A model has been derived theoretically to correlate capillary pressure and resistivity index based on the fractal scaling theory. The model is simple and predicts a power law relationship between capillary pressure and resistivity index (P c = p e · I β ) in a specific range of low water saturation. To verify the model, gas-water capillary pressure and resistivity were measured simultaneously at a room temperature in 14 core samples from two formations in an oil reservoir. The permeability of the core samples ranged from 0.028 to over 3000 md. The porosity ranged from less than 8% to over 30%. Capillary pressure curves were measured using a semi-permeable porous-plate technique. The model was tested against the experimental data obtained in this study. The results demonstrated that the model could match the experimental data in a specific range of low water saturation. The experimental results also support the fractal scaling theory in a low water saturation range. The new model developed in this study may be deployed to determine capillary pressure from resistivity data both in laboratories and reservoirs, especially in the case in which permeability is low or it is difficult to measure capillary pressure.

Summary In a deepwater west African field, the relatively small number of high-cost, highly productive wells, coupled with a high barium sulfate scaling tendency (upon waterflood breakthrough of injected seawater) requires effective scale management along with removal of near-wellbore damage in order to achieve high hydrocarbon recovery. The nature of the well-completion strategy in the field (frac packs for sand control) had resulted in some wells with higher than expected skin values owing to drilling-fluid losses, residual fracture gel, fluid loss agents, and fines mobilization within the frac packs. The paper will present how the challenges of managing impaired completions and inorganic scale forced innovation in terms of when to apply both stimulation and scale-inhibitor packages to deepwater wells. This paper will outline a novel process for non-conventional batch chemical applications where bullhead stimulation treatments have been displaced deep into the formation (>20 ft) using a scale inhibitor overflush. Not only does this benefit the stimulation by displacing the spent acid and reagents away from the immediate wellbore area, but the combined treatment provides a cost savings with a single mobilization for the combined treatment. The paper will describe the laboratory testing that was performed to qualify the treatments. The four field treatments that were performed demonstrate how these coupled applications have proven very effective at both well stimulation/skin reduction and scale-inhibitor placement before and after seawater breakthrough. The term “squimulation” is used by the local operations team to describe this simultaneous squeeze-and-stimulation process. Many similar fields are currently being developed in the Campos basin (Gulf of Mexico) and west Africa, and this paper presents a good example of best-practice sharing from another oil basin.

Summary Production and drawdown data from 10 subsea deepwater fractured wells have been modeled with an analytical model for unsteady-state flow with fines migration. The simulation results and the field data indicated a good match, within 5%. A sensitivity study conducted on initial concentration of fines, flow rate, maximum fines-mobilization velocity, fines distribution, formation damage, and filtration coefficients confirmed that the model-matching parameters are within values reported commonly in the literature. This paper describes the methodology used to integrate the modeling predictions with field and laboratory data to identify probable causes for increasing skins and declining productivity-index values observed in some of the wells under investigation. It discusses the results of an experiment designed to simultaneously assess the effects of pressure depletion and compaction on fines production and permeability with a triaxial-stress apparatus. This is, to the best of our knowledge, the first time an experiment of this nature is reported in the literature. The good match between the modeling and the field data, further validated with laboratory experiments, allows for discussion of long-term predictions on well productivity impacting current reservoir-management strategies and field-development plans.

In a deepwater West African field the relatively small number of high-cost, highly productive wells, coupled with a high barium sulfate scaling tendency (upon waterflood breakthrough of injected seawater) requires effective scale management along with removal of near-wellbore damage in order to achieve high hydrocarbon recovery. The nature of the well completion strategy in the field (frac packs for sand control) had resulted in some wells with higher than expected skin values due to drilling fluid losses, residual frac gel, fluid loss agents, and fines mobilization within the frac packs. The paper will present how the challenges of managing impaired completions and inorganic scale forced innovation in terms of when to apply both stimulation and scale inhibitor packages to deep water wells. This paper will outline a novel process for non-conventional batch chemical applications where bullhead stimulation treatments have been displaced deep into the formation (>20ft) using a scale inhibitor overflush. Not only does this benefit the stimulation by displacing the spent acid and reagents away from the immediate wellbore area, but the combined treatment provides a cost savings with a single mobilization for the combined treatment. The paper will describe the laboratory testing that was performed to qualify the treatments. The four field treatments that were performed demonstrate how these coupled applications have proven very effective at both well stimulation/skin reduction and scale inhibitor placement prior to and after seawater breakthrough. The term "squimulation" is used by the local operations team to describe this simultaneous squeeze and stimulation process. Many similar fields are currently being developed in the Campos basin, Gulf of Mexico, and West Africa, and this paper is a good example of best-practice sharing from another oil basin.

The effective stimulation of wells in offshore environments where the removal of existing completions is either not feasible or imparts significant cost implications can pose increased challenges for effective fluid delivery to the desired pay zones. This paper documents the challenges encountered in a sandstone reservoir requiring acidization and presents a hydrofluoric (HF) acid/aminopolycarboxylic acid (APCA) fluid stimulation methodology and ensuing field validation. Frac-pack sand control is the preferred completion method in many wells located offshore West Africa. This method presents the following challenges during the life of the well: Potential for underperforming well productionScreen integrity concerns on production hot spot impact points, resulting in reduced production rates or leading to potential long-term well failureLarge screen length or multizone completions leading to diversion challenges for any potential stimulation fluidRemoval of existing completion not permitted Wells in this area were previously stimulated using complicated fluid trains and sequences with strong HF acidizing systems; however, this stimulation approach encountered complications that included the following: Ineffective stimulation fluid placement, leaving areas under-stimulatedSpacers and pre-flushes necessitating large treatment volumesIneffective stimulation caused by fast reaction ratesFluid compatibility concernsPotential limitation of penetration of live acidPotential for rock disintegration, leading to accelerated sanding in the wellbore The HF/APCA fluid was developed and validated for use in such reservoir types, and the fluid qualification is documented and presented. The fluid pH is low, maximizing the generation of HF acid with an acid-soluble chelant. This chelant technology provides unique sandstone acidizing advantages, especially for mixed mineralogy (carbonate/sandstone) formations, coupled with simultaneous dissolution and/or removal of Ca, Mg, or Fe carbonate scales and fines (clay and silica) accumulated in proppant packs, perforation tunnels, tubing, and downhole tools. The fluid is designed such that historic spacer and pre-flush requirements can be eliminated, resulting in more efficient, effective treatment. The system includes health, safety, and environmental advantages; it is a readily biodegradable, nonhazardous material and is not considered a marine pollutant. In this field, the new chelant-based stimulation fluid used alongside engineered diversionary systems provided the ability to address the demands encountered in these wells. The field validation detailed in this paper documents the successful outcome of the fluid technology. Post-stimulation evaluation showed an improved velocity profile across the screens, indicating successful diversion into the underperforming reservoir sections. This result and the overall skin reduction allowed for a production uplift of 48%.