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Results
Unique Process and Tool Provides Better Acid Stimulation and Better Production Results
Al-Saqabi, Mishari (Kuwait Oil Company) | Gazi, Naz (Kuwait Oil Company) | Vishwanath, Chimmalgi (Kuwait Oil Company) | Al Bahrani, Hasan (Kuwait Oil Company) | Turkey, Naween (Kuwait Oil Company) | Abdul-Razaq, Eman (Kuwait Oil Company) | Al-Zankawi, Omran (Kuwait Oil Company) | Bouland, Ali (Kuwait Oil Company) | Surjaatmadja, Jim B. (Halliburton) | Al Hamad, Abdulla M. (Halliburton) | Brand, Shannon (Halliburton)
Abstract There are many ways to stimulate an unlined openhole horizontal well using acid. The simplest way is to just pump acid into the well (i.e., bullhead) without placement control. However, this can often be ineffective. Although still used, such approaches can create massive enlargements at the entry point or high injectivity area, thus causing ineffective treatments and re-entry issues. Wellbore collapse often follows. The use of coiled tubing (CT) as a "pin-point" delivery method is therefore preferred. Using CT allows dispersal of the acid either uniformly or intermittently along the lateral, as desired. CT also allows acid washing to be performed, which is another common process that can improve stimulation without much additional expense to the operator. Using a jetting tool with many jets, acid can be sprayed onto the wellbore wall, and the active agitation caused by the acid-wash process increases the chemical reactivity of the acid at the desired locations. Another beneficial approach of using CT is the hydrajet assisted acid fracturing (HJAAF) method. With focused jetting of acid at much higher pressures, the process initiates microfractures in the wellbore walls. When etched with acid, this approach effectively bypasses near-wellbore (NWB) damage much deeper than common washes, thus providing much better results. Further modification of the process by exerting high annular pressures offers the capability of delivering medium to large fractures. This paper discusses two HJAAF processes uniquely combined into one process used in two large horizontal wells. Because of the large dimension of the inner diameter (ID) of the wells combined with the small production tubing the tool must pass through, the implementation had to be further improved by using a unique jetting mechanism, which positioned the jet nozzles closer to the target. Actual results of such stimulations are presented.
- North America > United States (0.94)
- Asia > Middle East > Kuwait (0.30)
Field Treatment to Stimulate a Deep, Sour, Tight Gas Well using a New, Low Corrosive and Environmentally Friendly Fluid
Nasr-El-Din, H. A. (Texas A&M University) | de Wolf, C. A. (AkzoNobel) | Stanitzek, T.. (AkzoNobel) | Alex, A.. (AkzoNobel) | Gerdes, S.. (Fangmann Energy Services) | Lummer, N. R. (Fangmann Energy Services)
Abstract Matrix acidizing of high temperature gas wells is a difficult task, especially if these wells are sour or if they are completed with high chrome content tubulars. These harsh conditions require high loadings of corrosion inhibitors and intensifiers in addition to hydrogen sulfide scavengers and iron control agents. Selection of these chemicals to meet the strict environmental regulations adds to the difficulty in dealing with such wells. Recently, a new environmentally friendly chelating agent, glutamic acid -diacetic acid (GLDA), has been developed and extensively tested for carbonate and sandstone formations. Significant permeability improvements have been shown in previous papers over a wide range of conditions. In this paper we evaluate the results of the first field application of this chelating agent to acidize a sour, high temperature, tight gas well completed with high chrome content tubulars. Extensive laboratory studies were conducted before the treatment, including: corrosion tests, core flood experiments, compatibility tests with reservoir fluids, and reaction rate measurements using a rotating disk apparatus. The treatment started by pumping a preflush of mutual solvent and water wetting surfactant, followed by the main stage consisting of 20 wt% GLDA with a low concentration of a proper corrosion inhibitor. Following the treatment, the well was put on production, and samples of flow back fluids were collected. The concentrations of various ions were determined using ICP. Various analytical techniques were used to determine the concentration of GLDA and other organic compounds in the flow back samples. The treatment was applied in the field without encountering any operational problems. A significant increase in gas production that exceeded operator expectations was achieved. Unlike previous treatments where HCl or other chelates were used, the concentrations of iron, chrome, nickel, and molybdenum in the flow back samples were negligible, confirming low corrosion of well tubulars. Improved productivity and longer term performance results confirm the effectiveness of the new chelate as a versatile stimulation fluid.
