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.
Gupta, Shilpi (Schlumberger) | Pandey, Arun (Schlumberger) | Ogra, Konark (Schlumberger) | Sinha, Ravi (Schlumberger) | Chandra, Yogesh (ONGC) | Singh, PP (ONGC) | Koushik, YD (ONGC) | Verma, Vibhor (Schlumberger) | Chaudhary, Sunil (Oil & Natural Gas Corp. Ltd.)
Production logging has been traditionally used for zonal quantification of layers for identification of most obvious workover for water shut off, acid wash or reperforation candidate identification. The basic sensors help in making some of the critical decisions for immediate gain in oil production or reduction in water cut. However, this technology can be used in a non standard format for various purposes including multilayer testing to obtain layer wise permeability and skin factor using pressure and flow rate transient data acquired with production logging tools. This is very crucial and complements the present wellbore flow phenomenon to better understand relative zonal performance of well at any stage of its production. In addition, production logging along with the pulsed neutron technique is very crucial to evaluate the complete wellbore phenomenon, understand some of the behind the production string fluid flow behaviors. Another major concern in low flow rate wells is recirculation, causing fall back of heavier water phase while lighter phase like oil and gas move upwards. This well bore phenomenon renders the quantification from production logging string, and this in extension also prevents any comprehensive workover decisions on the well because of the risk involved. Oil rate computation from hydrocarbon bubble rates becomes very critical in such scenarios to bring out the most optimal results and enhance confidence in workover decisions. Another key concern in any reservoir is to evaluate the productivity Index; this is even more critical once the field is on production. It is essential to determine the performance of various commingled layers and reform the Injector producer strategy for pressure support or immediate workover. Selective Inflow performance is a technique used to identify the Productivity index of various layers in a commingled situation. This paper elaborates on various non conventional uses of production logging from the western offshore India.
Brown field management has been a key focus in the western offshore region. Over the last decade cased hole production logging for evaluation of reservoir phenomenon has been the backbone of workover operation in western offshore India. Besides the usual operations production logging has been pivotal in determining various important parameters for field development. Various unconventional uses require understanding of the tool physics and limitation. Advanced generation of production logging tools not only provide additional information in terms of wellbore flow fractions, slippage velocities and complex flow regimes but their basic outputs can also be utilized in variety of applications for reservoir evaluation and wellbore flow monitoring. Following sections describe several case studies describing unconventional usage of production logging outcomes.
Unconventional Applications of Production Logging
Case Study 1: Selective Inflow Performance
Field wise production logging has always been an excellent source to evaluate the open hole results and suggest some immediate workover to optimise the production. Selective Inflow performance is new variation in the already existing technique used to identify the Productivity index of various layers in a commingled situation. This operation can provide us with the openhole flow potential of the well and thus help in mapping the flow profile in the reservoir. A multichoke production logging survey usually covering two to three choke sizes is performed and flow profiling for each survey is done.
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.
This paper will describe the state of art in active acoustic detection ofoil and gas in the water volume as well as the seafloor. Examples of real datawill be described with the relevance to the leakage detection challenges wheresurveillance and early detection is crucial. Active acoustic data will bepresented from several trials from various parts of the world, examples hereofis California natural seeps, Brazil leakage detection, Norway plume mixingphenomenon's and more.
Applications: Leakage detection on subsea assets, Site surveys of leakages,Oil response capabilities, Oil recovery capabilities, Dispersant efficiencyespecially sub surface, Quantification of leak flux both gas and fluid.
Results, Observations, and Conclusions: Expedition results will be reviewedbased on several real life tests and deployments of active acoustic systems.Conclusion of expected performance of active acoustic systems will be drawn.Miniaturization and adaptation of power requirement as well as uplink demand,combined with sufficient processing to avoid false alarms will bediscussed.
Significance of Subject Matter: Early subsea leakage detection is absolutelykey to any arctic project, quantifiable flux rates is an important key input toall decision-making during operation of oil fields in all regions.
