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.
Facies modeling forms an integral part of geological numerical modeling. Over the last two decades, different facies modeling methods have been developed using geostatistical algorithms. Most of these methods rely on the assumption of discrete or binary modeling during which each model cell is assigned a single facies. In this study, the size of the cells is on average 100 meters by 100 meters laterally by one meter thick. Based on comparisons to outcrops and subsurface data, such cells should, in fact, include a mixture of facies.
The discrete-facies approach assumes a single facies per cell. The distribution of the facies between wells is described using classical categorical geostatistical algorithms. Reservoir properties are then populated by facies within mapped environments of deposition. This process is well-established and straightforward, especially with regard to tying well data, handling property trends, and applying net rock cut-offs.
A mixed-facies approach can be performed using effective property modeling in which multiple small, fine-scale models are built for each environment of deposition. These models are re-sampled to the full-field cell volume using static and flow-based upscaling methods. The resulting statistics are then used with geostatistics, conditioned to the proportion of each facies present, to populate the full-field model. Such models allow the incorporation of core-scale heterogeneity potentially important in improved oil recovery projects, and may reduce modeling cycle times, especially when multiple iterations are required, such as during history-matching or uncertainty analysis.
This paper compares the impact on simulated fluid flow of modeling facies using discrete modeling versus a mix of facies per cell. Shoreface and subordinate fluvial environments of deposition facies, and five reservoir lithofacies, were modeled.
Fluid-flow simulation of the mixed-facies model, under both primary depletion and pressure maintenance conditions, was smooth and uniform, with a highly conformable flood front. The discrete model was more stratified, with faster and less conformable water movement.
The assignment of discrete facies to large model cells (few hundred meters laterally & few meters vertically) takes less time than a mixed-facies approach and does a better job of preserving organized extremes of permeability important at the production timescale. In the early stages of field development, when there is much uncertainty and a rapid, scenario-based modeling approach is desirable, the discrete approach can be used to flag heterogeneity-related risks more quickly and confidently than the mixed-facies technique. Inaccuracies in performance parameters resulting from the assignment of unscaled discrete values can be corrected using fine-scale sector models tailored to the highest risk cases.
The reliability of the estimated parameters in well test analysis depends on the accuracy of measured data. Early time data are usually controlled by the wellbore storage effect. However, this effect may last for the pseudo-radial flow or the boundary dominated flow. Eliminating this effect is an option for restoring the real data. Using the data with this effect is another option that can be used successfully for reservoir characterization.
This paper introduces a new technique for interpreting the pressure behavior of horizontal wells and fractured formations with wellbore storage. A new analytical model describes the early time data has been derived for both horizontal wells and horizontal wells intersecting multiple hydraulic fractures. Several models for the relationships of the peak points with the pressure, pressure derivative and time have been proposed in this study for different wellbore storage coefficients. A complete set of type curves has been included for different wellbore lengths, skin factors and wellbore storage coefficients. The study has shown that early radial flow for short to moderate horizontal wells is the most affected flow regime by the wellbore storage. For long horizontal wells, the early linear flow is the most affected flow regime by the wellbore storage effect.
The most important finding in this study is the ability to run a short test and use the early time data only for characterizing the formation. This means there is no need to run a long time test to reach the pseudo-steady state. Therefore, from the wellbore storage dominated flow, the early radial and pseudo-radial flow can be established for horizontal wells and hydraulic fractured formations. A step-by-step procedure for analyzing pressure tests using the analytical models (TDS) and the type curves is also included in this paper for several numerical examples.
Offshore production of heavy oil can be challenging due largely to adverse fluid properties, sand production and flow assurance concerns. Recent technology advancements effectively driving management of these challenges and government support through tax relief have significantly contributed to the increased appraisal activity over the last several years in the North Sea heavy oil fields. Application of appropriate technologies and techniques has always been of paramount importance for acquiring high quality information throughout welltest for reservoir characterization at appraisal stage of the fields. It also provides high level of confidence in technology and "proof of concept?? prior to further application in a full field development at investment intensive offshore operating environment.
