Gas-producing Zones Research Articles

Właściwości złoża jurajskiej formacji Khatatba: Pole naftowe Tut, Pustynia Północno-Zachodnia, Egipt

The Tut oil field is in the North-western part of the Western Desert. This work aims to study the reservoir characteristics, to evaluate the hydrocarbon potentiality of the Upper and Lower Safa Members based on the available subsurface data obtained from open-hole well log records of four wells distributed in the study area. Numerous isopach and lithofacies maps have been constructed. The petrophysical evaluation, in terms of determining reservoir net-pay thickness, shale content (Vsh), effective porosity (∅eff), water saturation (Sw) and hydrocarbon saturation (Sh), were estimated. The vertical and the lateral distribution of the reservoir characteristics, in the form of litho-saturation cross-plots, iso-parametric maps and lithologic-matrix cross-plots were constructed. Three hydrocarbon charged zones in the Khatatba Formation were defined and represented by the Upper Safa-Top, Upper Safa-Bottom and Lower Safa-Top. The upper most part of Upper Safa Member (Upper Safa-Top) reservoir represents an oil producing zone where it consists of shallow marine to alluvial sediments. The Lower most part of Upper Safa Member (Upper Safa-Bottom) reservoir represents gas producing zone where it consists of a thick alluvial sand body. Finally, the upper most part of Lower Safa Member (Lower Safa-Top) reservoir represents an oil-gas producing zone consisting of shallow marine sediments with high terrestrial input. The iso-parametric maps show that Northern and central parts of the study area are the most favorable parts for hydrocarbon accumulation due to the increase in net-pay thickness and average effective porosity and decrease in water saturation toward these parts.

Study Explores Potential of Carbon Leakage in Denver-Julesburg Basin Wells

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210256, “Wellbore-Integrity Impact on Carbon Leakage To Ensure Safe Geological Sequestration,” by Yanrui Ning, SPE, and Ali Tura, Colorado School of Mines. The paper has not been peer reviewed. _ In the complete paper, poorly understood leakage potential is researched to quantify the carbon-leakage rate along one legacy well when carbon is injected into a storage formation in the Denver-Julesburg (DJ) Basin. The authors’ results indicate that, for secure carbon sequestration, a good geological storage site should be kept away from wells that have a surface casing depth of 476 ft or shallower and that were drilled before 1994. The effective well permeability highly affects leakage rate, suggesting the importance of estimating the most-representative value or range for this parameter. Introduction To estimate risks associated with geological carbon storage, the National Risk Assessment Partnership (NRAP) Open-Integrated Assessment Model (IAM) tool used in this study presents a modeling approach that can couple efficient reservoir and wellbore components with low computational cost. Two wellbore model components, the open-wellbore model and the multisegmented-wellbore model, were studied to estimate the leakage rate during and after carbon-injection operations. The effective permeability of the disturbed zone outside the well casing is an important parameter in leakage models. However, estimating a reasonable range for the effective well permeability of the disturbed zone remains a challenge. For this study, a more than 1-sq-mile section in the Wattenberg Field of the DJ Basin was used. The goal was to quantify the leakage rate when carbon dioxide (CO2) escapes through a well 1,100 ft from the CO2 injector. First, a reservoir simulation model was built to reflect the pressure and saturation changes during the 30-year injection period and the 100-year postinjection period. This model, based on an ongoing field study, included the CO2 injector, the legacy well that is the potential pathway of CO2 leakage, and the carbon storage formation. Study Area Carbon Storage Potential in Colorado. The top-ranked CO2 emission facilities in Colorado are above the DJ Basin. According to carbon-emission data, 13 facilities in Colorado, including five coal plants, emitted more than 0.7 million tons of CO2 in 2020. All the coal plants are scheduled to be retired by 2034. All eight CO2 emission facilities are in the DJ Basin, with half of those in the Wattenberg Field. This makes the DJ Basin, especially the Wattenberg Field, a good target for carbon storage. The stacked formations of oil and gas reservoirs and saline aquifers in the DJ Basin are potential CO2-storage formations. The current drilling activities with multistage fracture stimulation of horizontal wells target the oil- and gas-producing zones of Niobrara through Greenhorn. These oil and gas producers penetrate the shallower Pierre sandstone formation. This study quantifies the carbon-leakage risk when the Pierre sandstone is the carbon-storage formation and when one nearby Niobrara legacy well penetrates the storage formation and may behave as a potential leakage pathway.

