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Results
Abstract Asphaltic and sand production problems are common production challenges in the petroleum industry. Asphaltic problem results from the depositions of heavy material (asphaltene) in the vicinity of the well which may cause severe formation damage. Asphaltic materials are expected to deposit in all type of reservoirs. Sand production refers to the phenomenon of solid particles being produced together with the petroleum fluids. These two problems represent a major concern in oil and gas production systems either in the wellbore section or in the surface treatment facilities. Production data, well logging, laboratory testing, acoustic, intrusive sand monitoring devices, and analogy are different techniques used to predict sand production. This paper introduces a new technique to predict and quantify the skin factor resulting from asphaltene deposition and/or sand production using pressure transient analysis. Pressure behavior and flow regimes in the vicinity of horizontal wellbore are extremely influenced by this skin factor. Analytical models for predicting this problem and determining how many zones of the horizontal well that are affected by sand production or asphaltic deposition have been introduced in this study. These models have been derived based on the assumption that wellbore can be divided into multi-subsequent segments of producing and non-producing intervals. Producing intervals represent free flowing zones while non producing intervals represent zones where perforations are closed because of sand or asphaltic deposits. The effective length of the segments of a horizontal well where sand and/or asphaltene are significantly closing the perforations can be calculated either from the early radial or linear flow. Similarly, the effective length of the undamaged segments can be determined from these two flow regimes. The numbers of the damaged and undamaged zones can be calculated either from the intermediate radial (secondary radial) or linear flow if they are observed. If both flow regimes are not observed, the zones can be calculated using type curve matching technique. The paper will include the main type-curves, step-by-step procedure for interpreting the pressure test without using type curve matching technique when all necessary flow regimes are observed. A step-by-step procedure for analyzing pressure tests using the type-curve matching technique will also be presented. The procedure will be illustrated by several numerical examples.
- North America > United States (1.00)
- Asia (0.68)
- Europe > Norway (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
Summary Gas transient flow in a gas pipeline and gas tank is critical in flow assurance. Not only does leak detection require a delicate model to simulate the complicated yet dramatically changed phenomena, but gas pipeline and gas tank design in metering, gathering, and transportation systems demands an accurate analysis of gas-transient flow, through which efficient, cost-effective operation can be achieved. Traditionally, there are two types of approaches used to investigate gas-transient flow: one involves treating gas as ideal gas so that the ideal gas law can be applied and the other considers gas as real gas, allowing the gas compressibility factor to come into play. Needless to say, the former method can result in an analytical solution to gas transient flow with a deviation from the real-gas performance, which is very crucial in daily operation. The latter approach requires a numerical method to solve the governing equation, leading to instability issues with a more-accurate result. Our literature review indicated that no study considering the effect of changing gas viscosity on the transient flow was available; therefore, this effect was included in our study. Our investigation showed that viscosity does have a significant influence on gas-transient flow in pipe- and tank-leakage evaluation. In this study, a comprehensive evaluation of all variables was performed to determine the most-important factors in the gas-transient flow. Several case studies were used to illustrate the significance of this study. Engineers can perform a more-reliable evaluation of gas transient flow by following the method we used in our study.
Abstract This paper demonstrates the value of collecting and interpreting real-time data for reservoir surveillance. We present three examples of real-time data acquisition and interpretation. The first example shows how formation pressure while drilling (FPWD) data provides permeability quantification for placement of a horizontal lateral. Initial performance of the pilot injector confirmed optimum placement of the well demonstrating value of information (VOI) from real-time data acquisition. In addition, pressure data helped in understanding the pressure distribution along the lateral due to support from a nearby gas injector and also in adjustment of mud parameters for drilling. The second example highlights the use of downhole fluid analysis (DFA) to confirm gas breakthrough detected earlier by open hole logs, to estimate gas oil ratio of the producer and help selection of fluid sampling point. Integrated analysis of logs, modular formation-dynamics tester (MDT) pressures, DFA results, flow test data and subsequent PVT analysis of oil provided indication of complex gas movement from injector to producer and provided insight on vertical sweep of gas. The third example demonstrates the use of permanent downhole gauges (PDHG) data for real-time performance monitoring of a maximum reservoir contact (MRC) well. Results of the analysis show clear evidence of voidage balance from nearby MRC injector and underscore the feasibility of field development with water injection in a lower permeability area. Combining the effective well length derived from production logging tool (PLT) data, the example also illustrates pressure /rate deconvolution analysis to determine permeability and skin. Additionally, rate-transient analysis (RTA) is done using rate and high-frequency long-term pressure data to compute permeability, skin and drainage area of the well.
