disaggregating portions of the cores. Bakken conodonts are placed in 48 taxa and attributed to 17 form-genera. Specimens consist mostly of platform elements of Siphonodella, Pseudopolygnathus, Polygnathus, Bispathodus, "Spathognathodus", Palmatolepis, and Branmehla. Conodonts are unevenly distributed in the Bakken Formation. Most were obtained from thin (about 0.2 in; 5mm), fossil-rich beds in the upper shale. Only rare, fragmentary conodonts were recovered from the middle member. Conodont evidence indicates that the Bakken Formation in North Dakota is Late Devonian and Early Mississippian in age. A small conodont fauna from the lower shale includes species of Palmatolepis and Polygnathus and is tentatively considered of the Upper Polygnathus styriacus Zone (Famennian). Species of Siphonodoella, Pseudopolygnathus, and Polygnathus dominate the upper shale fauna. Conodonts from the uppermost beds of the upper shale of the Bakken are of the Lower Siphonodella crenulata Zone (Kinderhookian). Conodont evidence from the Bakken indicates that portions of the formation are correlative with the Exshaw Formation in Alberta, Sappington Member of the Three Forks Formation in Montana, Leatham Formation in Utah and Idaho, middle member(Leatham Member) of the Pilot Shale in Utah and Nevada, Cottonwood Canyon Member of the Lodgepole Limestone in Montana, and the Englewood Formation in South Dakota as reported by other workers. Paleontologic evidence suggests that an unconformity occurs at the contact between the middle member and upper shale of the Bakken and that this contact may coincide with the Devonian-Mississippian boundary. Conodont color alteration index (CAI) values from the upper shale of the Bakken range from 1.5 (about 7500 ft; 2290 m) to 2.5 (about 10,400 ft; 3170 m) and indicate that the Bakken has reached formation temperatures capable of oil generation at 7500 ft in depth but may have exceeded oil generation temperatures below 10,000 ft (3050 m). Lithologic and paleontologic evidence suggests that the two shale members of the Bakken were deposited in an anoxic, offshore, marine environment. Bedding features and fossils of the middle member indicate a current-influenced, mostly aerobic marine environment. Conodonts from the Bakken Formation, together with regional evidence, indicate that the lower shale and upper shale of the Bakken were deposited during episodes of widespread marine transgression and that middle member deposition occurred during a time of regional marine regression between these transgressions.

Simulation of Air and Mist Drilling for Geothermal Wells

Summary An improved method for calculating downhole temperatures, pressures, fluid densities, and velocities during air drilling has been developed. Improvements on previous methods include the following.A fully transient thermal analysis of the wellbore and formation is used to determine the flowing temperatures.The effects of flow acceleration are included explicitly in the calculation.The slip velocity between the gas and the cuttings is determined by the use of a separate momentum equation for the cuttings.The possibility of critical flow in the wellbore is tested and appropriate changes in the volume flow rate and standpipe pressure are made automatically.The standpipe and flowing pressures are predicted.The analysis is conservative. The effect of the cuttings on the wellbore flow will tend to overpredict the required volume flow rates. In this paper, the basic equations of fluid flow for a gas with cuttings and mist are presented along with a numerical method for their solution. Several applications of this calculational method are given, showing the effect of flow rate and standpipe pressure in typical air and mist drilling situations. Introduction Air and mist drilling have several advantages over conventional drilling fluids for geothermal drilling. The principal advantages are higher penetration rates, longer bit life, and no lost-circulation problems. The usual disadvantages, such as control of fluid influx and high pressure zones, are not normally a factor in geothermal well drilling. To realize these advantages, it is important to maintain adequate circulation. Determining the required volume flow rate to maintain this "adequate" circulation has always been difficult. The best available technique has been the analysis developed by Angel. This analysis allows estimation of volume circulation rates for various hole sizes. drillpipe sizes, and penetration rates. One difficulty with Angel's result is that the equation giving the volume flow rate must be solved by trial and error. This difficulty is avoided by use of the charts prepared by Angel, provided the case of interest is tabulated or can be estimated from similar cases. A second difficulty is that the drill cuttings are assumed to travel at the same velocity as the air. Angel notes that this is not a conservative assumption, and the analysis presented here demonstrates that the flow rates he predicts are 20 to 30% low. The downhole temperatures used for Angel's chart are assumed to be 80 degrees F at the surface, increasing 1 degrees F/100 ft of depth. There is no convenient way to convert to other temperatures. A final consideration is that the Angel charts do not apply to mist drilling. The addition of water to the air requires increases in both the volume flow rate and standpipe pressures to maintain the same penetration rate. The flow model discussed here was developed for Sandia Laboratories by Eneriech Engineering and Research Co. for use in a general purpose wellbore thermal simulator called GEOTEMP. Some features of GEOTEMP have been described in previous papers; however, the major technical features are summarized as follows. JPT P. 2120^

