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Results
Downhole Gas Compression: World's first installation of a new Artificial Lifting System for gas wells
di Tullio, Matteo Tommaso (ENI S.p.A. - E&P Divison) | Fornasari, sergio (ENI S.p.A. - E&P Divison) | Ravaglia, Dino (ENI S.p.A. - E&P Divison) | Bernatt, Noel John (Corac Group plc) | Liley, Norman (Corac Group plc)
Abstract Downhole Gas Compression (DGC) is an entirely new powered artificial lift technology designed specifically for natural gas wells and will serve an as yet unrealised opportunity within the Upstream Gas industry. The technology offers the opportunity to increase production by 30โ50%, significantly improve reserves and delay the onset of liquid loading. Although it can be applied at any time during a gas asset's life cycle, it will find particular favour during the decline phase. It may also be used to extend the life of a field hence delaying divestiture. While DGC has clear parallels with Electrical Submersible Pumps (ESPs), its deployment into gas wells presents new challenges due to the incompatibility of current well control methods and the technologies and operational considerations necessary for efficient wellbore turbo-compression. This paper presents these issues and reports on the candidate well selection criteria, the compressor requirements and the well completion design for the world's first DGC installation in a live gas well to be conducted by Eni in an operated mature gas asset located in Southern Italy. The paper offers guidance to other operators on the design, installation and operational considerations for the deployment of this all new Artificial Lifting System for gas wells. Introduction The Upstream Gas Industry is often faced with the challenge of selecting an optimum Artificial Lifting system for a well from various alternatives available for gas well production enhancement. These challenges become more complex with increasing dynamic changes in well flow characteristics over the life of the well. Downhole Gas Compression (DGC) is an entirely new powered artificial lift technology designed to serve an as yet unrealised opportunity within the natural gas extraction industry. The new technology comes at a crucial time for the global energy market. As previously reported (OTC 16372 and SPE 96037) the application of DGC technology in suitable wells offers value for:Acceleration of early production and extension of production plateau in new gas developments; Cost effective rejuvenation of mature gas reservoirs characterized by low reservoir pressure and liquid accumulation into the wells; Improvement of gas well production and maximization of recovery factor from gas reservoirs with low environment impact; Identification of incremental reserves and for monetizing stranded gas. As part of an ongoing development through a Joint Industry Program (JIP) supported by Corac, Eni, ConocoPhillips, and Repsol-YPF; Eni is to conduct the first field trial of the new technology in an onshore gas well producing in an operated mature asset located in Southern Italy. The Programme has been completed in phases including the design, build and testing in a full scale flow loop closely replicating downhole conditions (SPE 116406). The prototype has been tailored to suit the expected gas flow range, composition and condition of the selected field trial well.
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Production and Well Operations > Artificial Lift Systems (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Compressors, engines and turbines (1.00)
Organic Richness and Productivity Index relationship in Dual Porosity flow-system of gas and condensate Kerogen reservoirs of Najmah Formation, North Kuwait
Acharya, Mihir Narayan (Kuwait Oil Company) | Al-Awadi, Mishari Ameen (Kuwait Oil Company) | Aziz, Rafi M. (Kuwait Oil Company) | Al-Eidan, Ahmad Jaber
Abstract The Najmah formation of Jurassic age has been tested and found to be a prolific source-rock as well as a producer of gas, condensate and light oil in different wells discovered from various fields of North Kuwait. The challenges of this unconventional reservoir are its dual porosity nature and its relation to the flow controlling system in view of very low porosity and the dependency on natural fracture network system as flowing mechanism. The drill stem test (DST) results at some wells were quite successful without any stimulation, while at other wells the DSTs were unsuccessful in spite of advanced and repeated stimulations, thus categorizing the Najmah as a geologically-complex, naturally-fractured tight gas and condensate reservoir. Pressure transient analysis and flow regime interpretation of the successfully run Drill Stem Tested (DST) wells confirm the dual porosity flow-system and the fractured nature of the reservoir. In this paper, the authors will point out the relationship between organic richness (Total Organic Content, TOC) of lower Najmah sub-unit and Productivity Index (PI). The term "matrix-dominated" is used to represent units with some dual-pore systems showing a typical profile with initial fracture flow and stabilized matrix support. The term "fracture-dominated" is used for units flowing through a fracture network but with limited matrix support. The cross-plot shows that PI increases with higher values of TOC, up to 2.45% which is the upper limit of TOC window, within which Najmah has been successfully tested as dual pore-system, matrix-dominated Kerogen reservoir, while fracture-dominated dual pore-flow system lie as outliers. The authors strongly feel that this finding will tremendously change the current understanding of the prospectivity and predictive estimation of productivity of the Najmah formation in other fields in Kuwait as well as in other regions. Introduction The Jurassic formations in North Kuwait have proven hydrocarbon potentials and prospectivity for gas, condensate and light oil from composite Najmah-Sargelu and Marrat reservoirs in different fields of North Kuwait such as North-west Raudhatain, Raudhatain, Sabriyah, Umm Niqqa, Dhabi and Bahra (Figure 1). The Najmah formation has two informal members; generally known as lower, Najmah shale and upper, Najmah limestone. The lower member, represented by high total gamma ray values associated with high uranium on spectral gamma ray logs, is composed of highly organic-rich argillaceous and calcareous clay, is called the Najmah shale or Najmah kerogen. The term Najmah kerogen in this work is used interchangeably with Najmah shale. This Kerogenous unit is believed to be one of the main source rocks for the shallower and younger Cretaceous in most major oil reservoirs in Kuwait, as well as the deeper reservoirs. However the results of drill stem tests highlighted the problem of how to identify productive zones and sweeter areas in these unconventional reservoirs, challenged with their geologically complex and naturally fractured, tight nature. To date, 29 wells have been drilled in these six fields and 14 of them tested in composite Najmah-Sargelu reservoir, with a 50% success rate.
