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.
A live oil sample was subjected to a solid detection system (SDS) to measure asphaltene onset point (AOP) at 3850 psi, and asphaltene content of 1.3%. A high-resolution digital camera was used to measure asphaltene particle size distribution. The result showed that asphaltene particles were not uniform in size, but has a normal distribution of 100-120 µm. Asphaltene reversibility to dissolved back into the oil with increasing pressure was only 35% of the original deposition. Two core samples were examined for formation damage due to asphaltene deposition. A Low permeability core showed significant permeability reduction exceeding 50% of its baseline permeability, and the higher permeability core showed less permeability decline, even with the same asphaltene precipitation.
Maqbool, Zohaib (Eastern Testing Services (Pvt.) Ltd.) | Khattak, Kifayat (Eastern Testing Services (Pvt.) Ltd.) | Malik, Javaid Hussain (Eastern Testing Services (Pvt.) Ltd.) | Ahmed, Jawad (MOL Pakistan Oil and Gas Company B.V.)
Well testing is an important tool for field appraisal, field development, reservoir surveillance and management. Some key measurements during well tests are flow rates of individual phases, fluid properties, fluid composition, flowing surface, down hole pressure and temperature etc. Analysis of this data helps in pinpointing where improvements can be made, how the productive potential of the reservoir can be enhanced and where the future investments are to be focused. So production testing campaigns of wells are to be conducted and should be conducted annually or bi-annually to get the aforesaid vital information of the well and the reservoir.
While gathering vital data during production testing, an apprehension is that the hydrocarbon produced and separated on surface should not be flared, as it can cause a huge financial loss and environmental harm. Therefore, a zero flaring concept was adopted during production in which the separated gas was safely and effectively injected back to the production line and the fluids to the storage facility.
In Pakistan, production testing is generally carried out using conventional 1440psi separator and implementing zero flaring concepts. But there are certain limitations associated with the conventional 1440 psi separators available in the country. A few of them are that they cannot be used on wells whose downstream pressure or injection line pressure is greater than the safety limit of 1440 psi separator. They cannot be used on wells with high gas rates greater than the maximum limit of conventional 1440 psi separator which is 60 MMSCFD and the same limitation applies to condensate/oil/water rate as well. For this reason there are certain fields in Northern Pakistan where production testing campaigns with zero flaring cannot be carried out due to the above mentioned limitations of 1440 psi separator.
This paper describes the introduction of the first ever High Pressure (HP) separator in Pakistan. This separator has overcome the limitations due to its high design pressure of 2160 psi and high gas and oil flow rate capacity which in 90 MMSCFD and 13000 bpd respectively. Successful field applications at three different fields in Pakistan are discussed in this paper covering lesson learned and best practices during the operations. Producing wells were tested without flaring or wasting any hydrocarbon which is harmful to environment. All the separated gas was injected back to the high pressure production line which resulted in a huge financial advantage. The application of the non-conventional high pressure separator and implementing zero flaring is proven to be a beneficial solution with huge potential for future applications in Pakistan.
Jardim Neto, Abrahao T. (Baker Hughes) | Prata, Fernando Gaspar M. (Baker Hughes) | Gomez, Julio (Baker Hughes) | Pedroso, Carlos A. (Petrobras) | Martins, Marcio (Petrobras) | Silva, Dayana N. (Petrobras)
Operators developing reservoirs and producing them from deep and ultradeepwater wells are pushing the technical limits regarding horizontal extension. Deepwater wells completed in unconsolidated formations usually have low fracture gradients, severe leakoff zones, and/or significant washouts. Long horizontal open holes, therefore, may become technically difficult or economically unfeasible to gravel-pack with the use of conventional fluids and gravels. Typical completions in offshore Brazil start from a 95=8- or 103=4-in. casing, in which a 51=2-in. premium screen and tubular string is hung along an open hole drilled with an 81=2- or 91=2-in. bit. Horizontal extensions range from 980 to 4,000 ft. A variety of openhole gravel-pack techniques proved to be complex and costly, but ultralightweight (ULW) proppants have enabled simpler and more-cost-effective gravel packing in these longer horizontal open holes. The reduced gravel density allows a significant reduction in pumping rate that avoids fracturing the formation, minimizes fluid loss, and eliminates the risk of premature screenout caused by excessive gravel settling. ULW-proppant technology was introduced to Brazil in 2005 and has been applied successfully to gravel pack wells under extreme conditions such as low fracture gradient, severe fluid loss, and washed-out zones. ProppantULW-1.25 has proved to be effective for packing wells with narrow sections through the openhole interval, frequently found in horizontal wells completed through shale zones that are isolated by reactive packers and/or mechanical external casing packers. ULW-1.75 was introduced in Brazil in 2007 and has largely replaced ULW-1.25 for gravel packing wells in which an improvement in the operational pumping window is required. A combined package comprising ULW-1.75 during the alpha-wave phase and ULW-1.25 during the beta-wave phase is also discussed. This paper summarizes the procedures and results of almost 60 wells that have been gravel packed with the use of ULW-proppant technology pumped for a local operator.
