Acidizing/stimulation

Decade of Stimulation Experience in the Deepwater Gulf of Mexico

The deepwater Gulf of Mexico is a technically and economically challenging production environment. High rates and ultimate recoveries are required per well to offset high development costs.

The deepwater Gulf of Mexico is a technically and economically challenging production environment. High rates and ultimate recoveries are required per well to offset high development costs. Stimulation treatments maintain wells at peak production rates and accelerate reserves recovery. In these complex layered reservoirs, stimulation is necessary to ensure recovery volume. The primary objective of stimulation is to restore impaired well/reservoir connectivity. Successfully identifying the cause and location of impairment is required. Looking back over a decade of experience in this challenging environment yields useful insights as the industry moves into new deepwater provinces.

Introduction

Shell’s deepwater development began in 1991 with the Tahoe subsea prospect tied back to the Main Pass 252 platform. Development continued with the Auger, Mars, Ram Powell, Ursa, and Brutus ­tension-leg platforms (TLPs) and many subsea fields that tie back to them (Fig. 1). Most of the reservoirs producing to these structures are geologically young turbidite sands that require sand control. Initially, all of the fields were geopressured significantly above hydrostatic and were significantly undersaturated. The soft compacting sands and aquifer support often provide sufficient energy to achieve adequate recovery by depletion.

jpt-2015-05-decadestimf1.jpg
Fig. 1: Shell’s Gulf of Mexico TLPs.

 

The hydraulic fractures created in the frac-pack process provided lower skin values with minimal use of acid. The horizontal openhole gravel packs used acid-soluble bridging agents to stabilize the wellbore during gravel packing. The bridging agents were then removed with acid washing. Because most of these sand-control completions were cased-hole gravel packs or cased-hole frac packs, most of this paper refers primarily to the experience with those completion types.

As the fields matured, there were more subsea-tieback developments. Stimulation campaigns generally focused on the direct-vertical-access (DVA), or dry-tree, wells of the TLPs. How­ever, stimulation of subsea wells has been highly profitable, and technology has been developed to reduce the subsea-­intervention costs to make these interventions more attractive. The complex operations on TLPs introduce challenges when planning and conducting stimulation operations. Logistics coordination and proper management of returning wells to production are critical to realize production gains and to meet ­environmental-discharge regulations and goals.

Stimulation Process

Well inflow performance is assessed on a regular basis. Inflow-­performance anomalies are noted. These anomalies can include degraded performance of a given well with time, or poor performance when compared with analog reservoirs having similar ­permeability-thickness (kh) values and similar completion type. Well flow modeling, pressure-transient analysis, and, in some cases, production logging are used to investigate anomalies. Often, these investigations reveal increasing well skin or decreasing kh. Increasing skin is related to near-wellbore impairment, and triggers an immediate investigation of the cause. Decreasing kh is often caused by reservoir compaction. However, in layered reservoirs, a layer that is highly damaged relative to others can disappear from the pressure transient. When observed, this effect is investigated to determine if the deterioration of kh is consistent with rock properties and depletion or if it might reflect near-wellbore impairment. Treating both types of wells has shown success, but there has been a higher success rate in treating wells with increasing skin than treating wells with declining kh.

Most of the stimulation treatments have been injected directly down the tubing (bullheaded). Coiled tubing was used if cleaning fill from the wellbore was required or if production logging indicated a noncontributing interval. The condition of the tubing would be evaluated, and if needed, solvent would be spotted to bottom and reversed out to clean the tubing before bullheading the stimulation treatment. The scale-treatment designs involved injecting the treatment-solution leading edge into the completion and allowing the solution to soak (typically 12 to 24 hours for barium sulfate removers) to complete the treatment. ­Solvent-treatment designs involved spotting the required volume of solvent, allowing sufficient soak time, and then flowing back the well.

Often, fluid-compatibility testing is a challenge. There is a desire to avoid unnecessary additives, so these fluids are added only when necessary, to avoid forming sludges and emulsions. Corrosion inhibitors can be especially problematic with regard to fluid compatibility and often require the addition of mutual solvents or surfactants.

Stimulation execution is supervised by a well-intervention foreman. There is limited scope for real-time alteration of design because the entire treatment usually is in the tubing before the ­leading edge reaches bottom. Treatments are pumped on the basis of design pressure. Rates are stepped up to maintain that pressure as the well responds.

Treatments are reviewed twice. An operational after-action review is conducted within a few weeks of the treatment to capture operational learning. A well-performance review is conducted after several months to determine the effect of the treatment. Over the past few years, the production-system surveillance has become more consistent, sophisticated, and structured as part of a general corporate initiative.