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.70)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.70)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract The deconvolution of well test pressure transient data provides a constant rate pressure response that applies for the duration of the test. By extrapolating this response in time, the future performance of a well can be predicted. The extrapolation can include constraints defined by estimates of the volume of reservoir connected to the well but otherwise, relies only on information that is normally available at the time of testing. Uncertainty in either the deconvolution or the connected volume will result in a variety of extrapolations that defines the range of expected well performance. The advantage of this procedure is that a well's future production profile can be estimated very quickly and easily. Such a scoping exercise helps to understand a well's potential and to define the expected range of outcomes from more detailed modelling. Furthermore, it can be an efficient method for screening prospects when time and resources are limited. By monitoring the actual well performance against its prediction, underperforming wells can be identified for work-over. If permanent downhole pressure gauge data are available, the deconvolution can be continuously updated thus improving the production forecast. Where a production well is planned that is of a different type to the tested well (e.g. a horizontal or hydraulically fractured well instead of a normal vertical well), a technique is described to modify the tested well's deconvolved response to account for the change in well type whilst preserving the pressure transient response due to the reservoir and its boundaries. Two field examples of gas well tests are presented which demonstrate the method and the predicted production profiles are compared with observed data. Introduction A well's production can be estimated by building flow models and simulating future production for a given set of well and facility constraints. Simulation relies on what can often be uncertain geophysical, geological and petrophysical information. Generally, it is more accurate if it has been calibrated (history matched) to existing production data. Alternatively, the previous production history can be examined directly, trends identified and extrapolated to forecast production assuming that the operating conditions remain unchanged. This type of decline curve analysis uses no model but does require significant flow history in order to establish the trends for extrapolation. Production data analysis using simple analytical models is also possible (e.g. Fetkovitch, Blasingame) but also requires significant production data. In the initial stages of reservoir development, there is no production and the reservoir simulation model may be quite uncertain or unavailable because of insufficient information. This paper presents a method to forecast well production based on information obtained almost entirely during well testing without the need to build a dynamic model. The method involves four steps:Acquisition Deconvolution Extrapolation Prediction Each step is described in the following sections and the underlying assumptions are highlighted. Two field examples are presented and conclusions drawn.
- Reservoir Description and Dynamics > Formation Evaluation & Management > Production forecasting (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Integration of Production, Pressure Transient and Borehole Images in Horizontal Wells Drilled in Cambrian Sandstone Reservoirs of Hassi Messaoud Field, Algeria
Ogunyemi, Taofeek (Schlumberger North Africa) | Montaggioni, Philippe Jean (Schlumberger) | Azzouguen, Atmane (Schlumberger) | Kourta, Mourad (Shlumberger North Africa) | Kodja, Said (Sonatrach Inc.) | Madani, Messaoud (Sonatrach Inc.)