Asphaltene deposition is a major production constraint in several carbonate reservoirs in United Arab Emirates (UAE). The negative effects of asphaltene include plugging of reservoir formation, wellbore, tubing and surface production facilities and causing shutdown of certain wells. Many of these carbonate reservoirs are likely to be parts of a strategic EOR program through gas injection in the near term. However, as gas injection may further exacerbate the asphaltene problem, it is essential to investigate, as a priori, the effects of gas injection on asphaltene precipitation and deposition and this is the motivation for this study.
A critical analysis of the asphaltene problems to be faced in this particular field was carried out with both HC and CO2 gases as likely injectants under reservoir conditions. In doing so, different gas injection scenarios were studied. The results from experimental studies have been interpreted. The effects of gas injection ratio and depressurization speed on asphaltene onset pressure (AOP) have also been carefully studied. The strategy to adopt an equal-time-stepwise depressurization approach in this study yielded a more reliable result than conventional AOP detection method and also helped reduce the experimental time. In addition, asphaltene precipitation growth history and its nature as solids were studied with the aid of a high pressure microscope (HPM).
The asphaltene onset pressure is found to be affected by the way of system depressurization (frequency and time step magnitude) since it has a direct bearing on the stabilization time. Based on this study, a faster and more reliable method of AOP determination by using light scattering technique with near infrared range (NIR) light was proposed. The AOP of oil depends on the volume of injection for both HC and CO2 gases. It is noted that asphaltene deposition envelope enlargs with the increasing volume of injected gas.
Abdelsalam, Hazem Mohamed (Abu Dhabi Co. Onshore Oil Opn.) | Al-Rahma, Rahma Ahmed (Abu Dhabi Co. Onshore Oil Opn.) | Al-Mazrouei, Manal (Abu Dhabi Co. Onshore Oil Opn.) | Al Awlaqi, Salah Ali (Abu Dhabi Co. Onshore Oil Opn.) | Parkinson, Andrew (Abu Dhabi Co. Onshore Oil Opn.) | Kuyken, Chris (Abu Dhabi Co. Onshore Oil Opn.) | Al Menhali, Adnan
In 2011, ADCO embarked on a project of well abandonment in Town field, Located in an urban area approximately 25 km South-East of the main island of Abu Dhabi. Each of the three wells presented individual technical challenges and, due to proximity of the populated areas, complexities with logistics and emergency response planning arose. As well as significant presence of toxic H2S in the Town field reservoirs this categorizes those wells as critical high profile wells. And this necessitated extensive engagement with ADCO coordinating with external authorities of concerned parties' throughout the project.
This paper presents a successful case study and project over view with focus on the Three wells, one well T-09 required measures to be taken to address the Sustainable Annulus Pressure (SAP) in the Casing x Casing annulus SAP(B) as well as address accessibility issues associated with a stuck plug inside the tubing. The other well consider is T-06, which over Ten years before, been plugged & abandoned with cement to surface but had subsequently also developed Sustainable Annulus Pressure between Casing x Casing.
During the past decade, the completion technique used in liquid-rich unconventional plays in North America has undergone a transformation. Today, the vast majority of completions in these areas are open-hole (OH) graduated ball-drop fracturing isolation systems. This preferred completion type for horizontal wells is driven by the efficiency gains in fracturing operations and the production gains when compared to previously used completion techniques. Thousands of open-hole fracturing systems are run each year, with a continuously growing stage count.