Oil and Gas Developments in North Mid-Continent in 1981

In Kansas, drilling activity in 1981 reached an all-time high of 6,865 wells, a 30% increase over 1980. Exploration and development drilling of oil reservoirs dominated this activity with oil completions up 42.4% to 3,089, while completions of gas wells were up only 8% to 617 wells. Total footage drilled amounted to 23,618,361 compared with 14,546,356 in 1980. Approximately 22% of total wells were classified as exploratory, 77% were development, and less than 1% were miscellaneous tests. Exploratory drilling continued to spread slowly into the lesser drilled areas of the state while development drilling favored the well-established producing counties. The average depth of an exploratory test was 4,063 ft or 79 ft deeper than last year, while development wells averaged 3,2 0 ft in depth. All wells classified as exploratory had a success rate of 21%, compared to 64% for all development wells. The success rate of all wells drilled was 54%. In Missouri, drilling was up a moderate 13.5% over last year. However, the most startling information was the 200% increase in new-field wildcat completions, which were drilled in 6 counties. Total footage drilled was 133,531 compared with 77,525 in 1980. The average depth of a test was 339 ft. Oil production for the year was 226,206 bbl, up 70%. The success rate among all tests drilled was 42.13%.

Dynamic consolidation — dramatic way to strengthen soil : Ramaswamy, S D; Lee, S L; Daulah, I U Civ Engng, NY, V51, N4, April 1981, P70–P73

The dynamic consolidation technique consists basically of dropping a heavy pounder of up to 4 x 10 4 kg from a height varying between 50 to 148 ft. The weight, height of fall, number of drops per pass and number of passes to achieve required compaction levels depend on thickness of ground to be compacted, nature of soil, groundwater level and consistency of material underlying soil to be compacted. This technique has been successfully used in Singapore to improve properties of loose ground by deep compaction for different types of soils (such as silty clay, peaty clay and dredged granular fill) up to about 26 ft in depth. From experience gained from various compaction jobs, the dynamic consolidation method can provide a quick and economical solution to a variety of deep compaction problems.

Resteaming Time Determination-Case History Of a Steam-Soak Well in Midway Sunset

The steam-soak process has been one of the most successful applications of thermal recovery in California's oilfields. The performance of a typical well in the Buena Fe Fee lease in the Midway Sunset field is studied to show the phenomena apparent in other wells on the lease. Introduction About 15 percent of California's oil production comes from thermally stimulated wells, where the latest technological advances are used to satisfy the ever-increasing demand for oil.One of the most successful applications of thermal recovery has been in the steam-soak process, also known as "huff and puff," or steam stimulation. This method requires one of the highest levels of good engineering, operational analysis, and supervision. Where the proper conditions exist, the results have been rewarding and generally profitable. During the last few years, extensive drilling has taken place in many old leases containing heavy, viscous oil. The additional drilling could not have been possible without the incentive of higher production rates resulting from steam stimulation.The Midway Sunset field, in Kern and San Luis Obispo Counties, Calif., is one of the areas of greatest thermal-recovery activity. The field is one of the largest oil fields in California, having produced over 1.1 billion bbl of oil, second only to the Wilmington field. The Midway Sunset field is a unique accumulation of heavy petroleum hydrocarbons. Discovered in the late 1800's, petroleum hydrocarbons. Discovered in the late 1800's, the field is a huge regional north-northwest trending homocline along the east flank of the Temblor uplift, nearly 25 miles long and averaging 3 miles wide.The complex geology of the field has resulted in many pools and reservoirs of Pleistocene, Pliocene, and Upper pools and reservoirs of Pleistocene, Pliocene, and Upper Miocene age, comprising the Tulare, San Joaquin, Etchegoin Reef Ridge, and Antelope formations. Productive intervals for these zones range to over 6,000 ft in depth, although most of the heavy oil accumulations are found around 1,000 to 1,500 ft in depth. During 1972 and 1973, drilling in and production from this field reached the highest levels in its entire history.Thermal stimulation efforts for heavy oil leases in Midway Sunset were started in the early and middle 1960's. Considerable experimentation took place during the 1960's as the industry began testing the potential of thermal stimulation. With the publication of research reports and increasing operating experience, the ability and confidence of the industry in thermal processes grew. Thermal stimulation is successful in the production of many shallow, viscous oil reservoirs. Much research and experimentation continues today to gain a more complete understanding of the processes involved.The subject of this paper is the performance of a typical well in one of Atlantic Richfield's leases in Midway Sunset. The Buena Fe lease is a fee property located in Section 22, T32S, R23S, Kern County, Calif., on the western fringes of the central area of the field, about 2 miles west of the town of Taft. Limitation of the discussion to the entire life of one well in the lease presents an opportunity to show the phenomena that are presents an opportunity to show the phenomena that are apparent in many other wells in the lease. A section of this paper involves discussion of resteaming time, since this is one of the important facets of producing steam-stimulated wells.Although certain conclusions have been drawn for the Buena Fe lease, no implications of similar relationships for a general reservoir case are intended. JPT P. 665