Thick Shale Layer Research Articles

Identification of Shale Layer in Offshore Field of North East Java Basin for Non-Conventional Oil and Gas Exploration

<p>Non-conventional hydrocarbon exploration is one way to develop shale potential to increase oil and gas reserves in Indonesia. Shale is a rock that is rich in organic material and is a target for non-conventional exploration, because it functions as a source and reservoir rock with a large shale volume and low permeability. Isopach maps can represent the thickness of shale layers and have the potential to become non-conventional exploration targets located in thick shale layers. Based on this background, this research will identify shale layers in the offshore fields of the North East Java Basin for non-conventional oil and gas exploration. The methods used are well logging and seismic methods. This research focuses on determining the location of shale layer depocenters based on isopach maps as a first step in localizing areas that will be targeted for the development of non-conventional hydrocarbon exploration. This research uses 29 2D seismic lines and 2 well data, namely NP-1 and NP-2 wells and the research target is the Kujung Formation and Ngimbang Formation in the offshore area of the North East Java Basin. The results obtained from the isopach map show that the depocenter location of the Kujung Formation is in the northwest direction with a shale thickness of 600-800 meters, while the Ngimbang Formation is in the east direction with a shale thickness of 1000-1300 meters. From the depocenter location, it can be seen that this location has a wealth of organic material so it has the potential to become a source rock and reservoir.</p>

High resolution 3-D seismic and sequence stratigraphy for reservoir prediction in ‘Stephi’ field, offshore Niger Delta, Nigeria

The Offshore Niger Delta, Nigeria, stands as a dynamic geological marvel, known for its intricate processes and extensive hydrocarbon reservoirs. This study employed an integrated approach, utilizing 3D seismic data and well logs, to conduct a thorough analysis of sequence stratigraphy and reservoir characterization in the pursuit of optimizing hydrocarbon exploration in the region. The study focused on the NW–SE trending Miocene depocenters, which predominantly comprises alternating sandstone and thick shale layers within the Agbada Formation. These reservoir units showcased stacked shallow marine fluvial–deltaic sediments, separated by significant marine shale units. Within the study area, two hydrocarbon-bearing reservoirs were identified and named: R1 and R2. Petrophysical analysis identified R2 as the most promising reservoir, with a permeability of 1184 × 10− 3 µm2, 85% hydrocarbon saturation, porosity of 0.30, and effective porosity of 0.27. Fault structural analysis uncovered that hydrocarbons are trapped within a network of growth faults within the wave-dominated Niger Delta depositional system. From the sequence stratigraphic interpretation, four depositional sequences were delineated between the depths of 2030–3417 m, and are bounded by five sequence boundaries. Integrated seismic facies analysis revealed high-energy feeder systems likely supplying sediments from river sources to offshore locations. These integrated findings provide essential insights to inform resource management, exploration strategies, understanding of reservoir distribution, and structural intricacies within the complex offshore Niger Delta, Nigeria, providing valuable information. The depositional environment helped in the understanding of the stratigraphic traps which are prospects in the study area. This together with the associated reservoir quality allowed accurate prediction for potential reservoir facies and will further improve the field development plans.

Identification of overpressures resulting from undercompaction and hydrocarbon generation in shale-dominated settings using well-log data

Based on the concepts of organic geochemistry and well-log characteristics, we have determined the differences between undercompaction overpressure (UCOP) and hydrocarbon-generating pressurization (HGP) from well logs in the Chang 7 shale, Ordos Basin. The results revealed that shales have better hydrocarbon generation potential than mudstones. We found that UCOP is characterized by significant changes of the acoustic transit time (AC), compensation neutron (CNL), density (DEN), and resistivity (RT) on the well logs. Although HGP causes obvious changes in AC and RT logs, minor deviations are generally revealed in CNL and DEN logs. Further studies revealed that although UCOP occurs primarily in thick shale layers of the sedimentary center, HGP is predominant in the thin shales of the sedimentary edge. The reason for this difference may be attributed to the ubiquity of the shales associated with HGP, with the variation in well logs caused by the HGP concealed by the abnormal variation of UCOP. These findings thus revealed the distribution and well-log features of abnormal overpressure for the different generating mechanisms, thus providing significant guidance for further exploration and development of the overpressured formations.