- Asia > Middle East > UAE (0.94)
- North America > United States > Texas (0.93)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 282 > Boris Field (0.99)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > Hibernia Field > Hibernia Formation (0.99)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > Hibernia Field > Avalon Formation (0.99)
- Asia > Indonesia > Java > Central Java > Blora Regency > Asset 4 Area > Trembul Block > Trembul Field > Ngrayong Formation > P1 Well (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- (4 more...)
Fracture Growth Monitoring in Polymer Injectors- Field Examples
Shuaili, Khalfan (Petroleum Development Oman LLC) | Cherukupalli, Pradeep Kumar (Petroleum Development Oman LLC) | Al-Saadi, Faisal Salim (Petroleum Development Oman LLC) | Hashmi, Khalid Al (Petroleum Development Oman LLC) | Jaspers, Henri F (Petroleum Development Oman LLC) | Sen, Subrata (Shell International Exploration and Production Investments B.V)
Abstract The objective of injecting polymer in brown fields is to increase recovery beyond primary and secondary recovery mechanisms. However, generally it is difficult to achieve adequate (viscous) polymer injectivity in depleted sandstone reservoirs without fracturing. Therefore, monitoring fracture propagation is required in order to control vertical conformance and areal sweep and avoid early polymer breakthrough. Different surveillance methods are used to identify the existence and properties of fractures in polymer injectors. Pressure Fall off (PFO) survey data in conjunction with time-lapse temperature surveys are extensively used to determine the fracture dimensions. PFO tests in Polymer injectors have particular characteristics since they are influenced by shear-dependent viscosity seen in non-Newtonian fluids. A specially developed Injection Fall-off (IFO) model was used to determine fracture dimensions which is based on exact semi-analytical solution to the fully transient elliptical fluid flow equation around a closing dynamic fracture developed by Shell, (Van den Hoek 2005), as static fracture models are inadequate. This paper presents different phenomena in polymer injection seen in PFO tests such as fracture closure, the effect in-situ polymer rheology and the detection of the polymer front. The paper demonstrates the effect of liquid-level drop observed in PFO survey in under-pressured reservoirs and its impact on determining fracture and some other reservoir properties. It also shows how plot-overlays of time lapse PFO's for a particular well can be used to track changes in fracture dimensions. All of these are illustrated by a number of field examples of polymer PFO which also demonstrate the calculated fracture dimensions from the data. Finally, some recommended best practices are suggested for fracture monitoring.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)
Value of Well Test in the Determination and Characterization of Natural Fractured Reservoir Properties in Large Onshore Abu Dhabi Carbonate Field
Abdul Rehman, Abdul Samad (Abu Dhabi Company for Onshore Oil Operation (ADCO)) | Kumar, Arun (Abu Dhabi Company for Onshore Oil Operation (ADCO)) | Bejaoui, Riadh (Abu Dhabi Company for Onshore Oil Operation (ADCO)) | Nazarbayev, Nurbek (Abu Dhabi Company for Onshore Oil Operation (ADCO)) | Shuaib, Mohamed (Abu Dhabi Company for Onshore Oil Operation (ADCO)) | Sirat, Manhal (Abu Dhabi Company for Onshore Oil Operation (ADCO)) | Singh, Maniesh (Abu Dhabi Company for Onshore Oil Operation (ADCO)) | Al-Dayyani, Taha (Abu Dhabi Company for Onshore Oil Operation (ADCO)) | Ancuta, Cristian (SENERGY) | Farcasanu, Angelo (SENERGY) | Gholipour, Ali (SENERGY) | Belayneh, Mandefro (SENERGY)
Abstract Identifying natural fractures and assessing their impact on flow behavior in hydrocarbon reservoirs have been one of the key challenges in defining the field development strategy. Failure to correctly represent the natural fractures when working on a reservoir development plan can lead to poor performance and failure to analyze reservoir response. Pressure transient testing is widely recognized as a core competency in the oil industry as it provides subsurface specialists with valuable information regarding the reservoir properties, well connectivity to the reservoir and extent of reach into the reservoir. When borehole image (BHI) data triggers a signal that fractures are seen in wells but flow rates do not show production dominated by fractures, the engineers working on the reservoir need to pay attention to pressure transient tests. Depending on the contrast between fracture permeability and matrix permeability, pressure transient analysis in a fractured reservoir can show clear dual porosity behavior, or the effect can be masked by the wellbore storage. The latter happens when the contrast between the matrix permeability and the fracture permeability is small. The two parameters which characterize a dual porosity model are the storativity ratio, ฯ, and the inter-porosity flow coefficient, ฮป. The average value of ฮป for the vertical wells studied is 25*10, confirming a low contrast between fissure and matrix permeability. For the storativity ratio, a typical value is between 0.001% and 0.1%. An average of 0.03% has been calculated from the well tests. With the results from pressure transient tests, BHI and core description, fractures have been defined as mild with relative low-intensity. Numerical modeling on a field sector was employed to test the impact of the fractures on production.