Machine learning classification approach for formation delineation at the basin-scale

Machine learning and artificial intelligence approaches have rapidly gained popularity for use in many subsurface energy applications. They are seen as novel methods that may enhance existing capabilities, providing for improved efficiency in exploration and production operations. Furthermore, their integration into reservoir management workflows may shape the future landscape of the energy industry. This study implements a framework that generates predictive models using multiple machine learning classification-based algorithms which can identify specific stratigraphic units (i.e., formations) as a function of total vertical depth and spatial positioning. The framework is applied in a case study to 13 specific formations of interest (Upper Spraberry through Atoka / Morrow reservoirs) in the Midland Basin, West Texas, United States; a prominent hydrocarbon producing sub-basin of the larger Permian Basin. The study dataset consists of over 275,000 records and includes data fields like formation identifier, true vertical depth (in feet) of formations observed, and latitude and longitude coordinates (in decimal degrees). A subset of 134,374 data records were relevant to the 13 distinct formations of interest and were extracted and used for machine learning model training, validation, and testing. Four supervised learning approaches including random forest (RF), gradient boosting (GB), support vector machine (SVM), and multilayer perceptron neural network (MLP) were evaluated and their prediction accuracy compared. The best performing model was ultimately built on the RF algorithm and is capable of an overall prediction accuracy of 93 percent on holdout data. The RF-based model demonstrated high prediction accuracy for major oil and gas producing zones including the San Andres, Upper Spraberry, Lower Spraberry, Clearfork, and Wolfcamp at 98, 94, 89, 94, and 94 percent respectively. Overall, the resulting data-driven model provides a robust, cost-effective approach which can complement contemporary reservoir management approaches for multiple subsurface energy applications.

Geochemistry of the fracture-cave calcite of the Ordovician Yingshan Formation and its paleokarst environment in the Tazhong area, Tarim Basin, China

The fracture-cave reservoir of the Yingshan Formation is an important oil and gas producing zone in the Tarim Basin. Karstification occurs at the top surface of the carbonate rocks of the Yingshan Formation on the northern slope of the Tazhong area due to a short exposure, so abundant fracture-cave spaces are formed. On the basis of the data of nearly 49 samples obtained from 21 wells, the carbon and oxygen isotopes of the fracture-cave calcite were analyzed. The carbon and oxygen stable isotopic characteristics recorded during paleokarstification were discussed to provide geochemical evidence for predicting the distribution of the fracture-cave reservoirs, as well as to understand the genetic mechanism of karst fracture-caves and the fluid properties and paleo-hydrological conditions of paleokarstification. The fracture-cave calcite can be divided into three types based on its carbon and oxygen isotope values, which indicate three types of paleokarst environments with different fluid properties. Type I calcite has similar carbon and oxygen isotope values to the bedrock of the Yingshan Formation, with δ13C values of − 2.0 to 1.1‰ and δ18O values of − 5.76 to − 8.16‰. These values indicate that the calcite was precipitated in the eogenetic karst environment of the Yingshan Formation. Type II calcite has a δ13C value of − 2.13 to 1.0‰ and a δ18O value of − 12.41 to − 8.0‰. It has a similar δ13C value, but a significantly negative oxygen isotope value compared with values of the bedrock of the Yingshan Formation, indicating a buried karst environment. Type III calcite has an extremely negative δ18O value (δ18O value < − 14.50‰), indicating hypothermal karst genesis. Its formation is related to magma or deep hydrothermal fluids. No calcite with atmospheric freshwater genesis and significantly negative δ13C and δ18O values was found in the samples, indicating that the formation of fracture-caves is weakly affected by atmospheric freshwater. The main reservoir space of the Yingshan Formation is karst caves. The calcite in the karst cave fillings belongs to type I, indicating an eogenetic karstification environment. Therefore, the formation of the fracture-cave reservoirs of the Yingshan Formation in the Tazhong area is related to eogenetic karstification, which occurred during exposure and mainly contributed to the formation of the reservoir spaces.

Mineral composition and growth responses of tomato (Solanum lycopersicum L.) plants to irrigation with produced waters from the oil industry

ABSTRACTProduced waters are considered a byproduct from the oil industry that may contain mineral elements essential for plant nutrition, which enables them for irrigation purposes. Due to the growing demand for water for agricultural use in the world, the aim of this study was to determine the feasibility of using dilutions of fresh water and produced water derived from the gas-producing zone of Sabinas-Piedras Negras, in northern México and their effect on mineral content and allocation, growth, and yield of tomato plants. The results showed that the dilutions containing produced water reduced fruit, stem, and leaf fresh weight, and that the uptake and accumulation of minerals in plant tissues, except for sodium, was also decreased. However, plants irrigated with dilutions of produced and fresh water showed increased translocation of essential minerals from the leaves to the fruit, which partially contributed to alleviate the negative effects on fruit yield.