Effects of smectite dehydration and illitisation on overpressures in sedimentary basins: A coupled chemical and thermo-hydro-mechanical modelling approach

Diagenetic smectite dehydration and smectite-to-illite transition in clay-rich sediments can contribute to the generation of overpressure in sedimentary basins, because of the release of water associated with these mineralogical reactions. However, the challenge of deciphering the contribution of smectite dehydration and illitisation to fluid pressure amongst other mechanisms generating overpressure requires the different mechanisms at play to be jointly considered. Here, we developed a coupled chemical and thermo-hydro-mechanical code, named SURP, to calculate the overpressure generation in a sedimentary pile because of sediment compaction during its burial, temperature increase, water flow and because of the release of water by clay dehydration and illitisation. For this purpose, a revised thermodynamic model describing smectite dehydration by a solid solution approach was considered, together with the different thermo-hydro-mechanical processes occurring in sedimentary basins. The SURP code was applied to the case study of an overpressured passive margin in the Niger Delta, composed of thick shale layers in a sedimentary pile. In this geological scenario, smectite dehydration was simulated and could explain 10–30% (20–50 bar) of the present day overpressure in the main reservoirs, in addition to compaction disequilibrium.

Sedimentary Characteristics and Lithological Trap Identification of Distant Braided Delta Deposits: A Case on Upper Cretaceous Yogou Formation of Termit Basin, Niger

Lithological trap identification in thin sand and thick shale layers is still a challenge for hydrocarbon exploration. Based on the high-resolution sequence stratigraphy theory and the establishment of high resolution sequence stratigraphy framework with seismic-well tie, the dynamic deposition process of braided river delta sands on late Cretaceous Yogou formation has been analyzed on 62 wells in passive rift Termit basin with multi-stages depressions and reversals. (1) Six kinds of sedimentary microfacies and three major reservoir sands with multi-stages stacking and lateral migration are in Yogou formation; (2) Based on Accommodation space/Sediments supply change and the deposition progress, sedimentary facies distribution in each member of YS3 sub-formation has been done according to sands thickness statistics of sedimentary micro-facies, narrow-time seismic attributes and slices analysis, multi-sources braided river delta depositional model has been concluded; (3) Based on source rock and caprock evaluation, with reservoir sands distribution and faults impact on Yogou formation of Termit basin, four types of traps, including structure-lithology, Structure-strata, stratigraphic and lithology are concluded. Traps influencing factors, i.e., structure geometry, sands distribution, paleotopography, stratigraphy cycling, sand/shale lateral connection, reservoir quality and so on, have different impacts on these traps, and different lithologic-stratigraphy traps have different exploration risks. Structure geometry and sands distribution are very important for the structure-lithology traps; structure geometry and paleotopography are the key factors in Structure-strata traps. Sands distribution and reservoir quality can be focused on lithology traps. Moreover, paleotopography and sand/shale lateral connection are significant on stratigraphic traps. Therefore, different hydrocarbon accumulation types of lithological traps have been established.

