An Innovative Acid Diversion Using In-Situ Foam Generation: Experimental and Successful Field Application

In carbonate reservoirs, effective acid stimulation is essential to overcome reservoir damage and mainline high oil production. Recently, most of oil wells are being drilled horizontally to maximize production. Acid stimulation of horizontal wells with long intervals require very effective acid diversion system. If the diversion system is not efficient enough, most of the acid will be leaking-off near the casing shoe, in openhole well, which will result in a fast water breakthrough and diminish production. This study describes a breakthrough treatment for acidizing long horizontal wells in carbonate formations. The novel technology is based on in-situ foam generation to divert the acid. Gas diversion, as a foam, is a perfect diversion mechanism as gas creates pressure resistance which forces the acid stages to be diverted to new ones?. The diversion will not require the acid to be spent, compared to viscoelastic diverting system. Moreover, no gel is left behind post treatment, which will eliminate any damage potential. The system is not impacted with the presence of corrosion products, where diverting system will not function without effective pickling and tubular cleanup. Lab results showed that the new in-situ foam generation system was very effective on both dolomite and calcite cores. The system creates high back pressure when foam is generated, which significantly diverts the acid stages to stimulate other intervals. Moreover, the new system minimizes acid leak-off and penetration. Open completing the job, the foam collapse leaving no left behind any damaging material. Field application of the in-situ foam generating system showed high success rate and outperformed other diversion mechanisms. The well gain was up to 18 folds of the original well injectivity.

Identification of Patches of Bitumen in a Carbonate Reservoir: A Case Study

Carbonate reservoir X has varying levels of maturity in terms of development. The South/West is highly matured; development activities have recently kicked-off in the Crestal part while the areas towards the Far North is not fully developed and posed the largest uncertainty in terms of reservoir quality, fluid contacts, oil saturation, well injectivity/ productivity, area potential and reserves due to poor well control. In reservoir X with segmented development areas, patches of bitumen have been found in the Far North. The extent of this Bitumen was unknown. In order to expand the CO2 development concept to achieve production target from the Far Northern flank, an understanding and mitigation of the area uncertainties is crucial. Reservoir bitumen is a highly viscous, asphaltene rich hydrocarbon that affects reservoir performance. Distinguishing between producible oil and reservoir bitumen is critical for recoverable hydrocarbon volume calculations and production planning, yet the lack of resistivity and density contrast between the reservoir bitumen and light oil makes it difficult, if not impossible, to make such differentiation using only conventional logs such as neutron, density, and resistivity. This paper highlights the utilization and integration of advanced logging tools such as nuclear magnetic resonance and dielectric, in conjunction with routine logs, pressure points, RCI samples, vertical interference test and core data to differentiate between reservoir bitumen and other hydrocarbon types in the pore space. The major findings from the studies shows bitumen doesn't form as a single layer but occurs in different subzones as patches which is a challenge for static modelling. When high molecular weight hydrocarbons are distributed in the pore space and coexist with light and producible hydrocarbons, reservoir bitumen is likely to block pore throats. The Bitumen present in this reservoir have a log response similar to conventional pore fluids. The outcome of this study has helped in refining the bitumen boundary, optimize well placement, resolved the uncertainties associated with deeper fluid contacts and provided realistic estimate of STOIIP.

Novel Sandstone Stimulation Using Thermochemical Fluid: Successful Field Application