Three-zone characterisation of coupled strata and gas behaviour in multi-seam mining

We propose here a three-zone conceptual model in overlying strata of a longwall panel that accounts for the coupled behaviour of strata deformation and gas flow. The model comprises a fractured gas-interflow zone, a de-stressed gas-desorption zone, and a confined gas-adsorption zone. The fractured gas-interflow zone represents the area where mining-induced cross-strata fractures and bedding separations are well developed with high permeability in both the vertical and horizontal directions. Coal seam gas can easily be released from this lower zone to flow down into the mine workings. The de-stressed gas-desorption zone, which lies above the fractured gas-interflow zone, is another significant gas-producing zone in which strata are highly de-stressed. However, mining-induced fractures in this zone are mainly created in the form of bedding separations, which only increase horizontal permeability, and thus the gas cannot easily flow vertically down to the mine workings. In the upper confined gas-adsorption zone, strata depressurisation is limited; the major proportion of coal seam gas in this zone remains adsorbed and cannot be effectively captured. While both lower zones are the targets of gas drainage, the fractured gas-interflow zone is the main source of ventilation gas emission and the prime area of gas control. We have developed an approach to determine the height of these three zones based on the hypothesis of key stratum in strata movement, and verified the approach using gas drainage experience at a Chinese coal mine. The applications of the three-zone concept in selecting appropriate gas drainage methods for varied mining conditions, assessment of methane recovery efficiency, and gas drainage optimisation and maximisation in a mining district of China are also discussed.

Quantification of potential macroseismic effects of the induced seismicity that might result from hydraulic fracturing for shale gas exploitation in the UK

The furore that has arisen in the UK over induced microseismicity from ‘fracking’ for shale gas development, which has resulted in ground vibrations strong enough to be felt, requires the urgent development of an appropriate regulatory framework. We suggest that the existing regulatory limits applicable to quarry blasting (i.e. peak ground velocities (PGV) in the seismic wavefield incident on any residential property of 10 mm s −1 during the working day, 2 mm s −1 at night, and 4.5 mm s −1 at other times) can be readily applied to cover such induced seismicity. Levels of vibration of this order do not constitute a hazard: they are similar in magnitude to the ‘nuisance’ vibrations that may be caused by activities such as walking on wooden floors, or by large vehicles passing on a road outside a building. Using a simple technique based on analysis of the spectra of seismic S-waves, we show that this proposed daytime regulatory limit for PGV is likely to be satisfied directly above the source of a magnitude 3 induced earthquake at a depth of 2.5 km, and illustrate how the proposed limits scale in terms of magnitudes of induced earthquakes at other distances. Previous experience indicates that the length of the fracture networks that are produced by ‘fracking’ cannot exceed 600 m; the development of a fracture network of this size in one single rupture would correspond to an induced earthquake c . magnitude 3.6. Events of that magnitude would result in PGV above our proposed regulatory limit and might be sufficient to cause minor damage to property, such as cracked plaster; we propose that any such rare occurrences could readily be covered by a system of compensation similar to that used over many decades for damage caused by coal mining. However, it is highly unlikely that future ‘fracking’ in the UK would cause even this minor damage, because the amount of ‘force’ applied in ‘fracking’ tends to be strictly limited by operators: this is because there is an inherent disincentive to fracture sterile overburden, especially where this may contain groundwater that could flood-out the underlying gas-producing zones just developed. For the same reason, seismic monitoring of ‘fracking’ is routine; the data that it generates could be used directly to police compliance with any regulatory framework. Although inspired by UK conditions and debates, our proposals might also be useful for other regulatory jurisdictions.

Influence of modified starches composition on their performance as fluid loss additives in invert-emulsion drilling fluids

The influx of the liquid phase of drilling fluid, known as filtrate, in oil and gas producing zones can cause a significant decrease in the relative permeability of the fluids in the reservoir, and consequently, the well’s productivity. The growing interest in developing non-aqueous fluids with low toxicity and good performance under extreme temperature and pressure conditions encourages research in this area. This study investigates the potential of using starch derivatives modified with vinyl esters from fatty acids, as additives to control filtrate in invert-emulsion (W/O) drilling fluids. There are no reports of the use of modified starches as additives to control filtrate in non-aqueous systems. The synthetic drilling fluids used in this study were prepared from a standard formulation, submitted to a dynamic aging process and evaluated by means of physical–chemical filtration tests at high temperature and pressure, along with electrical stability and rheological tests. The results indicate that the formulations developed from fatty esters from starch are able to compete technically with the standard drilling fluid, and the performance of these materials is associated with the degree of chemical modification of the polysaccharide.