Abstract The economical viability of the Cambrian sandstone reservoirs in the Hassi Messaoud field is closely linked to the presence of fractures. Natural or hydraulically induced fractures control hydrocarbon productivity due to the low porosity, low matrix permeability and heterogeneous sedimentological characteristics of these fluvial deposits. Fracture corridors and permeable fault zones also represent a major risk of water breakthrough from the underlying aquifer in horizontal wells. The identification and characterization of open fractures and conductive faults is of critical importance for the completion decisions in this field. Whole cores enable a comprehensive description of fractures (morphology and type) over the cored sections of the reservoir. Meso-scale fractures can also be identified, oriented and characterized (open vs. cemented) on high resolution borehole images over the entire open-hole section. When combined with pressure transient analyses and production data, borehole image logs provide invaluable information on the enhanced fracture conductivity, the completion optimization and the reservoir management for sustaining long term production in these complex reservoirs. Wells with high fracture density usually correlate with high production rates as long as the dominant fracture strike is close to the direction of the maximum in-situ horizontal stress (sH). Wells with low fracture density or dominant fracture strike oriented oblique or perpendicular to sH generally show poor production rates. This paper discusses case studies of fracture and fault characterization from a combination of borehole images with production and pressure transient data to provide an explanation for ambiguous production observations and well test data. Examples of completion optimization utilizing this integrated approach are also presented. 1. Introduction Although it is widely admitted that the presence of fractures (natural and hydraulic) is directly linked to the production of the hydrocarbon trapped in the Cambrian reservoirs of the Hassi Messaoud field, very little is known about the relationship between their properties and spatial distribution with the dynamic measurements of the reservoir. Extensive core analyses have shown that permeability anisotropy at different scales is controlled by the interplay of depositional facies and fracture systems in this field. The design, execution and economic aspects of hydraulic fracturing to improve well productivity by limiting the effect of permeability anisotropy in the Cambrian reservoirs of Hassi Messaoud field have been studied by many authors. These topics are particularly well documented by Rahmouni et al, (2002) and Guehria et al, (2005). Similar patterns in production profiles, with high initial production rates followed by a sharp decline, have been observed across the majority of both hydraulically fractured and conventional wells in Hassi Messaoud field. In the majority of the transient test data performed in horizontal wells, the analysis of the pressure derivative reveals that production comes from both natural fractures and layered media in a bilinear flow characterized by a slope of ยผ (m = 0.25) of the Log-Log pressure-derivative plot (Azzouguen et al, 2000).
- Geology > Structural Geology (1.00)
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Africa > Middle East > Algeria > Ouargla Province > Hassi Messaoud > Oued Mya Basin > Hassi Messaoud Field (0.99)
- Africa > Middle East > Algeria > Ouargla Province > Hassi Messaoud > Berkine Basin (Trias/Ghadames Basin) > Hassi Messaoud Field (0.99)
Abstract Modelling flow around horizontal wells (HWs) is a complex and challenging task due to the three-dimensional (3D) nature of the flow including the permeability anisotropy. This work is aimed to provide a reliable tool for prediction of the well performance of HWs. The steady state Dracy flow of a single-phase incompressible fluid in a HW was simulated by developing a 3D single HW mathematical model using Comsol multi-physics mathematical package which is based on finiteelement methods. In house simulator is validated and verified when comparing its results with the corresponding values obtained from ECLIPSE commercial simulator, and a number of semi-analytical models widely used in the petroleum industry, all for the same prevailing conditions. These semi-analytical equations have been obtained by simplifying the 3D system to two 2D problems. We demonstrate that this assumption is only appropriate if the thickness of reservoir model is small compared to the length of HW. Our results also indicate that these equations may not predict the well performance of HW correctly specially in low permeability anisotropy values. Based on the results of in house simulator, correlation has been developed for calculation of mechanical skin using the efficient statistical Response Surface Method. This skin factor is employed in an open-hole vertical well productivity equation giving the same flow rate as that of the HW. The results of the proposed formulation have been tested against new data points, which have not been used in its development confirming the integrity of the approach. Moreover, a comprehensive sensitivity study on the impact of pertinent parameters (i.e. HW radius, HW length, reservoir dimensions, anisotropy and partial penetration) on the performance of a HW has been conducted with some important practical findings. Introduction In last few years, many horizontal wells (HWs) have been drilled around the world. The major purpose of drilling a horizontal well is to enhance reservoir contact and thereby enhance well productivity. Often, the productivity index of a HW is 3 to 4 times that of a vertical well in the same reservoir, as a result several vertical wells can be replaced by one HW. However drilling a HW is more expensive than a vertical well and involves more operational risk. There are many equations in the literature to estimate steady state flow rate around a HW. These equations can be categorized into three groups each using a different shape to represent the horizontal drainage area: The first group assumes an elliptical shape for drainage area of a HW, e.g., Borisov (1964), Joshi (1991), and Permadi (1993). The second group uses a rectangle with two semi-circles on both sides, e.g. Renard & Dupuy (1990). Shedid et al. (1996) improved the equation obtained by the second group by considering a non-symmetrical shape for the drainage area of a HW. He suggested a variable drainage area, instead of semi-circle section on both sides as a function of the HW length (L). He also studied different steady state equations developed to estimate flow rates of HWs and concluded that all these equations provide similar HW productivity for L less than 1000 ft, while there is a remarkable difference when L is more than 1000 ft. Economides et al. (1991) investigated the effect of anisotropy on the well performance using numerical simulator. Their results show that there is a significant difference between HW productivity predicted using Joshi's equation (1988) and corresponding values estimated using the numerical simulator specially for low anisotropy values. Therefore they introduced more appropriate equation by modifying Joshi equation for anisotropic reservoirs. All semi-analytical formulations are derived based on the analogy between Ohm's law for flow of electricity, and Darcy's law for flow through porous media.