- Geophysics > Seismic Surveying (0.49)
- Geophysics > Borehole Geophysics (0.48)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (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)
Abstract For robust field development and reservoir management, it is essential to properly identify reservoir uncertainties. In this paper, we present case studies on the analysis of pressure transient data acquired in one of the offshore Abu Dhabi carbonate reservoirs. The complexity of the reservoir creates a number of uncertainties in the pressure transient behavior, making application of conventional analytical solutions insufficient to fully understand the characteristic of the reservoir fluid flow behavior. The field was first developed by drilling vertical/ deviated wells in 1980's and then horizontal sidetrack was conducted to enhance the well productivity and improve sweep efficiency since early 1990's. We reviewed the pressure transient test data throughout the field history including past surveys for original deviated holes. It was found that most tests in original vertical/ deviated holes were conducted under the oil-water two-phase flow due to the early water encroachment from the underlying thick aquifer. A close examination of these tests showed that wellbore effects associated with the oil-water two-phase flow significantly influenced the acquired pressure data masking reservoir responses. We also identified major static and dynamic uncertainties complicating the pressure transient analysis in this field. The major feature of the pressure transient behavior is a decreasing trend of the pressure derivative. Due to a number of uncertainties existing in this field, this behavior can imply more than one geological setting: thick active aquifer, faults, and vertical transmissibility reduction. In each pressure transient analysis, we consequently examined all the identified possible mechanisms adopting different fit-for-purpose analytical and numerical models. The fit-for-purpose modeling was found efficient to evaluate many uncertain factors including geological heterogeneities, multi-phase flow effects, and even the pressure interference from neighboring wells. This approach considering all the possible mechanisms enabled us to understand remaining reservoir uncertainties to be further investigated. In other words, this study is useful to identify major reservoir uncertainties and consider further reservoir surveillance to reduce such remaining uncertainties.
An Interference Test Coupled with a Drawdown Analysis of Horizontal Well using a Multi-phase Flow Meter to Evaluate Reservoir Parameters and Connectivity
Al-Farhan, Farhan (Kuwait Foreign Petroleum Exploration Co.) | Gazi, Naz (Kuwait Oil Company) | Al-Humoud, Jamal (Kuwait Oil Company) | Tirkey, Naween (Kuwait Oil Company) | Haryono, Rafiq (Kuwait Oil Company)
Abstract Interference testing, although primitive in terms of its introduction and idea to the petroleum industry, still stands to this day as one of the most cost effective and efficient ways of confirming communication and evaluating reservoir properties between wells. Similarly, a pressure build-up is one of the most accurate ways of estimating dynamic reservoir parameters surrounding the well, providing that the shut-in of the well is allowable. On the other hand, a drawdown test is not usually recommended due to the instability of the flow rate, and hence, the uncertainty in the parameter estimation when analyzing the transient of the pressure drawdown. In this project, due to production constraints a drawdown test was run for the active horizontal well as a substitute to the pressure build-up. It was therefore decided to couple the drawdown test with an interference test so as highlight the subsurface uncertainties. In order to achieve these objectives, careful design and operational coordination between the different asset teams and contractors is crucial to obtain interpretable and useful data. Water production was observed in some of the nearby wells, and therefore communication between the horizontal well and the surrounding wells needed to be verified. The main objective of this project was to evaluate the reservoir parameters and connectivity surrounding the important horizontal well. In this test, the horizontal well was the active well in a five well interference test. The results of the test indicated different pressure behaviors seen from the observation wells corresponding to the pulse created by the horizontal well. Communication was established in some of the wells, whereas, faults were also verified in the surrounding regions. In addition, the drawdown analysis of the horizontal well showed all the flow regimes that relate to a horizontal wellsโ signature as well as boundary behavior which coincide with the interference test results. The results of the drawdown analysis indicate the possibility and accuracy of conducting a pressure transient analysis using this method without being constrained with production objectives, and hence not shutting the well in.
- Geology > Sedimentary Geology > Depositional Environment (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.47)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
- (13 more...)