- North America > United States > Texas (0.46)
- Asia > Middle East > Saudi Arabia (0.28)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.67)
Abstract Recovering acid after a stimulation job can prove to be very challenging in sandstone reservoirs, especially if the well has a potential to produce H2S. When the customer's gathering station is unequipped to handle acid or water, then it becomes impossible to flow the acid via the flow lines. The acid must be disposed at the surface in a separate facility as fast as possible. Allowing the acid to remain downhole for long time carries the risk of damaging the sandstone reservoir due to secondary precipitations. The customer, as per standard operating policy, does not allow flowing back fluids into their pits. Only return tanks are allowed, adding to the difficulty of flowing back stimulation fluids. With the help of concentric coiled tubing, an innovative technique to produce back acid from H2S wells became the sole solution to a major flowback challenge in South Oman wells. The technology successfully enabled the recovery of stimulation acid from a customer's well that had high H2S content, without producing any H2S at surface. The unique approach consisted of mixing an H2S scavenger with a scale inhibitor. This mixture was used as the power fluid for the concentric coiled tubing tool. With the help of the good shearing energy at the WellVac BHA, combined with the small concentric coiled tubing return annulus, the H2S scavenger solution was perfectly mixed downhole with the return fluids, and no H2S was produced or recorded at the surface return tanks. This new technique will certainly open new possibilities to stimulate many more wells that could not be stimulated previously due to high H2S content. The technique would also eliminate the great costs of a portable flare system.
- North America (0.69)
- Asia > Middle East > Oman (0.37)
- Well Completion > Completion Installation and Operations > Coiled tubing operations (1.00)
- Production and Well Operations > Well Intervention (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
Abstract As the oilfield industry requires new techniques to generate diversion over large pay zones and easier methods to perform workover operations and perform interventions through Coiled Tubing, research is focused to provide the industry with new technologies that support the growing demand for oil and gas in the world. Fluid systems that are used to divert acid over large zones and generate non-mechanical isolation on a wellbore have traditionally been viscosified fluids and solid particulates. These substances create (in most cases) a drastic permeability reduction in the near wellbore area of producing zones that are meant to be protected. In operations that require divertion or the generation of a temporary plug, researchers have found that polymer based fluids are best suited, since they create less damage on the formation, and in the case of temporary plugs they can withstand higher differential pressures. The use of such fluids has reduced considerably the need for more complicated deployed techniques, such as mechanical packers, bridge plugs and mechanical diversion techniques. This paper describes the first application of a polymer gel system in Saudi Arabian gas fields to isolate a section of a payzone on a vertical well, the system's design and operational challenges, and finally, its successful outcome and results. The objective of this application was to place a temporary plug between two producing zones to be able to selectively stimulate the lower zone.
- North America > United States (0.68)
- Asia > Middle East (0.47)
Abstract The deepwater Gulf of Mexico is a technically and economically challenging production environment. High rate and ultimate recoveries per well are required to offset high development costs. Stimulation is employed to maintain wells at peak production rates and accelerate reserve recovery. In the complex layered reservoirs of the deepwater Gulf of Mexico stimulation is also necessary to ensure volume recovery. The primary objective of stimulation is to restore impaired well /reservoir connectivity. In complex reservoirs this may be reflected in either a reduction of skin or improvement in apparent permeability height. In poorly consolidated sandstone reservoirs production may become impaired during completion operations by suspended solids, polymer residue, or incompatible fluid systems. During production fines migration, scale deposition, and organic deposits in the near wellbore and sand control system can lead to declining inflow performance. Successful identification of the cause and location of impairment is required for success. The increasing population of subsea wells creates new challenges for intervention. Correct operation of the well post stimulation is also necessary to achieve the desired rate increases without compromising production system performance. The nature of impairment, treatment options, and post treatment production issues often change over the life of the well. Looking back over a decade of experience in this challenging environment yields useful insights as we move into new deepwater provinces.
- Geology > Mineral (0.71)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.68)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Deep Water Marine Environment (0.47)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.31)
- North America > United States > Texas > East Texas Salt Basin > Shell Field (0.98)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Auger Basin > Garden Banks > Block 426 > Auger Field (0.89)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Viosca Knoll > Block 957 > Ram Powell Field (0.89)
- (17 more...)