This paper describes an integrated approach in analytical modeling and design developed and applied in the planning of flow test in a number of North Sea heavy oil fields. This includes a comprehensive pre-evaluation of well productivity, PVT properties modeling as well as design and selection of appropriate artificial lift method. A series of technical solutions considered relevant in relation to enhancing the low flowing well head temperature conditions, typically observed during the cold heavy oil production offshore and often leading to operational constraints on fluid handling capabilities is also discussed. Additionally, a probablistic approach considering base case, low and high case scenarios has been developed and implemented as part of the evaluation process, given the limited amount of available information and high level of uncertainties.
The study demonstrates the benefits of applying analytical techniques for uncertainties handling during flow test planning and thereby enabling accentuation of potential issues, properly planning for mitigation actions and predicting the entire flow test sequence. Finally the study underlines some important guidelines pertaining to planning for further appraisal and development of new heavy oil fields.
Turkey, Laila (KOC) | Hafez, Karam Mohamed (KOC) | Vigier, Louise (Beicip) | Chimmalgi, Vishvanath Shivappa (Kuwait Oil Company) | Dashti, Hameeda Hussain (Kuwait Oil Company) | Datta, Kalyanbrata (KOC) | Knight, Roger (KOC) | Lefebvre, Christian (Beicip-Franlab) | Bond, Deryck John (Kuwait Oil Company) | Al-qattan, Abrar (KOC) | Al-Jadi, Manayer (Kuwait Oil Company) | De Medeiros, Maitre (Beicip) | Al-Kandari, Ibrahim (Kuwait Oil Company)
A pilot water flood was carried out in the Marrat reservoir in the Magwa Field. The main aim of this pilot was to allow an assessment of the ability to sustain injection, better understand reservoir characteristics. A sector model was built to help with this task.
An evaluation of the injectivity in Magwa Marrat reservoir was performed with particular attention to studying how injectivity varied as injected water quality was changed. This was done using modified Hall Plots, injection logs, flow logs and time lapse temperature logs.
Data acquisition during the course of the pilot was used to better understand reservoir heterogeneity. This included the acquisition of pressure transient and interference data, multiple production and injection logs, temperature logging, monitoring production water chemistry, the use of tracers and a re-evaluation of the log and core data to better understand to role of fractures.
A geological model using detailed reservoir characterization and a 3D discrete fracture network model was constructed. Fracture corridors were derived from fractured lineaments interpreted from different seismic attribute maps:
A sector model of the pilot flood area was then derived and used to integrate the results of the surveillance data. The main output is to develop an understanding of the natural fracture system occurring in the different units of the Marrat reservoir and to characterize their organization and distribution. The lessons learned from this sector modeling work will then be integrated in the Marrat full field study.
The work described here shows how pilot water flood results can be used to reduce risk related to both injectivity and to reservoir heterogeneity in the secondary development of a major reservoir.
Oil or gas effective and relative permeabilities can be reduced to a great extent due to the invading liquid phase of the drill-in or completion fluid, contrary to the misconception that formation damage is less of a concern in lower permeability reservoirs (e.g., less than 5 md). Many laboratory, well logging, and formation tester data proved that mud filtrate (both from water- and oil-based muds) can deeply invade the formation enhanced by capillary forces. This will result in reduction of the oil or gas effective permeability, especially if the formation exhibits fluid emulsion blocks and phase trapping. Unfavorable interaction of the filtrate with the reservoir fluids and rock minerals can generate emulsions and precipitates. The same scenario may occur in hydraulically fractured formations.
An integrated multidisciplinary approach is pursued in this study to evaluate formation damage/remediation potential of low permeability reservoirs. The techniques involve different formation evaluation methods including core analysis, well logging, and well testing along with various cleanup scenarios. Furthermore, results from petrographic analysis and laboratory experiments (Micro and Macroscopic scales) are related and correlated with the larger Mesoscopic and Megascopic scales of well logs and well testing, respectively.
Results of these efforts lead to the following technical contributions; a) Delineation of the low permeability heterogeneous reservoirs, e.g. the Leduce carbonates, into their hydraulic units. b) Determination of the undamaged formation absolute and relative permeabilities along with the diameter of filtrate invasion. c) A rule of thumb is to minimize or prevent damage from taking place by selecting a drilling fluid that quickly forms an easily removable mudcake. d) Cleaning up damage due to water filtrate may be accomplished by just flowing the well and can be accelerated using solvents or surfactants. However, once the formation reaches its irreducible water saturation, remediating water saturation below the irreducible value may not significantly improve its permeability.
