In this paper, based on our analytical model, we analyze the transient pressure response of a naturally fractured reservoir with pressure dependent rock properties. ABSTRACTThe most commonly used methods to describe the transient flow behavior in porous media are based on the assumption of constant rock properties. Nevertheless, these methods are not strictly applicable to reservoirs that undergo changes in the rock properties due to variation in pore pressure. A frequent characteristic of fractured reservoirs is sensitivity of permeability and porosity to effective stress. This paper presents a new analytical model, for interpreting pressure transient test. The model considers the flow in a naturally fractured stress sensitive reservoir, that is to say, the dependency of rock properties on pressure is established (dependency of permeability on pore pressure is measured by the permeability modulus parameter), and makes that the flow equation be strongly non linear. Likewise, the theory is developed under unsteady-state or pseudosteady-state conditions, and considers that: the fracture is uniformly distributed, matrix geometry is the so called stratum and flow contribution from the matrix to the fracture is described by the term source proposed by De Swaan.The problem stated is solved through an analytical approach for different boundary conditions and different permeability modulus values, thus obtaining type curves that can be used for the analysis of pressure buildup and drawdown tests.

Most of the reservoirs in Ecuador are in mature fields with subhydrostatic pressure. To produce from these reservoirs, an artificial lift system must be included as part of the completion, and stimulation treatments are frequently required to produce economically.Hydraulic fracturing is commonly applied today to remove formation damage, since the penetration of the matrix treatments sometimes is not enough to fully bypass the damage zone because of the depletion. However, in the U formation, after performing fracturing treatments, the maximum drawdown is limited to ensure proppant pack stability. Proppant flowback has been an issue in the first wells hydraulically fractured. Apart from the production limitations, the consequences of proppant flowback may include: decreasing of fracture conductivity, damage to surface and downhole equipment, additional operational cost, and loss of workover efficiency, one of the main factors affecting the Ecuador oil industry scenario.All these consequences have created the need for a new approach to be able to produce these well economically without the mentioned issues. An innovative fiber-based technology for proppant flowback control (FBPFC) was proposed. At surface, low concentrations of short fibers are easily dispersed into the fracturing slurry. Meanwhile, at downhole conditions, the fibers are activated by temperature, becoming sticky and bonding with each other to create a continuous web that consolidates the proppant pack. The fiber web has negligible effect on conductivity, creating a stable proppant pack that is resistant to cyclic stress loading. This translates into higher drawdown and productivity.The novel FBPFC technique has been successfully implemented in Ecuador, after determining the associated risk of proppant flowback, based on the geomechanical reservoir properties. More than 30 stages have been pumped with this technique without proppant flowback despite optimizing the drawdown after the treatments. This resulted in a four-to five-fold increase in production compared with a two-to three-fold increase in wells where the bottomhole flowing pressure was limited by the risk of proppant flow back. The use of FBPFC enabled the full potential of the reservoir to be realized.

