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.
Saudi Arabian non associate gas reservoirs produce various amounts of condensate depending upon field and reservoir. In most cases, these wells are hydraulically fractured and at the initial stage after such stimulation treatment, each well needs to unload high quantity of the pumped fluid to ensure full potential. If the liquid starts accumulating in the wellbore during production, the well productivity will gradually decrease and eventually may stop producing. If the gas flow velocity in the production string is high enough, the gas will continue flowing and will carry the liquid droplets up the wellbore to the surface. The minimum velocity and critical gas rate (Qcrit) are therefore the determining factors while producing a well or several wells from a condensate-rich field so as to ensure the stable field production rate and maintain production plateau.
An analytical model has been developed to iteratively compute the critical velocity (Vcrit) and Qcrit, for given flowing wellhead pressure (FWHP), tubing diameter, and many other reservoir and completion properties. If the FWHP is set and a certain production rate is expected of a well, the program automatically computes the pressure drop due to friction, dynamic hydrostatic head, and the bottomhole pressure. Simultaneously, both Vcrit and Qcrit to unload the fluids are calculated. If the Qcrit is above the expected production rate, a different wellbore completion is automatically selected and computation is continued until Qcrit is lower than the expected rate of the well. If this is not possible, the program will display appropriate message.
Several wells from a condensate gas reservoir are analyzed from a field that has to maintain certain production potential for a given number of years. The analyses show that the wells that are producing without intervention are those that are confirmed by this model to be flowing above the Qcrit. For wells that were intermittently producing and ultimately could not sustain production were producing at rates below the critical values. Using this iterative model, those rates are automatically adjusted or new completion string is suggested to bring them back into production.
The high-profile blowout at Macondo well in the US Gulf of Mexico, brought the challenges and the risks of drilling into high-pressure, high-temperature (HPHT) fields increasingly into focus. Technology, HSE, new standards, such as new API procedures, and educating the crew seem to be vital in developing HPHT resources. High-pressure high-temperature fields broadly exist in Gulf of Mexico, North Sea, South East Asia, Africa, China and Middle East. Almost a quarter of HPHT operations worldwide is expected to happen in American continent and the majority of that solely in North America. Oil major companies have identified key challenges in HPHT development and production, and service providers have offered insights regarding current or planned technologies to meet these challenges. Drilling into some shale plays such as Haynesville or deep formations and producing oil and gas at HPHT condition, have been crucially challenging. Therefore, companies are compelled to meet or exceed a vast array of environmental, health and safety standards.
This paper, as a simplified summary of the current status of HPHT global market, clarifies the existing technological gaps in the field of HPHT drilling, cementing and completion. It also contains the necessary knowledge that every engineer or geoscientist might need to know about high pressure high temperature wells. This study, not only reviews the reports from the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) and important case studies of HPHT operations around the globe but also compiles the technical solutions to better maneuver in the HPHT market. Finally, the HPHT related priorities of National Energy Technology Laboratories (NETL), operated by the US Department of Energy (DOE), and DeepStar, as a strong mix of large and mid-size operators are investigated.
The significance of exploring deep and ultra-deep wells is increasing rapidly to meet the increased global demands on oil and gas. Drilling at such depth introduces a wide range of difficult challenges and issues. One of the challenges is the negative impact on the drilling fluids rheological properties when exposed to high pressure high temperature (HPHT) conditions and/or becoming contaminated with salts, which are common in deep drilling or in offshore operations.
The drilling engineer must have a good estimate for the values of rheological characteristics of a drilling fluid, such as viscosity, yield point and gel strength, and that is extremely important for a successful drilling operation. In this research work, experiments were conducted on water-based muds with different salinity contents, from ambient conditions up to very elevated pressures and temperatures.
In these experiments, water based drilling fluids containing different types of salt (NaCl and KCl) and at different concentrations were tested by a state-of-the-art high pressure high temperature viscometer. In this paper, the effect of different electrolysis (NaCl and KCl) at elevated pressures (up to 35,000 psi) and elevated temperatures (up to 450 ºF) on the viscosity of water based mud has been presented.
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.
For burst design, engineers routinely assume that the casing annular space is filled by a fluid equivalent. This assumption ignores mechanical resistance provided by solid cement. Some studies addressed this shortcoming by modeling the cement sheath as a solid with elastic failure criteria. Prior work used cement elastic modulus and Poisson's ratio to classify cement as "ductile" (soft) or "brittle" (hard). In the current study, numerical results from finite-element analysis (FEA) indicate that casing burst resistance is increased by the presence of the cement sheath. This study focuses solely on improvement offered by the cement sheath to casing burst resistance and ignores consequences of cement failure on overallwell integrity. Comparisons are provided for casing burst resistance, assuming various backup profiles. These include fluid hydrostatics, solid cement matrix (both elastic and plastic response), and cement as "loose" particles. The fluid hydrostatics include mud weight in hole, cement-slurry density, mixed-water density; normal pressure (saltwater column), and actual pore pressure. Calculations show that these fluid profiles are conservative when used as burst-resistance backup. Original cement-slurry density is least conservative. Because well designers are familiar with fluid profile backup assumptions in casing burst design, recommendations are provided to approximate cement behavior as particles with a fluid profile. This allows ease of calculation and is consistent with current practice. Guidelines are provided to explicitly calculate the enhanced casing burst resistance caused by the particulate cement.
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.
Producing hydrocarbon directly from the early mature source rock is becoming a subject of interest for Abu Dhabi National Oil Company (ADNOC) in recent years. The maturation modeling done in ADNOC for the Cenomanian Shilaif formation indicated the presence of early mature kitchens in the offshore and southern onshore synclines. Another maturation modeling showed that the Oxfordian Diyab Formation is also prospective mainly in the northwestern offshore area of Abu Dhabi.
Several conventional stimulation attempts were made in order to produce hydrocarbon from these source rock intervals encouraged by strong hydrocarbon shows while drilling and high hydrocarbon saturation from interpreted logs. Unfortunately, no successful results were obtained during all previous trials.
A volumetric calculation showed that the estimated volume of the hydrocarbon available in these new areas is significant and once a successful production method is implemented, an economical hydrocarbon recovery can be obtained.
In 2011, ADNOC drilled one well in the onshore area of Abu Dhabi. A secondary objective of the well was to test productivity of Diyab source rock and for the first time in Abu Dhabi a new approach was planned and implemented to produce these source rock intervals.
Due to logistical issues, the original testing design was not excuted, and a re-designed program was performed with the available equipments on site to prove the concept of producing hydrocarbon from such formations.
Promising results of gas and condensate were obtained and assuming much better results if the well is drilled in the optimum potential location in the most northwestern onshore area of Abu Dhabi.
In this paper, we will explain both the geological aspects of the potential Diyab source rocks in Abu Dhabi and the planned program, difficulties, executions and results of the new approached stimulation.
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.