Offshore pipelines are a viable option for the safe transport ofhydrocarbons in the Arctic. For continued safe and cost efficient operation, itis important to ensure integrity as well as minimize field inspection andintervention. This can be achieved through an optimized Inspection andMaintenance (IM) program. Determining the required frequency of IM, in a costefficient manner is critical for ensuring integrity and optimizing inspectionand maintenance costs without compromising safety. For piggable lines, smartpigs are used for In-Line Inspection (ILI). A conservative approach (small IMintervals) can be costly, increases the human / Remotely Operated Vehicle (ROV)exposure and yield little new information. A strategy with too little IM canlead to unexpected failures, as too little information is acquired on thecondition of the pipeline. An optimal IM strategy based on the condition ofpipeline is developed in this paper.
In this paper, major Arctic offshore pipeline integrity challenges areevaluated. Considering these challenges, a Risk Based Integrity Modeling (RBIM)framework has been proposed. Design challenges from the effects of ice gouging,strudel scour, frost heave, permafrost thaw settlement, and upheaval bucklingcan be mitigated through proper trenching and burial, as well as conditionmonitoring during operation. The major integrity challenges during operationmay arise from the progressive structural deterioration processes and changesin the right-of-way seabed conditions. The structural deterioration processeswill include time-dependent processes such as corrosion, cracking, andpermafrost thaw settlement. Non-time dependent (random) processes, such asthird party damage, ice gouging, strudel scour, and upheaval buckling will poseadditional risk during operation, but are not addressed in this paper. Theseeffects can be partially addressed through ILI and periodic seabed surveyinspections.
The risk to an Arctic offshore pipeline will be evaluated with respect tothe deterioration processes. The risk is estimated as a combination of theprobability of failure and its consequences. The probability of failure isestimated using the Bayesian analysis. Modeling the structural degradationprocesses using Bayesian analysis is not a new concept; however, modelingdegradation processes using non-conjugate pairs is a new technique that isdiscussed in this paper. Bayesian analysis is based on the estimation of prior,likelihood, and posterior probabilities. Field ILI data is used in theanalysis. The posterior models possess better predictive capabilities of futurefailures. The consequences are estimated in terms of the cost of failure andthe planned IM program. Cost of failure includes the cost of lost product, costof shutdown, cost of spill cleanup, cost of environmental damage and liability.Cost of IM includes the cost to access the pipeline, gauge defects, and carryout inspection and necessary minimal maintenance. Implementation of theproposed RBIM will improve pipeline integrity, increase safety, reducepotential shutdowns, and reduce operational costs.
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.
Hole enlargement is a serious problem while drilling in permafrostconditions. The hole enlargement problems leads to lost circulation. Irregularand unstable holes also affect the quality of cement jobs. The drilling fluidis generally at a higher temperature than the permafrost formation. This causesa heat transfer from the drilling fluid to the formation. The ice particlesbinding the sediments together start to melt. This loosens up thesediments and causes caving. This paper proposes to minimize this problem witha low thermal conductivity fluid.
The drilling fluid can be cooled at the surface after it comes out of theannulus and before it is circulated back into the drill string. Cooling reducesthe temperature gradient between the fluid and formation. But this cooling isnot enough since the permafrost is at subzero temperatures and cooling to suchlow temperatures is not economically and practically feasible. This is wherethe innovative drilling fluid comes in. The drilling fluid shall have hollowmicrospheres. These microspheres are easily available commercially undervarious trade names. These microspheres lower the heat transfer coefficient ofthe fluid. This means that a significantly small amount of heat will betransferred from the drilling fluid to the formation. Low temperaturegradient and low thermal conductivity will work in conjunction.
The drilling fluid shall have a low heat transfer coefficient of 2.9-3BTU/hr.ft2.oF. The composition of the fluid and the heattransfer coefficient measuring experimental setup shall be discussed in thepaper. The paper shall also discuss the effects of heat transfer coefficient,circulation rates etc. on the thawing of permafrost.
The technique in this paper could go a long way in mitigating drillingproblems in permafrost regions.
Young Technology Showcase - No abstract available.
Microorganisms play a vital role in many ecological, environmental and engineering phenomena: Examples include plankton blooms in the oceans and bioreactors for algae fuels. In the last decade, the mathematical models and numerical methods used in this field have improved significantly. In this paper, we review recent advances in the simulation of the individual and collective behaviors of swimming microorganisms, as well as discrete modeling of individual microorganisms for simulating large-scale flow structures. Because we have recently reviewed the biomechanical aspects of suspensions of swimming microorganisms (Ishikawa, 2009), we mainly focus on methodological aspects here.