Sandstone acidizing is implemented to remove the damage from the near-wellbore region. Different techniques are used to remove the formation and damage and improve reservoir productivity. This paper presents a novel sandstone stimulation technique using thermochemical fluids. The used chemicals are not reactive at surface conditions and react only at the downhole conditions. The reservoir temperature or pH controller can be used to activate the chemical reaction. A successful field application of the proposed method is reported in this paper. Different measurements were conducted to assess the performance of the new technique. A compatibility study was conducted at different conditions to evaluate the generation of acid foam. Also, Coreflood experiments were performed by injecting the foam generating solutions into tight sandstone cores. The rock permeability and the pores network were evaluated before and after the chemical injection. Scanning electron microscopy (SEM) and nuclear magnetic resonance (NMR) and analyses were performed. Moreover, a field application of the in situ acid foam generation was conducted. The treatment was implemented by injecting the solutions to react at the downhole conditions and improve the well injectivity. The profiles of injection rate, circulation pressure, and total volume were monitored during the field treatment to assess the treatment performance. Results showed that the used solutions can generate foam in less time and the volume of the generated foam is around 30 folds of the original chemical volumes. The in situ generated foam can penetrate deeper in the reservoir due to the larger foam volume compared to original chemicals, leading to improve treatment efficiency. Also, the new technique increased the rock permeability from 0.6 to 420 mD due to the dissolution and removal of illite minerals as well as the generation of micro-fractures due to the pressure pulses. The field application showed a very successful performance and the well injectivity was increased by 18 times after the treatment. The proposed technique utilizes thermochemical fluids to generate acid foam at the reservoir conditions. This technique can eliminate all the risks associated with HSE concerns, in addition to the corrosion issues. Also, the proposed treatment showed a successful field application and increased the well injectivity up by 18 folds of the original injectivity.

Effective Treatment of Humic Acid Foulants in SAGD Produced Water

Humic acids, one major type of organic foulants in steam assisted gravity drainage (SAGD) produced water, can precipitate on surface and downhole equipment in SAGD facilities, resulting in high cleaning costs, potential equipment damage and decrease of injectivity of disposal wells. In this paper, a cost-effective chemical solution is presented where an alcohol ethoxylate surfactant/chelating agent package can efficiently disperse the organic fouling molecules in SAGD produced water; therefore, the approach is expected to significantly mitigate the humic acid related fouling issues in the SAGD system. In this study, a variety of commercially available surfactant products were evaluated for their aids in well injectivity on humic acid molecules in the freshly obtained SAGD produced water. The lab testing filtration apparatus was specially designed to simulate the sandstone formation geology of SAGD disposal wells. An "efficiency factor" was defined to grade the dispersing performance of the surfactant and/or surfactant/chelating agent package in the lab filtration tests. The efficiency factor provides a reasonable estimation regarding how well the chemical can reduce the plugging risk in a disposal well as compared to the untreated produced water. Among all the surfactant products tested, an alcohol ethoxylate surfactant with the appropriate molecular structure shows distinguished dispersing performance on humic acids in SAGD produced water. However, the surfactant alone was found inconsistent in the dispersing performance when different batches of the produced water were involved. Inclusion of the specific metal chelating agents to the above surfactant formulation improved the dispersing performance consistency. The chelator molecules presumably help destroy the intermolecular bridges among humic acid molecules in the SAGD produced water; thereby, increasing the dispersing effectiveness of the alcohol ethyoxylate surfactants. Tests show that the efficiency factor of the surfactant/chelating agent package is higher than 8, which implies that the formulation could lead to eight times extension of the interval between workovers on SAGD disposal wells, a significant reduction for the operational downtime and costs. This study presented a cost-effective chemical solution to help disperse the humic acid molecules in SAGD produced water, which can help significantly reduce the fouling risk caused by organic foulants, improve injectivity and extend the intervals between workovers of SAGD disposal wells.

Semi-Analytical Method for Accurate Calculation of Well Injectivity During Hot Water Injection for Heavy Oil Recovery

Representation of wells in numerical simulation of petroleum reservoirs is a challenging task due to large difference in typical scales of grid blocks (tens to hundreds meters) and wells (~0.1 m), with high pressure and saturation gradients around wells. Although a variety of grid refinement techniques can be used for local simulations, they have limited application in field-scale problems due to huge model dimensions. Thus, auxiliary quasi-stationary local solutions (so-called inflow performance relations) are used to relate well flow rate with well and grid block pressures. These auxiliary solutions are strictly derived for linear cases and generalized to non-linear problems by using grid-block averaged values of fluid and reservoir properties. In the case of hot water injection for heavy oil recovery, this results in significant errors in well injectivity calculations due to large temperature and saturation gradients dynamically influencing viscosity and relative permeability distributions around the well. In this paper we propose a method which combines a semi-analytical solution of the hyperbolic Entov-Zazovsky problem for non-isothermal oil displacement with integration for pressure distribution taking into account nonlinear dependencies of fluid viscosities and relative permeabilities on temperature and saturations. Both constant injection rate and constant well pressure cases are considered. Example calculations demonstrate that the method helps to avoid underestimation of well injectivity in non-isothermal problems caused by grid-block averaging of fluid and reservoir properties in conventional inflow performance relations.