Malik, Saeed Aslam (Oil & Gas Development Company Limited) | Channa, Munsif Hussain (Oil & Gas Development Company Limited) | Majeed, Arshad (Oil & Gas Development Company Limited) | Latif, Muhammad Khalid (Oil & Gas Development Company Limited) | Asrar, Muhammad (Weatherford)
During this period of energy crisis in Pakistan every effort is being made to produce every molecule of subsurface hydrocarbons. Particularly, the gas reservoirs which were not brought on production, due to low well deliverability or lack of required technology in the past are being explored and exploited. These include Tight, Low BTU, Sour and Acidic gas reservoirs. Such reservoirs pose specific problems related to drilling, production and development aspects.
This paper depicts drilling and testing of a reservoir which is above sea level and its initial reservoir pressure is approximately 1000 psi below the normal hydrostatic pressure. It is one of the lowest pressure reservoirs of the world which has been drilled with successful flow of gas. Underbalance drilling technology was chosen to drill this challenging reservoir. Primary objective of under balance Drilling (UBD) was to establish reservoir potential by acquiring virgin reservoir characteristics.
Historically, three wells have been drilled to test this reservoir. First two wells were drilled using conventional drilling methodology, both the wells experienced heavy mud loses during drilling and it was difficult to evaluate the production potential of this low pressure reservoir. Afterwards, pay zone of SML in third well X #02 was drilled and tested using Underbalance Drilling technique.
This paper further describes the problems faced by the operator to drill first two wells in terms of mud losses and evaluation of production potential of low pressure reservoir of SML. In conclusion, it was a successful application which happened due to exceptional team work from all project parties. This application has opened new horizons of exploration and production of such reservoirs particularly in Baluchistan and generally in Pakistan.
INTRODUCTION AND BACKGROUND
The E.L of interest is located in Baluchistan province of Pakistan. First well Y # 01 was drilled by another operator back in 1953-54 to depth of 1947 M. This well experienced severe mud losses against carbonates of Habib Rahi (HRL) and Sui Main Limestone (SML), and other down hole problems. Drill Stem tests in SML flowed to maximum of 3 MMSCFD of gas at BHP of 279 Psi. This gas rate was observed after re-perforations, pumping acids and swabbing for many days.
Ilyas, Asad (MOL Pakistan Oil & Gas Co. B.V.) | Arshad, Safwan (MOL Pakistan Oil & Gas Co. B.V.) | Ahmad, Jawad (MOL Pakistan Oil & Gas Co. B.V.) | Khalid, Arsalan (Schlumberger) | Mughal, Muhammad Haroon (Schlumberger)
This paper describes the challenges in determining average reservoir pressures in multi-layer completed wells during the span of their production period. The wells with single production tubing and get comingled flow from different reservoir layers exhibit complex down holeflow profiles. Therefore, it becomes difficult to acquire average pressures of each producing layer separately. Production log data can be utilized in these kinds of wells to calculate average individual layer pressures with the help of Selective Inflow Performance (SIP) technique for better production allocation and also to monitor pressure depletion effects with time.
The SIP provides a mean of establishing the IPR for each rate-producing layer. The well is flowed at several different stabilized surface rates and for each rate, a production log is run across the entire producing interval(s) to record simultaneous profiles of downhole flow rates and flowing pressure. Measured in-situ rates can be converted to surface conditions using PVT data. Although SIP theory only applies to single phase flow, the interpreter can restrict the IPR's computations to a particular phase; only contribution of the selected phase will be taken into account. To each reservoir zone corresponds for each survey/interpretation a couple [rate, pressure], used in the SIP calculation. The different types of IPR equations can be used for SIP interpretation: Straight line, Fetkovitch or C&n, and LIT relations. In the case of a gas wells, the pseudo pressure m(p) can be used instead of the pressure "p?? to estimate the gas potential. Although SIP is a useful technique to estimate average reservoir pressure in multi-layered system, but it has some limitations under certain circumstances.