FeS-Scale Cleanout With High-Pressure Coiled Tubing and Tailored Fluid

This article, written by Dennis Denney, contains highlights of paper SPE 169759, ’Extreme Challenges in FeS-Scale-Cleanout Operation Overcome Using Temporary Isolation, High-Pressure Coiled Tubing, and Tailored Fluid Systems,’ by Mustafa Buali, Noel Ginest, SPE, Jairo Leal, and Oscar Sambo, Saudi Aramco, and Alejandro Chacon and Jose Vielma, Halliburton—Boots &amp; Coots, prepared for the 2014 SPE International Oilfield Scale Conference and Exhibition, Aberdeen, 14-15 May. The paper has not been peer reviewed. The gas-producing carbonate zones of the Ghawar field in eastern Saudi Arabia have been affected by extensive iron sulfide (FeS) scale deposition, reducing overall gas production and increasing risks during well interventions. Previous remediation attempts used workover rigs, which can be costly because of the time necessary for workovers and lost production. Hydrogen sulfide (H2S) levels (2 to 5%) in the reservoir also contribute to higher costs and risks with the use of workover rigs. H2S in the reservoir poses a safety concern with the returns at surface and a concern with potential corrosion of the coiled tubing (CT) and completion. Therefore, the safest and most economical method was deemed to be mechanical descaling with CT. Introduction Two wells were descaled mechanically by use of CT. Each well involved four major challenges: low reservoir pressure, higher reservoir temperature, horizontal openhole completion, and highspecific- gravity (3.7 to 4.3) scale. The low reservoir pressure required payzone isolation to enable circulating out the heavy scale and to minimize fluid losses to the formation. With a bottomhole temperature as high as 310°F, the operational envelope of temporary chemical packers in combination with lost-circulation materials (LCMs) to isolate the openhole section had to be expanded. Following mechanical descaling with CT, the final challenge was cleaning out the LCM in the horizontal open hole and bringing the well back to maximum gas production by use of pinpoint stimulation techniques. Scale Composition Many scale samples have been collected and characterized throughout the years with X-ray diffraction (XRD), X-ray fluorescence, scanning electron micrographs, and microscopic methods (thin section). Although the exact chemical composition of the scale changes from well to well and varies with depth in a given well, the scale deposits are mixtures of many compounds, usually dominated by FeS minerals including pyrrhotite, troilite, mackinawite, greigite, pyrite, and marcasite.

Lowered Tubing Offsets Field Production Decline

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 154394, ’Lowering Tubing in the Jonah Field Offsets Production Decline,’ by Chinenye E. Ogugbue, SPE, Cody R. Hopkins, Leah R. Greenly, SPE, Robert K. Wilson, and Gordon E. Gates, BP, prepared for the 2012 Americas Unconventional Resources Conference, Pittsburgh, Pennsylvania, 5-7 June. The paper has not been peer reviewed. Declining reservoir pressure and rate in the Jonah Field in the upper Green River basin in west-central Wyoming led to the common problem of liquid loading. Lowering the end of tubing (EOT) in more than 100 gas wells in the Jonah field enabled an average sustained production increase of approximately 105 Mcf/D, with an undiscounted payout of less than 12 months. In addition, for wells that have had the tubing lowered, the production-decline curves appeared to flatten out, offsetting anticipated double-digit decline. Introduction Discovered in the early 1990s, the Jonah field produces gas from the Lance formation, an extremely low-porosity, low-permeability, and fine-grained alluvial sandstone. The field is an overpressured area bounded on west and south by faults. The producing-formation thickness ranges from 2,000 ft updip to 3,500 ft downdip, at depths as shallow as 7,800 ft and as deep as 12,500 ft. Within this interval, the net-to gross-pay ratio varies from 25 to 40%. Sand bodies occur as both individual 9- to 15-ft-thick channels and as stacked-channel sequences, thicker than 200 ft in some places. Stacking of these alluvial-sand bodies resulted in an extremely heterogeneous reservoir in which reservoir sand bodies cover an areal extent of a few acres to as much as 640 acres. The field has been developed on 10-acre spacing. Wells are completed with eight to 16 hydraulic-fracturing stages, with each stage containing five to seven fluvial-sand-body channels. The Lance formation comprises the Lance Derbis Wedge, Lance Overpressure, Middle Lance, Jonah sands (Lance Jonah), Yellow Point sands, and the Wardell sands. The proven commercial gas-producing zones are the Lance Overpressure through the Wardell. BP operates 262 wells in the Jonah field. The wells have total depths ranging from 10,500 to 12,800 ft, with an approximately 3,500-ft vertical section of thick continental deposit composed of fluvial sandstones, back-swamp shales, coaly shales, and thick braided-stream sandstones. Porosity ranges from 8 to 10%, with permeability equal to 1 to 10 d. The average initial 30-day production was 1.5 MMcf/D. The aver-age condensate yield is 8.5 bbl/MMcf, and the water yield is 5–10 BW/MMcf.