Hydrocarbon-Gas Cycling Improves Recovery in the Arun Gas Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 186280, “Review of 20 Years of Hydrocarbon-Gas Cycling in the Arun Gas Field,” by Suhendro, SPE, Pertamina Hulu Energi, prepared for the 2017 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 17–19 October. The paper has not been peer reviewed. Lean-gas injection has been used as an alternative method in gas fields to maintain reservoir pressure, minimize condensate banking near the wellbore, and mitigate oversupply operations during low-market periods. In this paper, past gas-cycling operations were examined to identify subsurface implications and effects on operability aspects for the Arun giant gas field offshore Indonesia in the North Sumatra Basin. Production and pressure data show that gas cycling contributes significantly to the improvement of field-recovery factors. Reservoir and Fluid Description The Arun gas field was discovered in 1971. The formation is carbonate reef, created during the Miocene age. It lies between two thick shale layers, Bampo on the bottom and Baong on the top. The Bampo formation is identified as source rock, with Baong shale as caprock. The field trends north to south, with a width of 18.5 km and a length of 5 km. Gas/water contact, to the south and west, was tilted toward the southern part of the field. A gas-condensate reservoir at a depth of 10,000 ft was found to have an average thickness of 503 ft and an area of 21,450 acres, with 7,100-psig initial pressure and a temperature of 352°F. Initial condensate/gas ratio (CGR) was 50 bbl/MMcf. The reservoir has 16.2% average porosity and 17% initial water saturation. Volumetric original gas in place (OGIP) is calculated to be 17 scf. The current production rate from the field is approximately 80 MMcf/D with 2,400 bbl of condensate/day. Fluid expansion and gas injection are determined to be the two main drive mechanisms on the basis of material-balance analysis. Hydrocarbon production uses four clusters with approximately 21 wells in each cluster. Each cluster is equipped with the same typical surface facilities. All produced fluid is pooled at Point A before being piped to gas-processing facilities. Initially, the produced gas was delivered to the Arun liquefied natural gas (LNG) plant for liquefaction but, in late 2014, the plant was shut down because of contract termination. In the second quarter of 2015, the facilities were reactivated for an LNG regasification terminal, Perta Arun Gas (PAG). Currently, the produced gas is transported to PAG for separation and dehydration before downstream processing. The northern part of the field contains fair porosity; the middle part is dominated by good and fair porosity, while the southern part has a greater incidence of poor porosity. Clusters II and III, which are located at the middle part, contribute more cumulative gas production and condensate compared with Clusters I and IV. Thus, better reservoir properties and parameters are contributing to better production.

Sedimentary Characteristics and Lithological Trap Identification of Distant Braided Delta Deposits: A Case on Upper Cretaceous Yogou Formation of Termit Basin, Niger

Lithological trap identification in thin sand and thick shale layers is still a challenge for hydrocarbon exploration. Based on the high-resolution sequence stratigraphy theory and the establishment of high-resolution sequence stratigraphy framework with seismic-well tie, the dynamic deposition process of braided delta sands on late Cretaceous Yogou formation has been analyzed on 62 wells in passive rifting Termit basin with multi-stages depressions and reversals. (1) Six kinds of sedimentary microfacies and three major reservoir sands with multi-stages vertical stacking and lateral migration are in late Cretaceous; (2) Based on accommodation space/Sediments supply change and depositional progress, sedimentary facies distribution evolution has been done according to sands thickness statistics of sedimentary micro-facies, and narrow-time seismic attributes and slices analysis, multi-sources braided delta depositional model has been concluded; (3) Based on source rock and caprock evaluation, with reservoir sands distribution and faults impact on Yogou formation of Termit basin, four types of traps, including structure-lithology, Structure-strata, stratigraphic and lithology are concluded. Traps influencing factors, i.e., structure geometry, sands distribution, paleotopography, stratigraphy cycling, sand/shale lateral connection, reservoir quality and so on, have different impacts on these traps, and different lithologic-stratigraphy traps have different exploration risks. Structure geometry and sands distribution are very important for the structure-lithology traps; structure geometry and paleotopography are the key factors in Structure-strata traps. Sands distribution and reservoir quality can be focused on lithology traps. Moreover, paleotopography and sand/shale lateral connection are significant on stratigraphic traps. Therefore, different hydrocarbon accumulation types of lithological traps have been established.

Integrated Approach for Characterizing Unconventional Reservoir Shale Hydrocarbon: Case Study of North Sumatra Basin

Integrated analysis of geochemical, rock mechanic and geophysics were carried out to characterize and map the unconventional reservoir shale hydrocarbon in Baong field, North Sumatera Basin, which is proven with the large potential hydrocarbon, particularly in the sand reservoir. The new challenge of this field is the present of thick shale layer, which is offering the new concept of an unconventional reservoir. The shale layer has the double role as source rock and reservoir. In this work, we performed geochemical analysis on the core data to determine the Total Organic Carbon (TOC), mineralogy, Tmax, and Kerogen type. In term of rock mechanic, the Rock Strength was calculated to determine the hardness and brittleness index. While for petrophysical analysis, we performed multi-linear regression of log data to estimate TOC relationship with the seismic attribute. In term of geophysics, we carried out seismic inversion to produce acoustic impedance, which is useful to map shale distribution. Our analysis shows that the target of shale layer has TOC range from 2 up to 3.5 wt.% with brittleness index of 0.48. Based on the predicted Tmax, this shale layer is categorized into early mature phase and classified into II Kerogen type, which means it has a potential to produce oil. The shale layer was indicated by the result of acoustic impedance inversion which has a value for over 25000 ft/s *g/cc and Rock Strength less than 3000 Psi.