Summary Throughout a well's lifetime, formation damage can occur during the activities of drilling, completion, injection, or well-stimulation treatments. Typically, remedial treatments to restore the well performance involve injection of reactive fluids capable of removing such damage. Therefore, understanding damage mechanism and type is critical for fluid selection and effective treatment design. Without this knowledge, the conducted stimulation treatment could cause a more-severe form of formation damage. This report discusses the improper use of mud acid [at 9 wt% hydrochloric acid (HCl)/1 wt% hydrofluoric acid (HF)] in restoring the injectivity of Well N-510. The subject well was stimulated with two acid-stimulation treatments in an attempt to improve the poor results of a previous cleanout job, conducted to remove mud filter cake. These treatments were designed to remove the damage that has been limiting the well injectivity. However, it was found that these acidizing treatments created a new formation damage that resulted in the severe decline of well injectivity. Integration of chemical-analysis techniques performed on return fluids and coreflood experiments was used to assess the effectiveness of all conducted treatments. This report demonstrates the techniques used to identify the source and type of formation-damage mechanism that occurred during each treatment. On the basis of these studies, it was found that the poor results of the cleanout job were caused by precipitation of calcium sulfate. This precipitation was a result of the mixing between spent cleanout acid, having a high amount of calcium, and the high-sulfate-content water. Most of this precipitation occurred in the wellbore vicinity during the preceding stages of the well flowback. Calcium sulfate precipitation had a negative impact on the performance of the conducted acid-stimulation treatments. In the presence of this precipitation, the two successive mud-acid-stimulation treatments created another form of damage (i.e., in-situ fluoride-based scale). Initially, the fresh injected mud acid dissolved most of the calcium sulfate scale, and as a result, it contained a high amount of dissolved calcium ions. However, upon the spending of injected mud acid in the formation, calcium fluoride precipitated as a result of the increase of solution pH value. The interactions between different acid systems and the constituents of the downhole environment, resulting in the precipitation of calcium sulfate and calcium fluoride, are discussed. In addition, this report provides recommended modifications for future stimulation treatments, conducted under similar conditions, so as to prevent the formation of these scales.
- North America > United States (1.00)
- Europe (0.93)
- Asia > Middle East > Saudi Arabia (0.69)
Acid Stimulation by Bull-heading and Back-production: The Bonga Experience
Okoh, Ehimhen (Shell Nigeria Exploration and Production Company) | Olatunbosun, Olugbenga (Shell Nigeria Exploration and Production Company) | Ogunsina, Oluseye (Shell Nigeria Exploration and Production Company) | Uche, Enor (Shell Nigeria Exploration and Production Company) | Eta, Kingsley (Shell Nigeria Exploration and Production Company) | Oduola, Lukman (Shell Nigeria Exploration and Production Company) | Beldongar, Maye (Schlumberger Nigeria Limited)
Abstract Bonga producer (Well-X) became severely impaired during a series of interventions (to address SCSSV failure), with oil potential dropping from 18 to 3 kbod. The Well and Reservoir Management team believed the initial impairment was most likely caused by fines migration and secondly by fluid (MEG and brine) losses to the formation during interventions. A two-fold treatment was recommended –solvent (surfactant) and half stre gth mud acid to target the two impairment mechanisms. Considering the relatively low productivity and remaining reserves, the downside risk was low from a subsurface perspective. The major concerns were related to HSSE and integrity risks pertaining to unspent FPSO. Lessons learnt similar jobs by other acid flow-back to the Bonga from successful executions of Operators enabled the Bonga team to demonstrate the necessary risk management and purs e the concept towards execution. To minimize cost, the recommended deployment method was by bull-heading the treatment from the Field Support Vessel, via a flexible hose connected to the tree, and subsequently to back produce the well fluids to the FPSO with injection of Soda Ash to neutralize any unspent acid on the topsides. The key challenges that needed to be addressed were: Identifying an appropriate stimulation recipe, Ensuring adequate pump rate of stimulation fluid given limited pressure rating of the flexible hose, Managing flowback of unspent acid to topsides, Metallurgy compatibility with the stimulation fluid, ydrate risk and Production of H2S from chemical reaction. Full integration of the various functional aspects was essential for effective planning and execution. The Well-X stimulation led to an increase in production frrom 3 to 22 kkbod, with PI improving from 1.4 to 86 bpd/psi; a PIF of 60. Industry experience shows that gaains from mud acid stimulation to attack fines can typically be sustained for up to 12 months, while the partial gain from surfactant to remove MEG/brine impairment is expected to be sustained permanently. TThhis success paves the way for further acid stimulation in the Bonga field where fines migration is typical among producers, and provides opportunities for production acceleration in the field and other upcoming developments.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.89)