Successful Short-Radius Re-Entry Well in Deep-Gas Drilling in Saudi Arabia

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 139855, ’The First Successful Short-Radius Re-Entry Well in Deep-Gas Drilling in Saudi Arabia,’ by Shaker Al-Khamees, SPE, and Hope Okwa, SPE, Saudi Aramco, and Jaywant Verma, SPE, and Sukesh Ganda, SPE, Schlumberger, prepared for the 2011 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 1-3 March. The paper has not been peer reviewed. Successful short-radius sidetracking in a deep gas area in Saudi Arabia is presented. Well ANDR-XYZ was sidetracked from vertical at 12,242 ft and built inclination to 90°, with maximum dogleg severity (DLS) recorded as 39°/100 ft. Thereafter, a 2,400-ft-long lateral was drilled in the Khuff-B reservoir. The sidetracking and lateral were drilled because of deteriorating production. The time required for this work was 53 days vs. the planned 60 days. The short-radius sidetrack was one of three options studied and resulted in saving 45 rig days compared with the other options. The well also extended the frontier of drilling and workover options and enabled opportunities to re-enter several other wells in deep gas areas in Saudi Arabia. Introduction Most deep gas wells in Saudi Arabia are drilled in the southern Ghawar field. The Late Permian Khuff-B and Khuff-C stacked carbonate reservoirs are the main gas-producing zones at depths of 11,500- to 12,500-ft true vertical depth. Two types of casing designs are used in these deep gas wells: “K1” and “K2.” In the conventional K2 profile, 133/8-in. casing is set from the surface to 30 ft into the base of Jilh dolomite formation. A 12-in. section is drilled into the Khuff-C carbonate, and 95/8-in. casing is set. Thereafter, 83/8-in. hole is drilled across Khuff or pre-Khuff reservoir. In a typical K1 design, in place of the 133/8-in. casing, 95/8-in. casing is set 30 ft into the base of the Jilh dolomite formation. An 83/8-in. section is drilled into the Khuff-C carbonate, and a 7-in. liner is run. After setting the 7-in. liner, 57/8-in. hole is drilled to the target formation. Occasionally while drilling these wells, higher pressures are encountered in the base of the Jilh formation. Therefore, the K2 design is preferred over the K1 design because it provides the opportunity to set an additional casing string. At planning stages, off-set wells are studied to finalize casing design. Because drilling a slimmer hole is faster and less costly, the K1 design is preferred when there is no history of high pressure in offset wells. While planning workover operations on Well ANDR-XYZ, various options were studied from the perspectives of cost, time, and technical feasibility. The short-radius-sidetrack technically was the only economically acceptable approach. The full-length paper details the conventional long-radius drilling approach, drilling options, and planning and execution of the first successful short-radius well in deep-gas drilling in Saudi Arabia. The objective of the Well ANDR-XYZ L1 re-entry was to sidetrack from the original vertical well in the Khuff-B formation and drill a 57/8-in. lateral targeting the Khuff-B reservoir.

Biogenically enhanced permeability: A petrographic analysis of Macaronichnus segregatus in the Lower Cretaceous Bluesky Formation, Alberta, Canada

A detailed petrographic analysis was conducted on several core samples from the Cretaceous-aged Bluesky Formation in the La Glace area in Alberta, Canada. Within the gas-producing zone of these upper shoreface sediments, a fine- to mid-medium-grained chert-rich litharenite is intensely bioturbated with Macaronichnus segregatus. Petrographic analysis showed that the burrow mantle is generally lined with dark-colored, iron-rich (mainly chert, shale clasts, and organic grains) fragments, whereas the burrow fill contained mainly quartz and light-colored chert fragments. The reason for the dark-colored grain segregation of the tracemaker is unclear, but in the Bluesky Formation presented in this study, grain segregation has improved the reservoir quality by effectively resorting compaction- and cement-resistant chert and quartz into the burrow fill. Primary reservoir quality can be preserved in the presence of chert as pore-occluding quartz overgrowths do not form on chert fragments as they do on monocrystalline quartz, thus leaving open, well-connected primary pores and hence elevated permeability. Chert fragments are resistant to the effects of mechanical compaction and are not easily squeezed into adjacent pore spaces as are ductile rock fragments. Further research is needed to test the chemical constituents of the grains that modern tracemakers ingest. This may lead to a better understanding of why sands burrowed with Macaronichnus and similar burrowed sediment can have elevated reservoir quality.