Investigating Liquid Loading in Tight Horizontal Gas Wells

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 149477, ’Investigation of Liquid Loading in Tight Horizontal Gas Wells With a Transient-Multiphase-Flow Simulator,’ by Donald F.B. Jackson, SPE, SPT Group, and Claudio J.J. Virues, SPE, and David Sask, SPE, Encana, prepared for the 2011 Canadian Unconventional Resources Conference, Calgary, 15-17 November. The paper has not been peer reviewed. Liquid loading occurs in gas wells when production declines to a rate that is insufficient to lift the associated liquids to the surface. Liquid holdup in the horizontal section may impair production before liquid loading in the production tubing becomes evident. Holdup in the horizontal section can lead to slug flow at the tubing and to early onset of liquid loading in the tubing. The results from a transient-multiphase-flow model were found to be consistent with data acquired from video logging. Sensitivity analyses were performed with several normalized trajectories. Introduction Technology applied in conventional reservoirs in offshore horizontal wells can be applied successfully in onshore horizontal wells in unconventional reservoirs. The Jean Marie formation is an Upper Devonian carbonate platform between two thick shale layers in the Greater Sierra area, approximately 90 km east of Fort Nelson, British Columbia, Canada. The formation has low porosity (averaging 6%), low water saturation (averaging 20%), and low permeability (less than 1 md to air). Formation depth ranges from 600 to 1500 m subsea—1000- to 1900-m true vertical depth. The formation is entirely gas saturated with a dry sweet gas (95% methane) and is variably underpressured, with initial reservoir pressures of 6 to 15 MPa. The horizontal wells are drilled underbalanced to limit formation damage. Fig. 1 shows a typical well completion with 177.8-mm production casing set at the top of the Jean Marie formation. Gas is produced from the openhole portion of the completion. While drilling horizontally through the Jean Marie formation, the well trajectory is steered on the basis of gas-rate-while-drilling (RWD) data. The geologists maneuver up and down in inclination until a good permeability streak is indicated by a spike in flow rate from the RWD data. After reaching target depth, tubing (typically 60.3 mm) is installed and the well is brought on production. Typical gas- production rates for Jean Marie wells decline from an initial rate of 56×103 m3/d to 14×103 m3/d after 12 months and to 10×103 m3/d after 36 months.

Optimization of Production Gas Wells by Acidizing Using PLT Interpretation in Hassi R'Mel Field, Algeria

Abstract The Hassi R'Mel Field is a gas condensate reservoir with three Triassic sands (A-B-C) separated by a thick shale layer. Producing wells were drilled in the Northern-Central-Southern part with two lines of dry gas injection. A decrease in the production wells was observed. Build-up tests realized on those wells showed significant skin, which is due primarily to the excessive invasion mud used during drilling and workovers. A study was undertaken in order to see what method is to be used to optimize and improve the potential of these wells, which is less than hoped for given their petrophysic characteristics. Stimulation by acidizing was decided upon and three companies were selected to complete the program. During this program, 34 wells were acidized, which was carried out in three phases in order to diversify the methods. Of the 34 wells, 13 wells were chosen for the first phase, 13 wells for the second phase and the remaining eight wells were in the third phase. In order to study the stimulation's effects, PLTs were performed before and after each acidizing phase. The purpose of this paper is to show:The various methods of acidizing and the concentrations used in each of the three phases.Interpretations of the PLTs which enabled us to obtain flow layers, dynamic flowing pressure, static pressure, drawdown pressure and the productivity index in order to calculate the gain in production in each layer, the gain in production for each well and the flowing pressure. The combination of the PLT's results carried out on the acidized wells will be analyzed and shown in table form and graphs, which will enable us to draw a conclusion on the advantages and disadvantages of this stimulation program. Introduction Sandstone matrix stimulation has been the subject of extensive investigations for over 40 years and extensive experimental work has been conducted to investigate the reactions of various mud acid systems with damaging and formation materials(1–3). Theoretical analysis and modelling of the stimulation process have also been studied by some investigators(4–6). In this study, we wanted to share our experience of acidizing which was done in the Hassi R'Mel Field with different types of acids and various acidizing methods. The Hassi R'Mel Field is located 500 km southward from Algiers in the Algerian Sahara. It was discovered in 1956 and is one of the largest wet gas reservoirs in the world. This field has three distinct reservoir horizons: Zones A, Band C. Zone A sandstones are composed of very fine grained sandstones which are locally clay-rich with anhydritic cementing in some places. Zones B and C have very good reservoir quality with gas permeabilities ranging from 300 to 1,200 mD. Zone A also has very good reservoir quality, but its permeability is lower, at less than 300 mD. The productivity of Zones A, B and C has been reduced over time. Build-up tests performed on those wells had shown significant skin due to excessive invasion of mud used during drilling and workovers.

