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Formation damage caused by drilling-fluid invasion, production, or injection can lead to positive skin factors and affect fluid flow by reducing permeability. When mud filtrate invades the formation surrounding a borehole, it will generally remain in the formation even after the well is cased and perforated. This mud filtrate in the formation reduces the effective permeability to hydrocarbons near the wellbore. It may also cause clays in the formation to swell, reducing the absolute permeability of the formation. In addition, solid particles from the mud may enter the formation and reduce permeability at the formation face.
There are many possible causes of formation damage. In addition to the numerous sources identified in separate articles (see See Also section below), other, less common causes include emulsions and sludges, wettability alteration, bacterial plugging, gas breakout, and water blocks. The presence of emulsions at the surface does not imply the formation of emulsions in the near-wellbore region. Most often, surface emulsions are a result of mixing and shearing that occur in chokes and valves in the flow stream after the fluids have entered the well. It is uncommon to have emulsions and sludges form in the near-wellbore region without the introduction of external chemicals.The
Abstract Acid stimulation in sandstone reservoirs containing significant amount of clays can end up with undesired results due to unexpected reactions between stimulation fluids and formation clays. This paper demonstrates how heavily damaged clay-rich sandstone reservoir completed with cased hole gravel pack (CHGP) in offshore Myanmar can be successfully established for commercial production with organic clay acid stimulation treatment. The formation is laminated dirty sand with very high clay content (up to 30%) and large gross height (>100m MD). Production logging results showed only a small portion of perforated intervals contributing to production. Thus, an appropriate stimulation treatment is required to unlock well potential and prevent screen failures from concentrated flow through a small interval. Given high clay content as well as presence of acid sensitive clays, conventional treatments using HCl as preflush and hydrofluoric (HF) acids as main fluids would result in potential damages from secondary and tertiary reactions. Furthermore, undissolved clays in the critical matrix left over from the treatment would potentially migrate and plug the pore throat. The new acid system was designed to generate small amount of HF in-situ (∼0.1%) at any given time with total strength of 1% HF, which would greatly minimize second and tertiary reactions and also permits acids travel deeper into the formation. Furthermore, the reaction products would react with the clays and physically "welding" the undissolved clays to the surface of the pore spaces permanently and prevent them from migration. The treatment was designed in three stages: 1) screen and gravel pack cleanup using coiled tubing (CT) jetting; 2) injectivity test; 3) main treatment consisting of acetic acids as preflush, and new acid system as main fluids followed by overflush. A newly designed linear gel containing relative permeability modifier was used for diversions. Two underperforming CHGP wells were treated, and both wells yielded 100% increase in productivity with no fine production observed at the surface. The success of the campaign owes to the sophisticated engineering workflow which starts from diagnostic of the damage zone and root-cause of the formation damage, followed by detailed analysis of various skin components using radial numerical reservoir modeling for all the reservoir layers that led to a proper treatment strategy and fluid design based on the damage and formation mineralogy as well as comprehensive laboratory tests. This has helped to minimize the risk of the treatment and eventually unlocked the production from the heavily damaged sandstone reservoir.
Abstract The use of inflow control devices (ICD) have been used to balance flux around wellbores and also delay breakthrough of unwanted fluid into completions.1-2. Inflow-control devices (ICDs) were developed to avoid coning problems in long horizontal wells. The model for the ICD consists of pressure-drop equations from the reservoir, through the screen, the flow conduit, the ICD nozzle, and into the production tubing, along with pressure drop through the lower-completion system.1-2. This technology has been a common practice in the petroleum industry for many years now. This procedure though has been beneficial especially in highly heterogenous small formations, but however causes some pressure drop which does not contribute to additional fluid inflow into the wellbore and this is seen to be an impairment to the productivity of horizontal wells to some extent. In wells that are equipped with ICD, a precise quantification of this additional pressure drop is of paramount importance to completely identify the existence of damage created around the well bore. Many authors have proposed mathematical solutions that can be used to estimate various pseudoskin factor caused by damage, partial completion, slanted well and perforation. No author has researched about productivity loss or skin that may result from the use of inflow control devices. In this work, a 3D numerical model which includes inflow control devices along horizontal wells was used to investigate reservoir and production performances of various ICD nozzle sizes. Different productivity losses from different nozzle sizes were seen as skin. Consequently, a simple equation for calculating this skin due to restricted fluid entry through ICD nozzles was derived. The skin results obtained from this new equation is compared with the result obtained using existing skin equation and the variance is within acceptable limit.