Application of Horizontal Well Technology in Colombia

Abstract To date, 20 horizontal wells have been drilled in Colombia: 16 in sandstone, and four in carbonate reservoirs. In carbonate, the economical success rate is 50 %, but in sandstone it is 88 %. In general, wells in Colombia are expensive. The vertical well cost varies from $2 million to $11 million, depending upon the reservoir depth. Horizontal well costs vary from 1.5 to 2.5 times the vertical well costs. Initially, most of the wells were completed with slotted liners. Now, new wells are completed with cemented and perforated liners to control water and gas production. The range of True Vertical Depth (TVD) is between 914 m (3,000 ft.) and 4,880 m (16,000 ft.). This paper presents three brief field histories, and the lessons learned to date. In cases where production is less than expected, the principal causes are:A horizontal well has commingled production from zones of high contrast in permeability, reducing considerably the producing length of a horizontal well.Production of unwanted fluid such as water and gas. With slotted liner completion, it is not only difficult to identify gas and water producing zones, but it is also difficult to isolate them effectively.Geological uncertainty, which results in drilling a well through a zone which is geologically different than expected. New horizontal wells are planned as short length wells in high permeability zones, and long ones in low permeability zones. Also, re-entry wells are now used in mature reservoirs to reduce drilling costs. The method used to analyse the well performance is discussed in the paper. To determine the producing length, gamma ray analysis, log information, production tests and/or production logs were used. A productivity analysis using analytical equations was also conducted to define if the well was damaged or had a small producing length. Then, decline curve analysis was used to forecast rate and reserves, and well production histories were matched for rates and cumulative production over time. Depending upon the problem, and considering feasibility and cost effectiveness, a corrective action was designed to improve well productivity. In summary, horizontal wells in Colombia have been successful and a large potential exists to drill many more wells. Introduction The history of horizontal wells in Colombia began in 1991, with the attempt to drill the well Orito 1H (it did not reach the objective because of operational problems). In January of 1993, the well Chuchupa 14 was successfully completed in a gas reservoir with higher than expected production(1). Then, in 1997 the well Guatiqu?a 3H was drilled in the Apiay Reservoir(1). It had some operational problems, but had excellent productivity results. Since then, another 18 wells have been drilled in different Colombian reservoirs. Out of 20 horizontal wells, four wells have been drilled in carbonate reservoirs, and 16 have been drilled in sandstone reservoirs. From the four wells drilled in carbonate reservoirs, one has been economically successful, one is non-economical, and two have too short a history to determine the economics conclusively.

Chemical Plug for Zone Isolation in Horizontal Wells

A laboratory study has been conducted on the use of chemical plugs, instead of conventional mechanical packers, to isolate water and gas-producing zones in horizontal wells. Results of experiments using horizontal wellbore models, consisting of PVC pipes internally lined with sand, indicate that slumping of the chemical plug could be avoided if the plug were spotted in a viscous brine pill. Of the three chemicals tested, a monomer, a polyacrylamide, and a plastic, only the plastic plug had a sufficiently high holding pressure. Research is being continued using a full-scale horizontal wellbore model.

Reductions In the Productivity of Oil And Low Permeability Gas Reservoirs Due to Aqueous Phase Trapping

Abstract Many hydrocarbon bearing reservoirs exhibit the potential for significant productivity reductions due to adverse relative permeability effects associated with the retention of invaded aqueous fluids. These fluids could include-water-based drilling mud filtrates, completion fluids, fracture fluids, workover fluids, kill fluids or stimulation fluids (including-spent acid). This paper identifies potential mechanisms behind phase trapping and identifies particular reservoir types which tend to be susceptible to this type of formation damage, most notably low initial water saturation gas reservoirs and strongly oil-wet oil reservoirs. Laboratory techniques to investigate the severity of aqueous trapping and various remedial techniques are described, and two field case studies illustrating the potential for permeability impairment due to invasive aqueous trapping are presented. One case study describes a series of wells completed in the Paddy formation and the second in the Cadomin formation in the Deep Basin area of central Alberta (both gas producing zones). Laboratory case studies documenting the phenomenon of aqueous, phase trapping in strongly oil-wet porous media are also presented. Introduction Oil and gas bearing formations are potentially susceptible to many different types of formation damage(1–6). In this paper we are exclusively concerned with damage associated with aqueous phase trapping (or water trapping or blocking as it is often referred to). To understand the concept of aqueous phase trapping, it is essential to differentiate between the concept of initial (often referred to as connate) aqueous phase saturation (Swi) and irreducible aqueous phase saturation (Swirr).Initial aqueous phase saturation is the initial average fractional portion of the pore space which is occupied by water. The value of the initial aqueous phase saturation is controlled by numerous factors, including reservoir geology, depositional history, temperature, wettability, height above free water contact and pore size distribution. The key point to differentiate in this area is that the initial aqueous phase saturation is not necessarily, and often is not equal to the irreducible aqueous phase saturation and can be either higher or lower than the irreducible saturation. It is in the second case, where the Swi is less than Swirr where productivity reductions due to phase trapping can occur.Irreducible aqueous saturation represents that saturation which is forced to exist in the reservoir by capillary mechanics. Once again, the value of the Swirr is determined by parameters such as the reservoir morphology, pore size distribution, pore throat size distribution, wettability, surface roughness, etc. We often obtain estimates of Swirr through the use of air-brine or air-mercury capillary pressure tests, Although these values often provide good approximations to Swirr they may be poor indications of actual Swi. FIGURE 1: Mechanism or aqueous phase trapping. (Available in full paper) Mechanism of Aqueous Phase Trapping Figure 1 provides an illustrative example of a set of relative permeability curves. The diagram is applicable to either an oil or a gas reservoir. Examination of Figure 1 indicates that, if the zone of interest is at some aqueous saturation greater than the irreducible value of 45%, aqueous trapping will not be a severe problem because the reservoir is already initially highly saturated with water and may even be producing free mobile brine.