Spatial pressure compartmentalization in faulted reservoirs as a consequence of fault connectivity: a fluid flow modelling perspective, Xaréu oil field, NE Brazil

Sealing faults may have a major impact on reservoir compartmentalization and play a key role in advanced oil recovery strategies. Because of the different approaches and scales used to characterize faults, a considerable gap remains between engineers’ and geologists’ conceptions of faulted reservoirs. The fundamental difficulty in integrating these views lies in constructing realistic reservoir-scale models incorporating relevant fault properties on several scales, so that fault connectivity and its impact on fluid flow can be simulated and quantified properly. This paper is a step towards examining quantitatively the impact of fault connectivity on fluid flow at a reservoir scale. A stochastic reservoir model incorporating sealing faults was constructed. The number of faults in the model were gradually increased and several fluid flow simulations performed in order to verify the impact of fault density and fault connectivity on the spatial pressure variation. Despite being synthetic, the model incorporates some properties of an actual carbonate reservoir, the Xaréu oil field (XOF) in the Ceará Basin, NE Brazil. In the XOF, thin (<15 m) oil-bearing carbonate layers are interlayered in a thick (>50 m) shale bed. Sealing effects may be caused by the faults because they usually have a normal slip component, so that the thick shale layer becomes juxtaposed against the thin carbonate layers, behaving as barriers to fluid flow in the carbonate layers. It appears that there is no reservoir compartmentalization in the carbonate layers because there is overall pressure depletion in XOF – all the new wells drilled in the carbonate layers, before starting production, showed formation pressure values smaller than the formation pressure measured in the first wells drilled in the field. Nevertheless, it was not understood how such communication throughout the entire reservoir (approx. 19 km 2 ) could occur, given the presence of laterally extensive faults, with up to 5 km in strike and maximum vertical displacement greater than the reservoir thickness. In the synthetic model, fault population follows a displacement-length property derived from seismic data. Sub-seismic faults were also incorporated in the model using a downscaling law. The location, direction and length of each fault were also generated stochastically. In order to quantify the ‘degree of faulting’, two criteria were used: fault density (the fraction's ‘total fault length per occurrence area’; f 1 ) and fault connectivity (the fraction's ‘number of fault intercepts per occurrence area’; f 2 ). By comparing f 1 and f 2 for the real and simulated versions of the XOF carbonate reservoir it is concluded that the carbonate layers remain interconnected so that compartmentalization does not exist. From a methodological viewpoint, the most important aspect of the modelling is the change of focus regarding sealing. At least for the purposes of investigating interconnection, the adequate focus is on the ‘percolation core’ of the reservoir (its hydraulically connected and undamaged parts) and not on the faults themselves, regardless of their sealing nature.

Reservoir geology of the Utsira Formation at the first industrial-scale underground CO 2 storage site (Sleipner area, North Sea)

Abstract At the Sleipner fields in the North Sea, CO 2 is being injected into sands of the Miocene-Pliocene Utsira Formation, which is overlain by thick Pliocene shales. The highly porous (35%–40%) and extremely permeable (approximately 2 D) Utsira sands are organized into approximately 30 m thick packages. These packages are separated by thin (predominantly 1 m thick), low-permeability shale layers, which are assumed to contain potential fluid pathways of erosive or deformational origin. A 6.5 m thick shale layer close to the top of the sands separates an eastward thickening sand wedge from the main sand package below. Migration simulations indicate that the migration pattern of CO 2 below the shale layer would differ strongly from that within the sand wedge above. Time-lapse seismic data acquired prior to the start, and after three years, of injection confirmed a reservoir model based on these findings and showed that the thin shale layers act as temporary barriers and that the 6.5 m thick shale layer does not fully inhibit upward migration of CO 2 .