Results

Shell’s Gulf of Mexico portfolio consists of approximately 120 wells in water depths ranging from 1,000 to 7,000 ft. 80% are oil wells, and 20% are gas wells. Most of the stimulations were performed on oil wells. The portfolio consists of approximately two-thirds DVA wells and one-third subsea wells. Most of the stimulations have been conducted in the DVA wells, although in 2011, there was an equal number of subsea- and DVA-well stimulations. The total number of stimulations from 2002 through 2011 was 128.

The simplest way to assess the production benefit of stimulation is to evaluate the well-production rate at similar conditions (e.g., choke settings and separator pressures) pretreatment and post-treatment. The ratio of the post-treatment test to the pretreatment test is referred to here as the production-­improvement factor (detailed in the complete paper). While the production-­improvement factor is an early indicator of treatment response, it may not capture the value of the treatment correctly. Stimulation can result in a dramatic immediate improvement, but the impairment may return rapidly. In other cases, the initial improvement may not be dramatic, but the longer-term performance of the well is improved.

Fig. 2 shows the production response and decline for a typical well in which solvent treatments worked. The rapid post-treatment decline is factored into the expectations for solvent treatments. However, because they can be conducted at relatively low cost and will cause few if any process problems during flowback, these treatments are economically attractive and are required to maintain production.

jpt-2015-05-decadestimf2.jpg
Fig. 2: Typical response to a solvent treatment.

 

Hydrofluoric-acid (HF) -treatment results are more complex and variable. Stimulation response can be assessed by use of simple production-decline analysis. The prestimulation behavior is matched to an exponential decline that can be projected post-stimulation. A similar analysis of post-stimulation production can be used to estimate the incremental volume produced during a time period after stimulation. Well tests for 1 year before stimulation and 1 year after stimulation were curve matched and an exponential decline rate was obtained. The decline rate was essentially the same or greater for 75% of the wells. How­ever, the post-stimulation decline rate was lower than the prestimulation decline rate for 25% of the wells. Fig. 3 shows an aggregate-production curve constructed for one asset that had HF stimulations performed between 2002 and 2009, which demonstrates that in a composite analysis, the post-stimulation decline rate is lower than the prestimulation decline rate.

jpt-2015-05-decadestimf3.jpg
Fig. 3: Total-asset aggregate-production function for successful HF treatments.

 

In addition to accelerating recovery, stimulation can improve recovery volumes for a given well. Steep production decline and reduced inflow performance can be corrected with ­hydrochloric-acid/HF treatments. However, the improved production rate may persist for only a limited period of time, then the well returns to the prestimulation performance trend. This pattern is typical of production acceleration resulting from stimulation. Conversely, a post-stimulation increase in production followed by a reduced decline rate can indicate that the well will recover a greater hydrocarbon volume as a result of the stimulation.

Risk and Mitigation

The mechanical well and completion conditions need to be reviewed. Examples of factors to consider include compaction, known obstructions or mechanical defects, and history of solids production. The presence of these risk factors should be accounted for as an economic risk. The treatment design may be modified to reduce the risk. In some cases, the well may be considered too fragile for stimulation.

There are risks associated with well stimulation, and the consequences are magnified in high-cost, high-potential wells. Well and completion integrity must be assessed early in the candidate review. Because acid-stimulation fluids are the most corrosive fluids these wells will be exposed to in their lifetime, a thorough understanding of the metallurgy and testing of acid-corrosion inhibitors are essential. Other risks include introducing formation damage through the use of incompatible fluids. Rigorous laboratory testing should be conducted to find compatible fluid systems. Changes in production behavior including brief releases of sour gas, emulsions, and sludges have been observed following acid treatments. These risks must be assessed, and mitigation and response plans must be in place.

Conclusions

Stimulation of sand-controlled producers in deepwater turbidite reservoirs has delivered value, through both accelerated recovery and improved volumetric recovery. The best stimulation candidates are wells with high production and recovery potential and with clear indications of near-wellbore impairment. Although the incremental-production ratio may be lower than typical for matrix stimulation, the rate and volume ­changes, and hence business value, are greater than those in less-prolific wells. Stimulation of subsea wells is more challenging and costly than stimulation of DVA wells. However, the value of improved volume recovery can make these interventions extremely attractive. Improved surveillance focus and technologies are critical to make these opportunities more accessible and reduce risk. Improved intervention technologies are also required to provide more flexibility and to lower intervention-cost capability. Success requires determining that the undesired production behavior of the well is related to near-wellbore impairment, not other causes.

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 159660, “A Decade of Deepwater Gulf of Mexico Stimulation Experience,” by Lee N. Morgenthaler, SPE, and Leigh A. Fry, Shell E&P, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8–10 October. The paper has not been peer reviewed.