Microorganisms play a vital role in many ecological, environmental and engineering phenomena. Plankton blooms in the oceans, for instance, are at the bottom of the food chain and affect the oceanic ecosystem. They sometimes form harmful red tides in coastal regions of the ocean that cause serious damage to fish farms. Algae in the oceans absorb much CO2, which affects the global climate. Microorganisms are also used in bioreactors for medicine and food, such as bread, cheese and beer. Bioreactors for algae fuels are currently a hot topic because of the worldwide energy crisis, and they have the potential to generate an energy revolution (Service, 2011). Because microorganisms have a considerable influence on the global environment, industry and human life, mathematical models that predict their behavior are an important subject of scientific research. The flow field around a microorganism can be considered a Stokes flow, because the size and swimming velocity of a cell are usually small enough to neglect inertia. In terms of fluid mechanics, then, swimming microorganisms may be modeled as singularities, i.e., multipoles (Kim and Karrila, 1992). When a cell is denser than the surrounding fluid, external force is generated on the cell body.
Arukhe, James Ohioma I (Saudi Aramco) | Al Dhufairi, Mubarak (Saudi Aramco) | Ghamdi, Saleh (Saudi Aramco) | Duthie, Laurie (Saudi Aramco) | Elsherif, Tamer Ahmed (Schlumberger Middle East SA.) | Ahmed, Danish (Schlumberger Middle East SA.)
Two new records exist in one of current world's largest oil increment field development projects in Saudi Arabia. The records set while achieving a well's intervention objectives include; 1. Attaining the deepest coiled tubing (CT) reach for rigless well intervention at 29,897 ft (9.11 km) measured depth in an extended reach open hole horizontal power injector well using a CT tractor and; 2. The first application of real time logging enabled through a wired motor head assembly via the tractor. The intervention objectives were to acid stimulate an open hole completed relatively deep in the reservoir with total depth of 29,897 feet and open hole length of 6,697 feet utilizing 2" CT with open hole tractor, to perform injectivity / falloff test, and to conduct real time logging for evaluating the reservoir's injectivity profile.
The paper examines several challenges that engineers and operators encountered during intervention in this well. A partially sealing high viscosity tar layer exists between the overlaying oil column and underlying aquifer. Operationally, the challenge was to overcome obstructions arising from tar accumulation during the well intervention. This challenge was overcome by the use of a solvent and the well was successfully acidized with the aid of the CT-tractor. The other concern was the tractor integrity while large amount of acid is pumped and the extended exposure time of tractor to acid. The tractor successfully handled huge amounts of corrosive fluids in a sour environment while providing the required pulling force to reach the total depth of the well to set the intervention record for tractor reach without adverse effects on the integrity of its O-rings, seals, and mechanical parts. In addition to organic deposits, azimuth changes in the well added to well entry challenges as a result of changes in hole inclination, doglegs, and azimuth. The application of real time informed decisions was critical in overcoming all the challenges, optimizing stimulation design, and yielding a notable and consistent injectivity increase with evidence of extended life and a true reflection of deep penetration into the damage zone. The successful re-entry will benefit industry operators confronting similar intervention challenges.
An extensive study of the field and its predominant drive mechanism revealed that production and simultaneous peripheral matrix water injection is the preferred depletion strategy. Extended reach wells and relatively complicated trajectories typically characterize the powered water injectors drilled for reservoir pressure maintenance. The injectors will support oil production from one of the largest field developments in the history of Saudi Aramco in the M field. The field development consists of 27 artificial islands linked by 41 kilometers of Causeway spanning the Arabian Gulf Sea. The blend of onshore, offshore, causeway and artificial island construction concept was the optimal field development option for the field because it results in only 30% offshore development and 70% onshore development. The chosen concept for the field development requires water injection wells to provide peripheral matrix water injection as pressure maintenance strategy to support oil production. A tar mat zone characterizes the field. About 65% of the powered water injection wells have lengths greater than 17,000 feet, beyond the normal reach of coiled tubing.