Faulting, fracturing and in situ stress prediction in the Ahnet Basin, Algeria — a finite element approach

Many low-efficiency hydrocarbon reservoirs are productive largely because effective reservoir permeability is controlled by faults and natural fractures. Accurate and low-cost information on basic fault and fracture properties, orientation in particular, is critical in reducing well costs and increasing well recoveries. This paper describes how we used an advanced numerical modelling technique, the finite element method (FEM), to compute site-specific in situ stresses and rock deformation and to predict fracture attributes as a function of material properties, structural position and tectonic stress. Presented are the numerical results of two-dimensional, plane-strain end-member FEM models of a hydrocarbon-bearing fault-propagation-fold structure. Interpretation of the modelling results remains qualitative because of the intrinsic limitations of numerical modelling; however, it still allows comparisons with (the little available) geological and geophysical data. In all models, the weak mechanical strength and flow properties of a thick shale layer (the main seal) leads to a decoupling of the structural deformation of the shallower sediments from the underlying sediments and basement, and results in flexural slip across the shale layer. All models predict rock fracturing to initiate at the surface and to expand with depth under increasing horizontal tectonic compression. The stress regime for the formation of new fractures changes from compressional to shear with depth. If pre-existing fractures exist, only (sub)horizontal fractures are predicted to open, thus defining the principal orientation of effective reservoir permeability. In models that do not include a blind thrust fault in the basement, flexural amplification of the initial fold structure generates additional fracturing in the crest of the anticline controlled by the material properties of the rocks. The folding-induced fracturing expands laterally along the stratigraphic boundaries under enhanced tectonic loading. Models incorporating a blind thrust fault correctly predict the formation of secondary syn- and anti-thetic mesoscale faults in the basement and sediments of the hanging wall. Some of these faults cut reservoir and/or seal layers, and thus may influence effective reservoir permeability and affect seal integrity. The predicted faults divide the sediments across the anticline in several compartments with different stress levels and different rock failure (and proximity to failure). These numerical model outcomes can assist classic interpretation of seismic and well bore data in search of fractured and overpressured hydrocarbon reservoirs.