Abstract Acid stimulation is the means of improving the well productivity in hydrocarbon production wells. Carbonate formations are tolerance to wrong acid stimulation practices, and Kuwait reservoirs are not exception. Matrix stimulation for carbonate reservoirs is one of the most frequent operation in KOC. It is always associated with operational and technical challenges in order to select and design the proper stimulation method. The main challenges are selecting the acid type, concentration, dosage and diversion method, besides selecting the most suitable stimulation technique for each individual well and formation. It was important to create an adequate procedure to unify a solution for the faced challenges. Programming a software that provide a full acid stimulation program has been done by KOC Well Surveillance Group "First of its kind in KOC". The software is built based on KOC data base for all carbonate wells. These data went through a sequence of analysis and been grouped based on; reservoir's rock properties, fluid properties, reservoir's pressure/temperature, fluid compatibility, and formation lithology. By using the Software, the user will be able to overcome the mentioned challenges. In addition, the software is able to define the corresponding treatment radius (rs), diverter type (chemical or mechanical diversion, polymer or non-polymer based fluid), pre and post flush dosage and type, and prediction of liquid gain after the well stimulation. As a result, the variation in stimulation designs based on different level of experience and knowledge will be eliminated. Thus, the chemical dosage will be optimized from technical and operational prospective, which will reflect on the job expenses. The software is divided to five windows: two Coiled Tubing windows and two Bullheading windows (Mechanical Diversion and Chemical Diversion), and Matrix Volume Calculator window; which helps to calculate the required treatment dosage in order to cover the desired treated radius, given the casing OD and reservoir porosity.
Abstract Passive inflow control devices (ICDs) can redistribute the fluid influx (rate per unit length) into the well completion by causing additional pressure drops between the sand face and tubing. The aim of ICDs is to provide an increase in oil recovery and/or net present value (NPV) by reducing unwanted fluids. Software tools exist to model all aspects of ICD, reservoir, well and surface facilities. The challenge addressed by this paper is to provide an understanding of the implications for optimal ICD design over the life of the field, by integrating these models in a consistent manner. This paper investigates different aspects of detailed ICD design on horizontal producers, using a wellcentric reservoir model. The ICD designs from the well-centric models were then applied to a full field reservoir model and integrated studies were then completed. This was achieved by linking several existing software to study the interaction between the ICD design, full field reservoir, well and surface network. Various aspects of the integration of these models were simulated including: artificial lift, water injection strategy and surface network. Predictably, well-centric simulations showed that ICD designs are dependent on the objective function that is being maximized. If NPV is to be optimized, designing ICD strength to have higher production from the heel and toe regions of the well may produce better results than attempting to equalize the inflow for the entire well. Integrated studies showed that artificial lift can be beneficial in combination with ICDs, as the ICDs redistributed the fluid influx into the well, yet the liquid rate reduction due to the additional pressure drop from the ICDs was mitigated. Even when ICDs were shown to be beneficial on standalone reservoir/well models, the design and predicted benefit when a surface network is coupled depends on: how the surface network is operated, surface network constraints and the relative water cut of the well which ICDs are applied to in comparison to the other wells in the field. These results show that ICD design and optimization requires an integrated approach to ensure outcomes that are consistent with the reality of the field.
