Gravel-pack (GP) completions are used on formations presenting sand-production problems worldwide. The inherent problem with this type of completion is its tendency to become plugged as a result of fines migration, solids invasion, and emulsion problems, which are the most commonly damaged mechanisms affecting productivity. Pumping acid systems is an effective method to solve GP plugging problems but usually results in increased post-treatment water production. Acid will enter zones with higher water saturations, which often are higher permeability, and causes operational problems, such as decreased oil production and increased lifting costs. Historically, various methods for diverting fluids have been used. These methods included the use of viscous fluids, degradable particles, ball sealants and foam. Recently, relative permeability modifiers (RPM) have been used successfully as a diversion system for acid systems to decrease the relative permeability to water. Customized application to clean up GP completions is the presented solution. This paper describes the use of RPM diversion systems that reduce the formation's permeability to water without significant effects on permeability to hydrocarbons. Four GP wells that were treated with this system, resulting in increased hydrocarbon production without increasing water production, are presented in detail. The four wells discussed are located in the same reservoir in Oriente Basin, onshore Ecuador. Wells are placed in formation M-1 Tarapoa Oilfield, which is an unconsolidated sand formation. Sand production has occurred in some of the oil producers. Wells are generally completed with GP screens with sand being pumped to fill the perforations and the wellbore x screen annulus. Well A8 was the first well treated with the acid system diverted with an RPM. Well A8 had a production decline caused by GP plugging, which also affected the ESP equipment performance. After the treatment the well productivity was restored successfully. It was decided to treat three more wells in the same reservoir. These treatments also resulted in a gain in production. Introduction Acid preferentially goes into zones with high water saturation.(Eoff et al. 2004; Eoff and Dalrymple 2003). In heterogeneous production zones where matrix stimulation treatments are normally carried out, the acid tends to enter the area of greatest permeability and leaves the less permeable areas untreated. In this scenario, the water cut increases over time because water travels more easily through the more-permeable water zones. Faced with this problem and the necessity to remove the formation damage in the gravel pack (Schmidt 1996) small volumes of acid without diverters were pumped in an attempt to penetrate only a few inches. Following stimulation, the Productivity Index (PI) increased, partially by increasing the bottomhole pressure but mainly by significant increase in water production. Different types of diverters were later tested to reverse these results. The forms or methods of diversion of fluid wereViscous fluidsDegradableparticlesBall sealantsFoams All these methods have advantages as well as disadvantages, but it is important to mention that none of them were guaranteed not to stimulate the water areas.

A giant oil field consisting of carbonate reservoirs in onshore Abu Dhabi has been provided with long term Field Development Plan, including several Dual Oil Producer (DOP) completions in formations Shuaiba and Kharaib, more specifically in zones A & B to maximize oil recovery. Upper Zone and Lower Zone B have been producing on natural flow using dual completions. This has been possible due to high reservoir pressures available since the beginning of the production. Conditions have changed, especially for the Lower Zone B, and reservoir pressure has been declining for the past years. As a result, several wells ceased to flow mainly due to lower pressure and/or higher water cut conditions. Therefore, Gas Lift has been selected as the preferred artificial lift method in lower zone B. The problem has been identified in current dual wells where Upper Zone is still producing but changing dual into Gas Lift single oil producer in lower zone B will translate into halt in oil production in upper zone, therefore reducing the oil recovery for Upper Zone. This is a consequence of the current practice of plugging and abandoning the Upper Zone. An innovative application for dual oil producer completion with Gas Lift mandrels in long string has been evaluated to keep both zones producing and extend the ultimate oil recovery of the current wells. Candidate selection, including analysis and workflow, will be presented in detail. Moreover, the design process, well modelling and installation will be addressed further in this paper.

Sand production has remained a challenge within the oil industry for many years. Gravel pack completions has been the primary method for addressing sand control in countries like Ecuador where reservoirs with high-permeability unconsolidated formations exist, such as in the Oriental basin. Although gravel packing has been a good solution for addressing sand production, challenges related to well geometry, short net pay, and even cases of corrosion and material failure still exist. For these reasons, research has focused on new techniques to prevent sand production. Chemical sand consolidation can provide additional strength to maximize the sand-free fluid rates. This paper discusses a proposed chemical treatment to consolidate a near-wellbore (NWB) area to remediate a gravel pack completion that had become damaged in Well F21, which produces 22° API oil from the M1 sandstone in T Block, Ecuador, South America. Well F21 was completed using gravel packing in June 1999; but, after more than 10 years, gravel and formation sand became present in the flow stream, causing the electrical submersible pump (ESP) to experience sticking problems, making it almost impossible to produce oil from the well. Chemical sand consolidation using a premixed two-resin component system was tested in the laboratory using the sand formation and gravel samples from the selected well. The laboratory results showed that it was a good alternative to consolidate not only the formation sand, but also the gravel still present in the current completion. In October 2011, the well was intervened, pumping the sand consolidation material using coiled tubing (CT). After treatment, the well was placed back on production with the ESP and initial production was 600 BOPD with no sand. This paper presents a case history of chemical placement and gravel pack completion repair in the Oriental basin. After the treatment, the formation was completely consolidated in the NWB area, with no sand production after well production was reinitiated. The results lead to additional well applications in Ecuador, providing new opportunities to effectively produce unconsolidated sand reservoirs in this basin. Introduction Unconsolidated formations can exhibit typical characteristics that can be evaluated using sonic surveys and rock mechanics laboratory analysis. An extreme unconsolidated formation has a total absence of cement in its pore spaces to create good compressive force; therefore, taking a rock sample for laboratory evaluation can become a difficult task. This particular phase requires novel procedures for evaluation of rock mechanics modules in downhole conditions. Theories, such as Mohr-Coulomb, should be applied to a step rate test. Typically, the sonic survey can provide good evaluation; but, in cases of poor cement bond logs, limitations can arise. A better knowledge of lithology can lead to job optimization to minimize future production loss. Typically, a reservoir with good permeability (more than 350 md) could be good a candidate for sand consolidation. A bigger net pay (more than 60 ft) can present limitations. In cases of gravel pack repair, procedures can be optimized if only a short portion must be fixed. It is necessary to run an image logging tool to evaluate the top and base of the gravel pack. In cases of limited size, other tools can be used to view damaged portions, such as a downhole video camera. In the case history discussed, it was not necessary to run logging tools because of the short gravel pack size and the entire production interval was consolidated.