- Well Drilling > Drilling Operations > Directional drilling (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)
Abstract During hydraulic fracturing process, different hydraulic loading and stress status of formations result in hydraulic fractures with various geometries and properties. Several propagation models including PKN and KGD have been widely applied in fracturing design and implementation. However, in the process of post-stimulation modeling, fractures are usually simplified with uniform geometries and conductivity distribution; therefore the effects of actual fracture geometry and proppant properties on the well transient pressure and production performance remain unclear. This study intends to comprehensively study the fractured wells with 2-D and 3-D non-uniform geometry and conductivity distribution. In the development of shale gas reservoirs and tight oil formations, horizontal well multistage fracturing is the key technology. The modeling results presented in this paper can help offer valuable information of reservoir properties, evaluate the conductivity distribution of propped fractures, simulate more realistic fracture configurations, and help optimize fracture treatment process and fractured wellsโ performances with improved accuracy. A semi-analytical approach coupling fluid flow in reservoir and fractures existed in more realistic shape with non-uniform conductivity distribution has been developed to obtain well transient pressure and production responses. Source and sink function method is utilized to solve unsteady state flow problems of fluid flowing from reservoir to non-uniform fractures with geometries that are well defined in PKN, KGD and other generally ideal models. The effect of fracture conductivity with linear and stepwise distribution, and elliptic fracture shape variations has been investigated. Comparison study has been highlighted to illustrate effects of fracture geometry and conductivity distributions. Realistic hydraulic fractured wells with non-uniform fracture geometry and conductivity have been studied to showcase a consistent workflow of entering fracture properties from hydraulic fracturing models and outputting fractured well performance prediction in post-stimulation reservoirs. Instead of assuming pseudo-steady state flow status between reservoir and fracture, unsteady state flow problems related to non-uniform fracture geometric have been solved in a semi-analytical manner with solution of near analytical accuracy. More realistic fracture geometries estimated from fracture propagation models can be entered into post-stimulation models without idealized simplification; thus the gap between fracture propagation and post-stimulation modeling has been fulfilled.
Abstract A common way to produce hydrocarbons from tight reservoirs is to use horizontal wells with multiple hydraulic fractures. In many cases, fractures do not have a simple bi-wing shape, but are branched. For modeling purposes, branch-fracturing can be represented by a high permeability region near each fracture, while the bulk of the space between the fractures remains unstimulated. This paper presents an analytical model to simulate the flow rate and pressures for such a reservoir system. The model is a variation on the tri-linear flow solution. It is simple, and flexible enough to be applicable to multi-frac horizontal wells. The model takes into account three linear flow regimes: flow within the fracture (at very early time), flow within the stimulated region towards the fracture and flow within the un-stimulated region towards stimulated region. The model was validated by comparing its results with synthetic data sets generated using numerical simulation; the results showed excellent agreement. This paper illustrates the various flow regimes and how they are affected by reservoir and completion parameters. The characteristic features of each flow regime are demonstrated using typecurves. History matching of actual field case is presented to illustrate the practicality of the model. The proposed analytical solution provides a practical alternative to numerical solutions, and saves significant computational time.
- North America > United States (1.00)
- North America > Canada > Alberta (0.28)
The Bakken formation in the Williston Basin has been rapidly developing since 1980s; however, the recent advancements in horizontal well completion and stimulation technology play a key role in the success of today's Bakken production. Pressure buildup tests, mini-DSTs and mini-frac tests are valuable sources of information for determining key reservoir properties, such as permeability. The Bakken formation is comprised of an upper and a lower organic-rich black shale and a middle silty dolostone or dolomitic siltstone, and sandstone member. The Bakken is overlain by the Lodgepole formation which consists of a dense, dark gray to brownish gray limestone and a gray calcareous shale and underlain by the Three Forks formation which is composed of thinly interbedded greenish gray and reddish brown shale, light brown to yellow gray dolostone, gray to brown siltstone, quartzite sandstone and minor occurrences of anhydrite (Kume, 1963). Historically, horizontal wells in the Bakken were drilled in the Upper Bakken formation while the recent developments have changed the focus to the Middle Bakken and Three Forks formations. Historically, when a reservoir interval has been productive it has been attributed to natural fractures (Murray, 1968). Natural fractures include regional fractures, local stress fractures and local micro-fractures resulting from pore fluid over-pressuring. Although fractures are typically determined by examining cores, image logs, and structural curvature, pressure transient tests could provide additional insight in deciphering the presence of fractures and their flow contribution.
- North America > United States > North Dakota (1.00)
- North America > Canada (1.00)