The well drainage pressure and radius are key parameters of real-time well and reservoir performance optimization, well test design and new wells' location identification. Currently, the primary method of estimating the well drainage radius is buildup tests and their subsequent well test analysis. Such buildup tests are conducted using wireline-run quartz gauges for an extended well shut-in period resulting in deferred production and risky operations.
A calculation method for predicting well/reservoir drainage pressure and radius is proposed based on single-downhole pressure gauge, flowing well parameters and PVT data. The proposed method uses a simple approach and applies established well testing equations on the flowing pressure and rates of a well to estimate its drainage parameters. This method of estimation is therefore not only desirable, but also necessary to eliminate shutting-in producing wells for extended periods; in addition to avoiding the cost and risk associated with the wireline operations. The results of this calculation method has been confirmed against measured downhole, shut-in pressure using wireline run gauges as well as dual gauge completed wells in addition to estimated well parameters from buildup tests.
This paper covers the procedure of the real-time estimation of the well/reservoir drainage pressure and radius in addition to an error estimation method between the measured and calculated parameters. Furthermore, the paper shows the value, applicability and validity of this technique through multiple examples.
The success of recent applications in underbalanced drilling (UBD) and managed pressure drilling (MPD) has accelerated the development of technology in order to optimize drilling operations. The increased number of depleted reservoirs and the necessity for reducing formation damage has also increased the need to apply UBD/MPD to such candidate fields. Several methods used the latest mechanistic multiphase flow models in order to predict bottomhole circulation pressure when performing UBD/MPD operations. A new model is developed that utilizes the latest mechanistic multiphase flow models; the developed model calculates the bottomhole circulation pressure as a function of surface injection rates, choke pressure and time.
The developed model can be used in designing and optimizing UBD/MPD operations in terms of determining the correct injection rate and/or choke pressure. In addition, the developed model is used to utilize the reservoir energy to attain correct bottomhole conditions. The developed model in addition to utilizing the latest mechanistic models also reduce the error in calculating the bottom hole pressure by incorporating an algorithm in which the injection rates are calculated in-situ rather than assuming constant injection rates.
The model is validated against data from literature and against a commercial simulator. Results show that the developed algorithm has increased the accuracy in predicting bottomhole pressure by incorporating the changes in new gas and liquid injection rates.
At Kuwait Oil Company (KOC) most of the ESP wells are running with downhole sensors to enhance the daily monitoring routine and for having a better knowledge of the pumps performances. However, one of the most important parameter of these ESP Wells is only known after a time period within 3-6 months: The Flow Rate. Production Tests are obtained using Multiphase Flow Testing Units which usually last between 4 and 6 hours that are also utilized to conduct some sensitivities such as choke size and motor speed changes. At Well Surveillance Group, a tailored fit model was developed from which the ESP flow rate can be estimated based on the downhole sensor data and basic fluid properties with an overall deviation below 2% (when they are compared to the results obtained from the Testing Unit). In this sense, flow rate monitoring can be performed at any time and flow testing time and associated cost can be reduced among other benefits. The method requires knowing the ESP model and total number of stages installed in the well, and then using the corresponding performance curve of the ESP model usually provided by the manufacturer, the data is processed and the calculation performed. This work aims to show how this model works, advantages, limitations, implementation status and future improvements.
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.
The time taken to safely optimise a reservoir produced by artificial lift can be measured in weeks or months.
Typically the well by well process is as follows:
• Well testing
• Amalgamation of the well test data with down hole gauge and ESP controller data
• Analysis of the data to find the existing operation conditions
• Analysis of the ESP pump curve operating point and optimisation limitations
• Sensitivity studies in software to assess the optimum frequency and WHP
• Notification for the field operations to action the changes
• Further well tests to verify the new production data.
• Analysis of the data to ensure the ESP and well are running optimally and safely at the new set points
New technology enables this process to be performed in real time across the entire reservoir or field, significantly shortening the time to increased production and enabling real time reservoir management.
Each artificially lifted well in the reservoir was equipped with an intelligent data processing device programmed with a real time model of the well. The processors were linked to a central access point where the operation of field could be remotely viewed in real time.
Each well's processor was provided with a target bottom hole flowing pressure to enable the optimum production of the reservoir. The real time system automatically compared the desired target drawdown values with the capability of the pumping system installed in each well, and automatically suggested the optimum operating frequency and well head pressure to achieve the target. Where the lift system was not capable of producing to the target bottom hole pressure, a larger pump was automatically recommended. As production conditions change the system adapted its recommended operating points to compensate and maintain target production.
This paper discusses three case studies where real time optimisation and diagnosis lead to improved production from the reservoir.
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.
Widening supply and demand gap in natural gas industry, the advent of tight gas policy and increasing interest of operators in tight gas sands and shale has opened new venues for development of unconventional plays in Pakistan.
Middle Indus Basin hosts important gas fields of Pakistan. Most of the wells in this basin are completed in conventional lower Goru Sands. Lower Goru formation consists of inter-bedded sequences of sands and shale. Its unconventional sand and shale plays hold immense potential which has not yet been exploited due to lack of technology and promising economics. Moreover, Sembar shale is the well known source rock in this basin holding large shale gas potential. GIIP estimates for Lower Goru tight sands excluding the shale prospects are 8.4 TCF which are considered pessimistic due to lack of data in many fields.
From the currently suspended or abandoned wellbores of the Middle Indus Basin, a pilot project needs to be defined in each of the fields, to prove the technical and economical feasibility of tight Gas Potential of the Basin. Commencement of production from unconventional sands will enhance the production in a cost effective manner due to availability of infrastructure and facilities.
This paper focuses on the utilization of existing wellbores as well as data set and highlighting additional data acquisition requirements coupled with completion and multi-stage fracturing techniques for designing a pilot project. Case study of a pilot project in one of the fields of this basin is discussed. It encompasses the basic workflow, candidate selection criterion, Geo-mechanics, sector modeling, hydraulic fracture design and risk evaluation coupled with its use in full field development projects.
Background and Introduction
Pakistan's last year 2010-2011 production was about 3.91bcf/d, while its demand was (4.2bcf/d) and supply gap was also started. Since then the production from the conventional fields has decreased, while demand has been increased due to infrastructure and human needs. This huge shortfall in the gas market cannot be fulfilled with existing number of completions/producers. The conventional reserves of the country were 56 TCF out of which the country has already produced 50% of its conventional reserves. The recoverable remaining reserves are 24-28TCF, but will be produced at much lower production rate and in much longer period of time. The country has an infrastructure of Gas Processing Facilities 5bcf/d.
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.