Multiple Hydraulic Fracture Stimulation in a Deep Horizontal Tight Gas Well

Abstract This paper outlines the stimulation program used to successfully complete the 15,687 ft (4,783 m) TVD deep horizontal well Soehlingen Z-10 in the tight Rotliegendes sandstone onshore Germany. The program included the breakdown multiple rate injectivity test, use of proppant erosion stages to reduce near wellbore restrictions, and minifrac data analysis. Use of open annulus to analyze the stimulation treatment and modify the design is also covered. Considerations and experiments behind the design and execution of this horizontal well stimulation with hydraulic fractures perpendicular to the wellbore are presented and discussed. The well is now producing at a stable rate of 18 MMSCFD (20,000 m3/hr). Introduction Mobil Erdgas-Erdoel GmbH has recently drilled, completed and fracture stimulated a very deep horizontal gas well in an ultra-tight Rotliegendes Sand at a TVD of 15,687 ft (4,783 m) in North-West Germany (Z-10 well location is shown in Figure 1). Mobil is the operator of a consortium that includes BEBErdgas und Erdoel GmbH, RWE-DEA AG and Wintershall AG. The well was drilled in the Soehlingen gas field to a TVD of 18,860 ft (5,750 m) including a 2,063 ft(630 m) horizontal section. A multiple frac concept was used in order to develop an innovative method to economically produce significant gas resources from the tight sand. The first experience with multiple fractures from an inclined well dates back to the 1960's when Mobil completed a field experiment. Fracturing horizontal oil wells has been extensively used by MAERSK in the Danish part of the North Sea. Also, NAM has stimulated a horizontal well with two fractures in a moderately permeable (about 1 md) gas reservoir. Multiple fracturing of an ultra-tight gas sand (0.01-0.02 md) at a TVD around 15,700 ft (4,800 m) with a reservoir pressure of about 8,700 psi (600bar) and a temperature of 288 F (l42 C) has not been reported to date. This paper summarizes the fracturing concept and results of this unique project, concentrating on an integrated team approach with detailed frac design and project implementation. Background The multiple frac concept was used in order to economically produce significant gas resources in an ultra-tight Rotliegendes sand. Mobil, as an operator, began developing the Soehlingen field in 1982. The Main Sand, the target of this project, is a member of three productive sands in the Soehlingen field. The areal extent of the Main Sand is large (ca. 12 square miles, 30km2), The sand is massive (about 350 ft, 100 m) with moderate porosity (10 to12%) but with a very low permeability (0.001 to 0.1 md). The very low permeability is caused by the presence of diagenetic illite in the pore space, which reduces the permeability significantly. The Main Sand is underlain by a130 ft (40 m) fanglomerate layer separating it from the lowermost gas producing horizon. At the top of the reservoir a 30 ft (9 m) thick shale layer provides a seal to the Ebstorf Sandstone which is usually extremely tight. This tight reservoir has been produced on a limited basis from three vertical wells drilled in the early 1980's and fractured using massive hydraulic fracture technique, i.e. with large fluid volumes (500,000 gallons of crosslinked fluid), large amounts of proppant (in excess of 1.2 million pounds), and up to 7 ppg proppant concentration. These wells typically produced about 0.09 MMSCFD (100 m3/h) after perforation and around 0.9 MMSCFD (1,000m3/h) after formation breakdown with acid. Post-frac rates were around 4.5MMSCFD (5,000 m3/h) sustained for up to six years but proven uneconomic. To economically develop this significant resource required production rates three to five times the rate of a conventionally fractured vertical well. To achieve this goal, a multi-fractured horizontal well was deemed necessary.

Interpretation of Buildup Data Obtained From MHF Wells In Northern Germany

Summary The low-permeability (1 to 100 mu d) sand members of the Rotliegendes and the Carboniferous formations are a major source of gas reserves in West Germany. To establish commercial production from the limited number of deep (+13,100 ft [ +4000 m]) Rotliegendes and Carboniferous wells drilled to date, stimulation of the wells with massive hydraulic fracturing (MHF) treatments is necessary. A great deal of effort was directed not only at the design and performance of these MHF stimulation jobs, but also at the interpretation of buildup data obtained from the treatments and at the integration of the results into a model for future production forecasts. This paper reviews the available hand-applied methods used to analyze the postfracture behavior of wells stimulated with the MHF technique. These methods analyze buildup data collected during the past 5 years from three wells, each producing from more than one horizon. The results of these analyses include the length and conductivity of the fracture created during the MHF treatment. Introduction Recent estimates of gas reserves in West Germany amount to about 10.6 × 1012 scf [300 × 10 std m3]. Similar reserves are anticipated from future discoveries, which will probably occur in the Rotliegendes and Upper Carboniferous formations and are expected to be deep, low-permeability reservoirs. We estimate that at least one-third of the predicted discoveries can be produced economically if MHF stimulation treatments are applied. For an economic evaluation of the high cost of the development of deep, low-permeability gas reservoirs, it is necessary to predict the long-term flow behavior of MHF wells. This prediction requires realistic estimates of the length and the conductivity of the fracture system created in an MHF treatment, estimates of the formation permeability, and estimates of other reservoir parameters. permeability, and estimates of other reservoir parameters. This study updates Brinkmann et al.'s 1980 work, which reviewed the "hand-applied" methods that were available and used them to analyze the early data for three MHF wells and to obtain estimates for the fracture parameters. Since then, more data and methods have parameters. Since then, more data and methods have become available for the analysis. Data comparisons give some indication of the long-term behavior of the fracture properties. The new methods are suited for the analysis properties. The new methods are suited for the analysis of fractures intercepting multilayer reservoirs and result in improved estimates for the properties of the multihorizon/ multifracture system typically encountered in the Rotliegendes and Upper Carboniferous wells. The locations of the gas fields and the analyzed wells in northern West Germany are shown in Fig. 1. Each well produces from more than one horizon. The horizons were produces from more than one horizon. The horizons were separated by thick shale layers and were individually fracture stimulated. The well log for Goidenstedt Well Z7, shown in Fig. 2, is typical for all the wells. The available pressure/production performance results for the wells are shown in Fig. 3. Massive Hydraulic Fracturing The purpose of MHF is to expose a large surface area of the low-permeability formation to flow inside wellbore. This is achieved technically by generating fractures that extend far into the formation and by filling them with proppants to keep the fractures open and to ensure a high proppants to keep the fractures open and to ensure a high conductivity. A low-permeability formation is characterized as having an in-situ permeability of 1 to 100 mu d. At depths of +13,100 ft [+4000 m], a two-wing vertical fracture is created and is assumed to be symmetrical around the wellbore. Fig. 4 illustrates the influence of a two-wing vertical fracture by showing a three-dimensional representation of the pressure distribution in one quadrant of the drainage area of the MHF gas well Hamwiede Well Z2 (lower interval). Table 1 lists the reservoir parameters. After 1 year of production, the cumulative production amounted to about 636 ⨯ 10 scf [18 ⨯ 10 std m3 ] corresponding to 3% of the gas initially in place within the drainage area. Fig. 4 shows the influence of the fracture on the flow behavior in the reservoir. The flow is no longer radial to the wellbore; instead, it is almost linear in the region nearest the fracture. Radial flow is primarily away from the fracture. Therefore, conventional radial flow theory, as described in Refs. 2 through 4, is inadequate for analyzing low-permeability MHF gas wells. To make realistic predictions for the rates and reserves of MHF wells and to evaluate the long-term effectiveness of the stimulation, a theory explicitly accounting for the fracture system created in the MHF treatment was used. JPT P. 2173