Acoustic Flowmeter Field Test Results

Summary The newly developed borehole acoustic flowmeter provides data to locate depth precisely and to quantify gas production from individual gas entries, even when they are spaced closely together, for low-flow-rate gas-producing zones in a typical Devonian shale well in the Appalachian basin. Data from a field test conducted in Aug. 1987 are presented, along with the measurement theory involved. A comparison to a conventional spinner flowmeter on the same well is also presented.

Structural and Stratigraphic Controls on Natural Gas Production from Devonian Shales of Appalachian Basin of Southeastern Ohio: ABSTRACT

Detailed subsurface mapping and evaluation of production data from 12 Devonian shale units in southeastern Ohio indicate that the lower Huron Member of the Ohio Shale is the primary gas-producing zone. Jointed or fractured structural traps serve as the dominant reservoirs and consist of (1) regional joint or fracture systems, (2) fractures related to anticlinal or domal features, and (3) fractures related to monoclines. Evaluation of production data shows the Devonian shale reservoirs to be a multiple-porosity system. Gas is released from the reservoir in a stepwise manner: first, from the open fracture system; second, from adsorbed gas on the fracture surface; and third, from adsorbed gas within the shale matrix. Rapid decline of production typically occurs during the first year. However, release of adsorbed gas from the shale matrix has resulted in wells producing for 50 years. Stratigraphic variations in the shale units are of secondary importance. Isopach mapping is most useful in defining areas of penecontemporaneous faulting during shale deposition. These areas may serve as untested jointed or fractured reservoirs characteristic of Devonian shale reservoirs in southeastern Ohio.

Successful Application of Carbon/Oxygen Logging to Coalbed Exploration

Summary Two primary objectives of TRW's involvement as integrating contractor for the U.S. DOE's Methane Recovery from Coalbeds Project (MRCP) are (1) to demonstrate that this unconventional methane resource can be characterized and (2) to select target sites with the greatest production potential. It was contemplated that the wireline carbon/oxygen (C/O) logging tool could help the project's activities meet these objectives. A study using the C/O tool was initiated in the Arkoma basin at the Barringer Well 1–11 located in the Kiowa syncline, Pittsburg County, OK. Several nearby wells are producing methane commercially from strata that are associated with these coalbeds. The C/O log has shown that the various coalbeds in the Barringer well can be delineated. C/O ratio measurements have proved a valuable means of determining the presence of coal behind casing. Results from the Barringer well study indicate that this tool can identify and locate coal behind casing for possible recompletion and production of associated coalbed methane. Comparative data based on previous logging programs for the uncased Barringer Well 1–11 and laboratory studies on the coal are presented. Introduction The Arkoma basin contains extensive bituminous coal reserves. Accurate coalbed correlation and coalbed thickness are essential prerequisites to the determination of coal resources and reserves, especially those beds that are particularly gassy. The coals in the basin are generally considered moderately to highly gassy (appx. 200 to greater than 500 cu ft/ton). A range in coalbed methane contents is to be established for each bed and is used in conjunction with the verified coalbed reserves to provide an estimate of the volume of methane in place. Mustang Production Co. of Oklahoma City completed a successful coalbed characterization field test using the C/O tool during Jan. 1980. The cased test well. Barringer 1–11, is located in the Kiowa syncline (west central part of the Arkoma basin), Pittsburg County, OK (Fig. 1). This well penetrates about 18 possible coalbeds of Desmoinesian age (Pennsylvanian) over a 4.635-ft interval (Table 1). Several offset wells are producing methane commercially from strata associated with coalbeds in the Kiowa syncline. The objectives of this field test were to demonstrate that coalbeds can be (1) identified and located behind casing, (2) distinguished from gas-producing zones. and (3) shown to contain gas. Examples of the C/O tool response to coal are presented. Discussion of the field test includes a description of completed MRCP activities in the Arkoma basin, the resulting MRCP well test data, the C/O log field test configuration, and the test description. Comparison of the C/O results were made with openhole log information. Results have shown that the C/O logging tool successfully delineated the various coalbeds in the Barringer well. Application of the C/O log includes:identification of coalbeds behind casing,differentiation of coalbeds from gas zones,location of thin coalbeds on the order of 1 ft thick, anddetermination of coal quality. C/O Tool Response to Coal The C/O log utilizes a high-energy pulsed neutron source that produces 14-MeV neutrons by the deuterium/tritium reaction. Under high-energy neutron irradiation, elements emit gamma rays with specific energy levels. JPT P. 421^