The Selective Inflow Performance (SIP) technique has been implemented on some of the producing wells in north o f Pakistan. These wells have been completed in multiple producing reservoirs. Initially all these reservoirs were tested separately (with DST) to estimate their reservoir pressures and other parameters. However, due to adapted completion strategy, the producing layers were comingled with the option to monitor each layer's pressure depletion with the help of SIP technique in future. As per reservoir surveillance activity, Production logs are run on routine basis by utilizing SIP method and the same has been utilized for reservoir management and for simulation model updates.
Saleem, Saad (Pakistan Petroleum Limited) | Sattar, Suhail (Pakistan Petroleum Limited) | Shahzad, Atif (Weatherford Oil Tools M.E. Limited) | Ziadat, Wael (Weatherford Oil Tools M.E. Limited) | Sabir, Shahid Majeed (Weatherford Oil Tools M.E. Limited)
The name "Sui?? has become synonymous with natural gas in Pakistan. Sui is Pakistan Petroleum Limited's (PPL) flagship gas field. Commercial exploitation of this field began in 1955.
Two major reservoirs of this field are Sui Main Limestone (SML) and Sui Upper Limestone (SUL). Both the reservoirs have become highly depleted by time. Conventional drilling technologies in these formations result in complete loss of drilling fluid, stuck pipe and severe formation damage issues.
Pakistan Petroleum Limited (PPL) planned to drill a horizontal well Sui-93(M), where target reservoir was Sui Main Limestone (SML). Drilling a horizontal well with conventional drilling techniques can cause a complete loss of drilling fluid. Underbalanced Drilling integrated with electromagnetic telemetry transmission was successfully used to drill this well to a target depth of 2200m MD with complete directional controls. Electromagnetic transmission modeling was performed on the resistivity data of offset wells to determine signal attenuation for Sui-93(M) Well. Based on modeling results it was decided to run an extended range set-up with a downhole antenna.
The main reason for using EM-MWD was to provide real time data for annular pressure (APWD sensor) and directional controls in UBD environment. The APWD (annular pressure while drilling-real time ECD) sensor was considered mandatory to monitor and ensure underbalanced condition while drilling, thereby avoiding significant problems such as lost circulation and stuck pipe.
This paper discusses the planning, results, problems and lessons learned during the first application of the Extended Range EM-MWD (Electromagnetic-Measurement while drilling) technology in Sui-93(M) well.
The application of EM-MWD along with UB technology represents a stepwise progression for improving PPL's ability to exploit mature reservoirs, especially those that are severely depleted like in Sui Gas Field, Pakistan.
Arif, Muhammad (University of Engineering and Technology) | Bhatti, Amanat Ali (University of Engineering and Technology) | Khan, Ahmed Saeed (University of Engineering and Technology) | Haider, Syed Afraz (Kuwait Foreign Petroleum Exploration Company (KUFPEC))
It has long been proved experimentally that the tight gas sands are more pronounced to stress changes as compared to moderate and high permeability reservoirs because of the narrow flow channels of the formation . The consideration of the effect of stress in the evaluation and production performance of tight gas reservoirs is very important in order to make right decisions regarding their development. Due to hydrocarbon production, the effective stress increases causing a reduction in permeability and porosity of the porous medium.
The conventional pressure transient analysis techniques in gas wells based on constant permeability would become unreliable . Consequently, the incorrect evaluation of permeability leads towards wrong decision regarding well stimulation. Also the inflow performance modeling of tight gas reservoirs based on constant permeability will not be corrected as far as evaluation of well's production potential is concerned.
Few studies on tight gas reservoirs considering the effect of stress sensitive permeability used the Raghavan's stress dependent pseudo-pressure approach  for which pressure vs. permeability data was determined experimentally. But, if laboratory data is not available then there is need to develop an analytical approach to generate the pressure vs. permeability data required for the use of stress dependent pseudo-pressure in reservoir evaluation and production performance studies in tight gas reservoirs.
The objective of this paper is to develop an analytical approach, in the absence of lab data, to generate pressure vs. permeability data for the determination of stress dependent pseudo-pressure. This stress dependent pseudo-pressure is used for well test analysis to determine the stress sensitive formation permeability and also to generate production performance in tight gas reservoirs. The developed technique has also been implemented on the field data of a tight gas reservoir to validate the results by using actual well's production history.