Development and Trial of Technology for Open Hole Wells Performance Enhancement in GoM

Open hole (OH) completions are not very common in the GoM, but the area has seen an uptick in OH wells in recent years, and a few big projects have elected to use the same completion archetype. There are several different ways to complete an OH well, and one of these completion techniques involves running screens across the OH in Drill-In fluid (DIF), displacing the DIF out of the OH with brine, and then setting the packer, before pumping a filter cake breaker, designed to remove the filter cake and restore the reservoir permeability to near pre-drilling levels. A review of past open hole (OH) well completions in GoM revealed that there was an inconsistent action of the breaker on the filter-cake: sometimes the breaker would react quickly, and sometimes there was no noticeable effect. This study led to the development of a new technology to allow better displacements of the OH, with the ultimate objective of reducing initial well skin induced by the drill-in fluid (DIF) and filter cake. It was theorized that the low displacement rates would lead to poor removal of the mud from the OH, in turn leading to a poor breaker action on the DIF filter cake and a long-term impact on well injectivity and increased OPEX, as these wells tend to need an initial stimulation within a short timeframe after initial completion. The approach used was to develop a new tool to allow faster displacement rates, and test it on a trial well, to verify the results and validate this theory. To solve this problem, a new tool was proposed, developed and fully tested in a tight deadline of 6 months. The new module allows up to 9 bpm rates and up to 3,500 psi differential pressure before setting the packer, versus the previous ∼800 psi differential pressure limit, present in all tools in the market, for that casing size (7 5/8"). During the first well trial, the tool allowed a displacement of the OH at double the pump rates obtained in previous wells in the same basin, with similar OH lengths, leading to the smallest volume of contaminated fluid interface seen to date, indicating a much better displacement. Once the well was put online, it achieved an injection rate above expectations, even when the drilled OH interval penetrated significantly less net sands than originally planned. The results on this single well trial seem to corroborate the theory posed, however it is recognized that more data is required to be certain of its results, and that will only come with time, as well performance is measured and compared with other wells that did not use the same technology. The novelty of this new technology is the ability to obtain a better displacement of the OH, leading to a better breaker action and well cleanup in OH completions. Although the trial well was an injector well, the technology is equally applicable to producer wells. The paper will cover the problem description, installation procedures, development and testing of the technology, design aspects of using the technology and the successful implementation in the trial well.

Produced Water Disposal in Deep Aquifers: Case History Review of Ughelli East-30 Pilot Injector

A water injector pilot well - Ughelli East-30, was drilled across high-permeability unconsolidated sandstone aquifers to dispose 30 Mbwpd of produced water in November 1998 and suspended in December 1998 due to lack of injectivity. Review of the failed pilot injection was performed as part of an extensive water management study for a cluster of onshore fields located in the western Niger Delta area. The technical investigation focused on the target disposal aquifer petrophysical parameters, produced water composition analysis, well completion design and injection performance result. Potential impairment mechanisms and failure risk factors for injectors with similar cased-hole, perforated completion design in analogue reservoirs were also investigated. The poor well injectivity performance was attributed to sub-optimal sand control completion design and the ‘water hammer’ effect which resulted in massive sand fill as evidenced by a sand bailing exercise during November 1999 riglessre-entry in the well. The 17-ft rat hole below the bottom aquifer sand perforations was also deemed to be inadequate for the sand fill which apparently bridged the perforations. Optimal completion requirements to prevent water injection failure in unconsolidated sandstone formation has been brought to the fore in this paper which is expected to steer engineers focus to those factors with high impact on water injection system performance.