Water Drive From Interbedded Shale Compaction In Superpressured Gas Reservoirs A Model Study

The behavior of abnormally high-pressured gas reservoirs in sand formations with randomly interbedded, thin, noncontinuous shale layers is examined using numerical simulation. The relevance of the internal water drive resulting from shale compaction and the influence of mobile water generation on reservoir and well behavior are discussed. Introduction An increasing number of hydrocarbon reservoirs discovered at great depths have pressures that are significantly higher than the hydrostatic pressure. Because of the high temperatures found at great depths, a large percentage of these superpressured reservoirs are gas or percentage of these superpressured reservoirs are gas or gas-condensate types. Several authors discussed the conditions that help create superpressured reservoirs. Such reservoirs often are found in thick sedimentary basins characterized by high-velocity sedimentation. Tightly interbedded shale and sand layers (under impermeable layers) are typical of superpressured reservoirs. The compressibility of abnormally high-pressured formations is higher than normal resulting from their understressed condition. When the abnormally high-pressured formation is a hydrocarbon reservoir, the high rock compressibility and even higher compressibility of the shale layers, either interbedded or boundary, may contribute appreciably to reservoir energy. Purpose Purpose It long has been recognized that reservoir rock compaction as well as interstitial water expansion, both resulting from pressure depletion, can contribute appreciably to the energy supporting production in abnormally high-pressured gas reservoirs. Several authors pointed out that in reservoirs embedded between thick shale layers, a sensible contribution to the production mechanism may originate by water expelled from the confining shale layers. Because these shale layers are very thick, the time required for the decreasing reservoir pressure to diffuse throughout the shale body may be more than the productive life of the reservoir. When reservoir rock contains very thin, noncontinuous shale layers, randomly distributed within the sand body, the time delay for water release from interbedded shale compaction can be disregarded. Wallace presented a list of actual gas reservoirs where water released presented a list of actual gas reservoirs where water released from the compaction of interbedded shale layers did contribute relevantly to reservoir drive, thus creating what might be termed an "internal water drive." In this study, production behavior of abnormally high-pressured gas reservoirs with thin shale interbeddings was examined. The study aimsto evaluate the energy contribution to reservoir drive resulting from water released from interbedded shale compaction; andto gain information about the adverse influence that diffused generation of mobile water (resulting from shale compaction) may have on well performance, considering that water production in gas wells poses disposal and often difficult lifting problems . JPT P. 937