Production and recoverable reserves of mature oilfields can be increased through the application of Production enhancement and optimization techniques. In the Napo reservoir, where an important percentage of the total production comes from highly depleted sands with moderate permeability and high clay contents, the implementation of hydraulic fracturing stimulation, with the simple objective of skin by-pass is generally accepted, however the production performance and decline after these conventional treatments is not optimal, due to subsequent fracture conductivity impairment caused by clay and fines migration issues, which is the primary formation damage mechanism. For this reservoir, with a clearly identified damage mechanism combined with moderate permeability and significantly low reservoir pressure gradients (down to 0.1 psi/ft) a fit-for-purpose strategy to successfully stimulate and obtain sustained production was required. A xthorough multidisciplinary study and well screening was carried out to identify the best candidates. This task incorporated petro-physical, stratigraphic, completion and production history analysis, as well as enhanced Hydraulic Fracturing modeling for dedicated optimum fracture geometry and treating fluid selection. The study presented on this paper shows the workflow followed of the candidate selection, treatment design, execution and the post-job evaluation and validation methodology implemented on the campaign. Also, well testing before and after stimulation treatments had enabled the validation of the strategy, followed by production monitoring. After 14 months of production it has been proven that this production enhancement strategy has achieved sustained production, with an average production increase of 350% and average post-frac skin values of -3. The post stimulation production conditions have had a positive effect on the run life of electro submergible pumps and the reduction of workover operations.  On Parahuacu and Guanta fields the achievement of a sustained production optimization through the application of a fit-for-purpose hydraulic fracturing strategy has unlocked the reservoir potential, quantifying an incremental production in excess of 390,000 bopd during 14 months after the hydraulic fracturing campaign. After 14 months of the campaign start-up, 990 bopd of incremental production associated to the Hydraulic Fracturing activity, Represents on average 30% the total field production, proving the effectiveness of this technique which is now part of the asset's production optimization strategy.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA geomechanical study for naturally fractured carbonates was performed as part of an integrated study for the Mara Oeste field in Venezuela. The study included working with one paleomagnetically-oriented core in which natural and induced fractures were identified and oriented. Geomechanical static and dynamic laboratory tests were performed, to obtain strength, deformability and failure characteristics of the rocks. The in situ stress field orientation was determined in one well by using special core techniques such as ASR, DSA, AAA and SWAA. Regional information provided by focal mechanism data available in the Maracaibo basin was integrated together with image logs for eleven wells. Natural fractures and breakouts were studied and fracture orientation and in situ stresses were related with geological structures present in the field. A stress orientation map was built with all the available directional information. In situ stress magnitude was estimated by lost-circulation data, extended leakoff test and backanalysis from breakouts. A three-dimensional stress model of the field was performed using a lagrangian finite difference code. The model showed that stress orientation is dependent on geometry of the layers, and faulting can introduce jumps in stress magnitude. Out from the influence of the main faults the model reproduced the regional trend of stresses. Close to the main fault of Mara Oeste, stress rotation was evident both in depth and spatially, particularly at the crest of the folds. The model provided estimates of in situ stress magnitude that can be used to design new wells in blocks with little information.

A robust and efficient least-squares algorithm for parameter estimation in well test analysis is presented. The algorithm parameter estimation in well test analysis is presented. The algorithm is a Levenberg-Marquardt with a "trust region" approach for global convergence along with restriction in the unknown parameters. In this approach, the selection of the step length is not parameters. In this approach, the selection of the step length is not independent on the choice of Marquardt parameter, in contrast with linear search procedure. For a homogeneous reservoir, the algorithm converges to the same result even if each initial guess differs from the final estimates in approximately three orders of magnitude. Compared with the most robust algorithm known up to now (Watson and Lee algorithm), it usually requires about half of the iterations. On the other hand, in cases involving negative skin the convergence is slowed, due to the stronger non-linear character of the problem and the bigger residuals. Introduction In the last decade, non-linear regression techniques along with constrained optimization methods have extensively been used in well test analysis. These procedures ease and enhance the parameter determination process. Iterative numerical comparisons between the observed response and the calculated response obtained from the model system with the unknown parameter values are made. The iteration ends when a numerically acceptable comparison is achieved. This method is therefore objective, more accurate and precise. Besides these advantages, it allows the analysis of complex reservoirs (multilayer, composites, finites, etc.) or of variable flow rate test, which can not be evaluated using conventional techniques. In the past, one of the difficulties in the implementation of the non-line regression algorithms in well test analysis was the evaluation of analytical expressions modeling the reservoir responses. These expressions and their derivatives were only known in the Laplace space. Rosa and Horne showed that by applying the Stehfest numerical inversion algorithm to both the analytical solutions and their derivatives, it is possible to utilize the least-squares technique to fit the experimental pressure data to any reservoir model. Particularly, they studied pressure data to any reservoir model. Particularly, they studied homogeneous, single layer and multi-layer reservoirs producing at constant flow rate. Later, this method was used by Barua and Horne for interpreting thermal recovery well test data. However, the above mentioned analysis procedure presents some practical limitations, such as the need of selecting initial values close to the best final estimates (in the leastsquares sense) in order that the algorithm converge or converge to physically acceptable values. This is mainly due to the weak global convergence of the utilized algorithm. Another difficulty, of different nature, is the convergence to unacceptable values when the study involves statistically dependent parameters. In general, this can happen when there are many parameters involved. Except in the case of a homogeneous reservoir, many reservoir models require the estimation of several parameters. Barua et al. used a modified Newton-type algorithm (Newton-Greenstadt method) in their study of ill-defined parameters. They showed that this procedure is more parameters. They showed that this procedure is more appropriate than the Gauss-type methods in cases where more than one parameter is ill-conditioned. Nevertheless, this algorithm preserves the typical non-global convergence of the second-order methods.