Abstract This paper probes the gauge placement issue with regard to yielding quality formation parameters, unaffected by wellbore effects. Non-physical or biased results may result if the wellbore effects go unaccounted for. We used a wellbore/reservoir simulator, which conserves mass, momentum, and energy to develop a comprehensive understanding of the gauge-placement issue. First, we reproduced a field example from a deepwater asset to demonstrate the simulator's capabilities. In this example, we matched the bottomhole pressure, and pressure/temperature monitored about midpoint of the flow string during a multirate test sequence lasting some 60 hours. Calculations show that thermal effects are exacerbated by increasing flow rate and increasing gauge distance from the perforations. Second, we performed a detailed uncertainty analysis with experimental design. Variables included in this analysis were perforation-to-gauge distance, permeability, geothermal gradient, flow rate, fluid viscosity, thermal conductivity of annular fluid and formation, and mechanical skin. This analysis sheds light on relative importance of these variables on our ability to extract formation parameters. Simple correlations are developed for designing gauge placement in many environments. Introduction Reservoir monitoring with permanent pressure sensors can be traced back to the 1960's (Engel 1963; Nestlerode 1963). However, downhole technology development had to occur before the industry-wide usage began in the 1980's (Shepherd et al. 1991; Bezerra et al. 1992; Unneland and Haughland 1994). Various case studies (Unneland et al. 1998; van Gisbergen and Vandeweijer 2001) point to the ever-increasing popularity today. Long-term gauge performance and reliability of electronic gauges have been explored by van Gisbergen and Vandeweijer (2001), with the reliability-analysis tools provided by Veneruso et al. (2003). Fiber-optic sensing (Kragas 2004) provides an alternative to electronic gauges. Technology also exists for processing voluminous data with wavelet analysis (Athichanagorn et al. 2002), deciphering noise from signal and reducing data points for analysis. Data interpretation capabilities with convolution (Unneland et al. 1998) and deconvolution (von Schroeter et al. 2004; Levitan et al. 2006, and Ilk et al. 2006) algoithms have really provided necessary impetus for the use of downhole pressure with surface or subsurface rate data. While great strides have been made in various aspects of data gathering, processing, and interpretation, integrity of downhole pressure data has not gained as much attention. This paper explores issues that may arise from gauge placement in the borehole and the consequence of dealing with potentially imperfect data, influenced by wellbore effects. Placement of permanent downhole sensors is often dictated by completion hardware and other logistical issues. As a consequence, a pressure gauge is often placed hundreds of feet away from the point of fluid entry. Questions arise whether pressure data so collected are free of wellbore thermal effects. For a given gauge location, flow rate plays the most dominant role in distorting the pressure response from a transient-pressure analysis standpoint. In other words, the larger the rate the larger is the thermally induced distortion. Consequences of potentially inaccurate pressure data can be significant, from both pressure-transient and rate-transient analyses viewpoints. Papers dealing with thermally induced pressure distortion are a very few. Kabir and Hasan (1998) showed how off-bottom gauge measurements can induce significant errors in pressures, thereby posing serious interpretation difficulties. In other words, when temperature diffusion dominates pressure diffusion, pressure may decline during a shut-in test and increase during a flow test. Consequently, standard interpretation techniques become unworthy of use. Both forward and reverse simulations with a coupled wellbore/reservoir simulator accounting for energy transport in the wellbore appear to be the most prudent approach. Advances in coupled wellbore/reservoir modeling have been reported with the introduction of semianalytic energy transport equation in the wellbore (Hasan et al. 2005; Izgec et al. 2006). Significant gain in computational speed results when efficient coupling of finite-difference forms of mass and momentum equations occurs with the semianalytic energy equation. This paper presents general guidelines for placing the permanent downhole sensor to minimize thermal distortion.
- Europe > United Kingdom (0.93)
- North America > United States > Texas (0.47)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Green Canyon > Block 727 > Tonga Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Green Canyon > Block 727 > Tahiti Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Green Canyon > Block 727 > Caesar Field (0.99)
- (21 more...)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)