Geology and Log Study of Tight Gas Sandstones--Cotton Valley Group: ABSTRACT

Through a cooperative research program among Schlumberger-Doll Research (Ridgefield, Connecticut), Schlumberger Well Services (Shreveport, Louisiana, and Houston, Texas), and Delta Drilling Co. (Tyler, Texas), a whole core and a conventional (DIT (FOOTNOTE *)/BHC, GR/CNL (FOOTNOTE *)/FDC (FOOTNOTE *), HDT/FIL (FOOTNOTE *)) and experimental-prototype (Digital Sonic, CNT-G, EPT (FOOTNOTE *), GST-A (FOOTNOTE *), NGT (FOOTNOTE *), NML (FOOTNOTE *)) suite of logs were examined from the lower and middle Cotton Valley sands (Upper Jurassic) of a 10,200-ft (3,100 m) well (Alice Snider 1). The well is located in the Carthage tight gas sand field, located in Panola County, about 60 mi east of Tyler, Texas. Particular attention was directed to one of the two gas-producing zones (9,3 4 to 9,638 ft, 2,851 to 2,938 m); a deeper gas-producing zone (9,700 to 10,027 ft, 2,957 to 3,056 m) was not cored. A synthesis of the rock core and log data leads to the following conclusions. 1. The formation is dominantly a well-laminated and horizontally bedded unit with low-angle, planar cross-bedding, shallow-water ripple marks, and convoluted bedding. Bioturbation and diagenesis have dramatically altered these features in some parts of the core. 2. The lithology is an alternating sequence of lithic sandstones (sublitharenites) and silty shales. Minor amounts of conglomerates, coal laminae, and fossil-bearing zones are also noted. 3. The tight gas sands have low porosities (< 10%) and low permeabilities (< 0.1 md). Intergranular porosity (2%) is reduced by authigenic quartz and/or calcite overgrowths and/or pore-lining, filling, and bridging clay minerals--illite, chlorite, and illite-chlorite mixed layers. Relatively abundant intergranular and secondary (4%) porosity is also noted. 4. The depositional environment of the gas-producing zone is interpreted as an alternating and transgressive sequence of shallow marine water dominated by barrier bars. Interbedded with the bioturbated shoreface sediments are minor tidal-deltaic sands deposited near the northeast-southwest-trending edge of a sedimentary basin. End_of_Article - Last_Page 1435------------

The Structure and Interpretation of Noise From Flow Behind Cemented Casing

Here is a noise-logging technique for finding behind-casing leaks. The leak source is located from a noise-amplitude log and the type of leak (single- or two-phase flow) is determined from a spectrum of noise at the source. Appropriate frequency cuts are then used to estimate leak rates. Introduction A noise-logging technique described in this paper has proved useful in searching for fluid movement in proved useful in searching for fluid movement in channels in the cement behind the casing of oil and gas wells. Such channels, of course, provide undesirable paths of communication between sands of different pressure. The idea of noise logging is old. In 1955, Enright qualitatively described a procedure for locating down hole, with an appropriate listening device, the peak noise associated with the point of origin of a leak. Korotaev and Babalov Used a noise detector to locate gas-producing zones in thick, open intervals. Stein et al. described the interesting procedure of listening opposite a productive zone in a flowing gas well for the "pinging" of sand grains against the producing string, thereby determining the maximum rate permitted before sand production begins. permitted before sand production begins. In spite of these applications, the general industry attitude still seems to be that a noise log is no better than or not even as useful as a temperature log - the traditional leak detector. This attitude is not entirely justified since there are instances in which noise logging has clear advantages over temperature logging. For example, it is seldom possible to flow a potential blowout well at a rate sufficient to give a definitive temperature anomaly. Likewise, a leak behind casing in a producing well might have a rate too small to detect with a routine temperature survey. We give in this paper experimental results that show that if one uses a detection sonde with good fidelity over the bottom half of the audible frequency range, the frequency structure of channel-type leaks has quite distinctive features. These features not only help distinguish single-phase flow from two-phase flow, but also provide a clue to a procedure for estimating an order-of-magnitude leak rate from peak noise. Several field examples demonstrate the routine operation of noise logging for detecting leaks and estimating rates. In particular, we present cases in which the noise log gives about the same information as a temperature log, cases in which the noise log gives additional information, and cases in which incorrect conclusions were drawn from a temperature log. Finally, we describe the potential of the noise logger as a flowmeter without moving parts. Here we rely primarily on experimental data, since our field data for such applications are quite limited. Frequency Structure of Channel-Type Leaks Details of construction and calibration of the detector are in Appendix A. We merely emphasize here -that the device, when driving 9,000 ft of armored cable, has its half-power points at 20 Hz and at 5,000 Hz. All subsequent spectra data are normalized to this frequency response (see Fig. 13). The experimental noise chamber, or leak simulator, is described in Appendix B. In using the simulator to study noise, we expand fluid across a porous plug and into a jacket packed with crushed marble. A 2 1/2-in. tubing string packed with crushed marble. A 2 1/2-in. tubing string through this jacket allows the detector to be positioned at the point of the leak. Variations on the basic theme are discussed in Appendix B. JPT P. 329