There are sand formations that do not have a minimum contact pore space cemented. Typically, these sands have very low toughness, high permeability, and high porosity. Such factors allow fines and solids migration. The consequence of this scenario is the increase of workover interventions and equipment damage/erosion caused by sand flow, thus resulting in increasing cost, lost time, and insufficient production. Drilling these formations is challenging. Taking core samples to perform rock mechanic tests in a laboratory is also a difficult task. Additionally, there are cases where wells do not have sonic dipole surveys to help with evaluations. Usually, the samples are not uniform, have cracks, are broken, or completely dispersed, making their application in rock mechanic characterizations impossible. The presented methodology applies the Mohr-Coulomb cycling test for the first time to actually process step-rate, fracturing, and falloff tests. Field tests using this technique have shown good correlations and obtained reliable curves for hydraulic fracturing simulators. A package of rock mechanics equations described in the oil industry are evaluated and tested in field scale. Many times, engineering teams must have a source of equations which can easily calculate required parameters to be used for sieve analysis, gravel pack, and fracture pack projects. Basically, the methodology is reliable because of the equations of theoretical soil mechanics (Terzagui 1943), Mohr-Coulomb, and field practices of determinations of minimum in-situ stresses and overburdens. After field test confirmations, the objective of this matter is to present correlations of Terzagui (1943) and Mohr-Coulomb equations to be used during gravel, fracture pack, and hydraulic fracturing operations. The methodology has an important presence during the study to help minimize risk during these jobs and obtain good approach simulations because, as previously discussed, this type of sandstone makes obtaining formation samples challenging. Equations can provide a good number of useful calculations and help reduce operational risk when performing these types of well completions or treatments.

This case study well is in a mature onshore field, which has been under production for a long time (started in 1970) resulting in depletion of some of the reservoir units presenting challenges for optimizing drilling performance and managing risks associated with stuck-pipe incidents. Additional challenges are minimized surface footprint, 100% reservoir contact in thin targets and acquisition of accurate petrophysical data for formation evaluation. A detailed pre-well study was conducted utilizing historical field and nearby wells’ data in the planning phase with close collaboration in a multi-disciplinary team including well and Bottom Hole Assembly (BHA) design and pre-well modeling for geosteering and LWD tool string configuration taking into account the elimination of radioactive chemical sources. The pre-well study has concluded that the azimuthal deep propagation resistivity image is going to provide proactive geosteering solution to identify the approach to both top and bottom boundaries. The BHA has also included rotary steerable system (RSS) along with optimized Logging While Drilling technologies (LWD) which has included, high-resolution micro resistivity imaging, Laterolog resistivity, nuclear magnetic resonance (NMR), sonic caliper and near-bit gamma ray. Continuous real-time monitoring provided drilling performance monitoring and analysis as well as facilitating geosteering services. The 8,356 feet horizontal section was effectively geosteered with 100% reservoir contact tapping into two thin reservoir sub-layers. Real-time azimuthal deep propagation resistivity image/curves were used to geosteer the well trajectory precisely within target zones and provided 4-5 feet TVD detection to bed boundaries. Also, high-resolution microresistivity images, dip picks and near-bit azimuthal gamma ray helped in maintaining the well-bore attitude parallel to the stratigraphy within each sub-layer. This data facilitated a smooth transition from one sub-layer to the next with minimum borehole tortuosity aided by the push the-bit RSS and at-bit-inclination measurements. In addition, NMR provided real-time porosity and permeability measurements assisting in well placement and enhancing reservoir understanding as well as optimizing future well planning workflows. This paper presents a step change from the traditional field development drilling techniques in terms of horizontal length. Similar well designs are currently being implemented in an effort to benchmark drilling, well placement and petrophysical data gathering requirements for future development drilling in order to maximize asset value.