Graduated ball-drop type completions rely on a sliding sleeve activated by a ball dropped from surface. Each ball travels the length of the lateral well to its intended operational depth, at which it meets a mated seat and isolates the wellbore below. Once the ball is in position, the sliding sleeve opens via the hydraulic force on the ball and seat, allowing a fracturing stage to commence. This dual function of the ball—activation and sealing—is of extreme importance for the stimulation treatment process. If the ball fails, it will result in bypassed pay zones and unintentional refracturing of previously stimulated zones. Although sometimes surface pressures can be used to infer ball behavior, often the pressure signals observed at surface cannot guarantee successful ball performance.
This paper will present an extensive study of ball performance under pressure for the most common ball materials in the industry. Phenolic, composite and metal alloy materials were explored with the pros and cons for each investigated. In particular three main areas were analyzed: 1) molding, layering and extrusion of material versus inconsistencies in ball performance; 2) ball deformation at high pressure versus pressure required to bring the ball off seat; and 3) comparison of the performance of phenolic, composite and metal alloy materials for ball fabrication and their performance at high temperature.
The conclusions from this paper provide operators the necessary information to consider when making completion and ball material decisions in their field operations. In particular, the results of this testing may illuminate some previously unexplainable occurrences in graduated ball sliding-sleeve systems. This testing clarified that not all fracturing balls pumped in horizontal wells perform equivalently under wellbore fracture conditions.
Rate- and pressure-transient analysis of unconventional gas and oil reservoirs is a challenge because of complex reservoir characteristics that dictate flow. An important flow regime for analysis of these reservoirs is transient linear flow, which can be associated with linear flow to induced hydraulic fractures or to horizontal wells. One of the complications in the analysis of this flow regime is stress-sensitivity of porosity and permeability. This work aims to provide a method for analyzing transient linear flow in reservoirs with stress-sensitive permeability.
Flow of a compressible fluid in a stress-sensitive formation is governed by a nonlinear second order partial differential equation (PDE) with nonlinearities in both the accumulation and flow differential terms. A version of the Kirchhoff transformation is used to make the accumulation term linear, while a monotonically varying nonlinearity (as a function of a new pseudopressure function introduced in this work) exists in the flow differential term. The transformation, however, does not introduce any nonlinearity to the constant-wellbore pressure-condition, which is the case for constant well flow rate.
An exact solution of the transformed nonlinear PDE is provided for pressure distribution and flow rate calculations. The results are compared with approximate solutions in which fluid and rock properties are considered to be constant and evaluated at a specified pressure, as obtained by the error function (erf) solution. The results show that, at the wellbore, the value of the slope of the square-root of time plot (reciprocal of flow rate vs. square-root of time) can be used to calculate one of the two parameters, permeability modulus or initial permeability. This is the case if the derivative of the Kirshhoff parameter with respect to the Boltzmann variable is known for different values of fluid and rock compressibility, permeability modulus, and pressure drawdown. In this study, the Fujita's method is used to calculate the derivative for some ranges of the affecting parameters. The results are presented as plots which can be used for analyzing the production data.
Post-production performance after hydraulic fracturing has been studied for decades. Most of the issues that arise are related to drainage area and low pore pressure after the fracture is created. The goal of hydraulic fracturing is to always try to maintain the original reservoir pressure while still providing the best geometry possible. Treatment options vary, depending on the pressure and capacity of the formation to return fluids pumped to minimize face damage.
Some tight-gas wells respond very well to new, improved fracturing techniques, and proppant-carrying fluids have been continuously modified to reduce damage in the formation. But, for some wells, such as the gas fields in the Burgos basin in North Mexico—located in the North-East area of the country and bordered with South Texas in the USA—problems still persist.
This is especially problematic in unconventional gas reservoirs, such as ultralow-permeability or tight-gas sands. When fracturing, the damage mechanism must be mitigated to help prevent fracture face damage. By reducing fracture face damage caused by the use of conventional surfactants, which absorb rapidly within the first few inches and result in fluid phase trapping, relative permeability, and wettability issues, substantially increased regained permeability can be achieved in unconventional reservoirs, with the primary purpose using surfactant-reducing surface and capillary tension.
This study discusses revised operations where a novel microemulsion (ME) surfactant was used, the fluid recovery that occurred during the cleanout process, and the hydrocarbons production a few months after the stimulation. Also, these wells were compared, as much as possible, to those that received a conventional treatment. Results demonstrate exceptional water recoveries compared with conventional ME surfactant treatments.