Abstract The dimensionless parameter “skin” is commonly used to describe actual well performance with reference to an ideal case, and a number of analytical correlations have been derived over the years to account for the effect on well productivity caused by well geometry, completion design, formation damage and production rate. In a previous publication (Byrne and McPhee, 2012) we outlined the case for reducing the industry's reliance on analytical skin factors for well performance evaluation, particularly since the various “components” of skin, or “pseudo skins,” are often lumped together, and their interaction and interrelationship are often confused. The concept of well design without recourse to a “total” or lumped skin parameter merits further description. For example, whilst hydraulic fractures may present an opportunity for significant enhancement in well performance, the fact remains that the fractured well itself, while an improvement on the unfractured case, may still not be producing at an optimum rate, especially if there is damage in the formation, at the fracture face or in the proppant pack. An overall total “negative skin,” which arises naturally when characterising the fractured well productivity with reference to an ideal vertical, unfractured well, can actually mask the true well potential. There is a tendency to believe that performance has been optimised but this is simply not the case. If the geometry of the wellbore, including the completion and induced fractures, are relatively well understood and can be described then the well productivity can be modelled based on the system architecture without the need to compare it to some hypothetical simpler geometry. The quantity and location of formation damage can then be imposed on the model to determine the impact of damage in the fracture, at the fracture face and deeper within the formation. This paper will illustrate how an indiscriminate use of skin factors can lead to sub-optimal well design and resulting performance prediction, and how this can be improved by representing the real system geometry as rigorously as possible. Decoupling formation damage from its association with other pseudo skins enables a proper description of the impact of damage and its contribution to well performance.
Abstract Wellbore completions are a key well component and could have a positive or a negative impact on productivity, thus designing a suitable completion and implementing it properly must be a priority for production engineers. Consequently, well productivity indices related to specific completion designs have received much attention in the literature, with analytical and numerical models used for simulating various completion properties. The completion impact on wellbore skin effect, however, is seldom documented. This paper looks at the effect of completion and reservoir characteristics on skin factors, and focuses on perforated, gravel-packed and frac-packed wells. For this study, a commercial black oil simulator was used to simulate different reservoir conditions and completion strategies, and the resulting skin effects were estimated by well test analysis of the corresponding synthetic pressure and rate data. Results show that decreasing perforation density and tunnel length leads to high skin values due to wellbore flow restrictions. Moreover, it shows how a damaged gravel-pack completion coupled with a highly permeable formation results in high skin values that range between 1 and 100. Finally, in frac-pack completions, it is important to find the right balance between formation permeability and proppant permeability in the fracture as well as the permeability contrast between the proppant and the gravel as this dictates how a frac-pack will perform. Thus, depending on permeability of proppant and gravel-pack, skin values for frac-pack completions range between -2.5 to 15
This paper was prepared for presentation at the SPE International Student Paper Contest at the SPE Annual Technical Conference and Exhibition held in Denver, Colorado, USA, 30 October-2 November 2011. This paper was selected for presentation by merit of placement in a regional student paper contest held in the program year preceding the International Student Paper Contest. Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Abstract A program was created that successfully models the way frac sand flows through each perf cluster and erodes it away.
Abstract In long horizontal wells, oil production rate is typically affected by the reservoir heterogeneities, heel-to-toe effect and mobility ratio. The resulting imbalanced production profile may cause early water or gas breakthrough into the wellbore. Once coning occurs, well fluid production may be severely decreased due to limited flow contribution from the toe or from reservoir areas with high flow resistance in the porous media. To eliminate this imbalance, passive inflow control devices (PICDs) are placed in each screen joint or inflow point to balance the production influx profile across the entire lateral length and compensate for permeability variation. PICD performance in producer (oil, gas, and high gas/oil ratio environments) wells under different operational conditions will be presented to show the technical benefits of this technique as well as their improved recovery efficiencies when compared to non-PICD completions. The quantification of the benefits of this completion technique was performed using a fully integrated reservoir simulator where the PICD flow performance characteristic (as a function of fluid properties and geometry), well completion description (packers, blank pipe, gravel pack, annulus flow, etc.) and reservoir simulation are considered. The latest-generation PICD design incorporates an integral sliding sleeve which allows selective isolation of portions of the wellbore during the course of a well's life. Shutting off whole sections that have unacceptably high water and/or gas production using the latest PICD feature is also modeled to show improved recovery performance. This paper details the development of the latest-generation PICD design concept which provides the ability to isolate zones selectively as sections of the completion become uneconomical. Experience from the initial field installations of this new technology will also be discussed.