Abstract Acid treatments for dolomite formation with low permeability differ from that applied for calcite rock. Unlike limestone acidizing where HCl reacts with limestone in rapid reaction rate to generate reaction products soluble in water. In Some cases, injectivity well can not effectively improve in dolomite formation with low permeability using conventional 15 wt% HCl acid. In addition, formation damage due to drilling or workover operations can not be removed. Therefore, the process of treating dolomite for injectivitiy improvement may consider a serious issue for acid stimulation. The challenges of dolomite acidizing are to optimize damage removal while maximizing rock permeability with wormhole occurrences. Well DW-4 drilled and completed as horizontal open hole wastewater disposal wells for excess water production from offshore oil wells in Al-Khafji Field. This well is used to dispose the un-wanted co-produced water which shows injectivity decline with time due to sand plugging and oil content droplet. Several acid stimulation treatments were conducted on subject well with low rate of success due to not considering the dolomite reaction rate and the chemical volume to be used. A simple previous treatment review was conducted to select the best chemical recipe and treatment volume for injectivity improvement. As a result of conducting new chemicals recipe with optimum treatment volume, a major improvement in well injectivity with formation damage removal was obtained. This paper demonstrated new design methodology with extensive field study to address the challenges and the best future operation practices for acid stimulation. It included a pre-flush of mutual solvents, then bullheading stage of 20 wt% HCl with intensifier to accelerate the chemical reaction with dolomite rock. A carefully designed train of treatment fluids was applied to remove formation damage induced by drilling and injection fluids. Injectivity tests before and after each step of the treatment was recorded and evaluated. Proper design and execution of the stimulation treatment almost doubled the well injectivity index. Challenges, fluid selection, design criteria, field treatment, lessons learned, and results of the acid treatments were discussed in this paper.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.66)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Tayarat Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Bahrah Field > Marrat Formation (0.98)
Technology Focus Well stimulation continues to be a hot topic in our industry, particularly with hydraulic fracturing of shales. Having been in the industry since the Dark Ages, (at least, it seems like it at times), it is interesting to see the technology changes over time and what areas are currently in the spotlight. Certainly, hydraulic fracturing continues to lead the industry interest; however, we do pump a lot of acid, and we have not forgotten its importance. Our acid blends have not changed much since the very early days—the late 1800s—of acidizing. Hydrochloric acid has been the mainstay, with primarily hydrofluoric acid and formic and acetic acids being the complimenting acids. Specialty acids, such as phosphonic, sulfamic, and others, have also been playing a role. Major technology developments in nonproppant-fracturing well stimulation, as evidenced by the numerous publications over the last few years, have been primarily in carbonate acidizing. This is a continuing trend brought about by the significance of the carbonates to the world’s oil supply. However, our industry does use a lot of acid in the noncarbonates. One of those areas is in spearheading fracturing treatments to reduce near-wellbore tortuosity, most of these in sands and shales. My experience with this approach in horizontal shale wells has not always been successful; however, one of the papers selected for this month’s feature shows a unique acid blend that has shown some success in tight-gas-sand fracturing. Perhaps this and other unique acid blends could provide increased success in shales. Horizontal wells in all reservoir types are now quite common, allowing our industry to exploit lesser-quality reservoirs economically. Shales are excellent examples. Many reservoirs have a high water cut, and stimulating wells in these reservoirs can be a real challenge. Acid-placement techniques, as well as diagnostics while acidizing, are a significant challenge to our industry. Of course, in our industry, challenges beget solutions. A recent development helping with well stimulation and production diagnostics is distributed temperature sensing (DTS) and distributed acoustic sensing (DAS). From reviewing numerous technical papers from worldwide SPE meetings held in the last year or so, the development and application of DTS and DAS appear to be in the forefront. Two of the papers selected for this month’s feature reflect on these developments and applications. Readers are advised to review the following synopsized papers as well as the recommended additional reading to gain information on recent advancements in well stimulation. Recommended additional reading at OnePetro: www.onepetro.org. SPE 144803 Selective Stimulation and Water Control in High-Water-Cut Wells: Case Histories From Upper Magdalena Valley Basin in Colombia by E. Rodriguez, Ecopetrol, et al. SPE 154257 Acidizing Optimization: Monterey Shale, California by Rakesh Trehan, Halliburton, et al. SPE 143942 Sandstone Reservoir Stimulation Using High-Temperature Deep-Penetrating Acid by Puyong Feng, China Oilfield Services, et al. SPE 148835 Fracture-Stimulation Diagnostics in Horizontal Wells Using DTS by M. Tabatabaei, Texas A&M University, et al. SPE 152320 Stimulation in Wells With Electrical Submersible Pumps Increases Production and Saves Costs Without Damaging Pumps by M. Gallegos, Schlumberger, et al.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- North America > United States > Louisiana > China Field (0.99)
- North America > United States > California > Monterey Formation (0.99)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Acidizing (1.00)
- (4 more...)
Abstract 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 five 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.
- Africa (1.00)
- Europe > United Kingdom > North Sea (0.28)
- North America > United States > Texas (0.28)
- Geology > Mineral > Silicate (0.94)
- Geology > Geological Subdiscipline (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.68)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment (0.46)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > East Texas Salt Basin > Alba Field (0.99)
- Europe > United Kingdom > North Sea > North Sea Basin (0.99)
- Europe > Norway > North Sea > North Sea Basin (0.99)
- (5 more...)