|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Kumar, Rajeev (Schlumberger) | Zacharia, Joseph (Schlumberger) | Guo Yu, Dai (Schlumberger) | Singh, Amit Kumar (Schlumberger) | Talreja, Rahul (Schlumberger) | Bandyopadhyay, Atanu (Schlumberger) | Subbiah, Surej Kumar (Schlumberger)
The unconventional reservoirs have emerged as major hydrocarbon prospects and optimum yield from these reservoirs is dependent on two key aspects, viz. well design and hydrofracturing wherein rock mechanics inputs play key role. The Sonic Measurements at borehole condition are used to compute the rock mechanical properties like Stress profile, Young's Modulus and Poisson's Ratio. Often, these are influenced by the anisotropy of layers and variations in well deviation for same formations. In one of the fields under review, the sonic compressional slowness varied from 8us/ft. to 20us/ft. at the target depth in shale layer in different wells drilled with varying deviation through same formations. This affected the values of stress profile, Young's Modulus and Poisson's Ratio resulting in inaccurate hydro-fracture design. At higher well deviation, breakouts were frequently observed and could not be explained on the basis of compressional slowness as it suggested faster and more competent formation. Current paper showcases case studies where hole condition improved in new wells with better hydro fracturing jobs considering effect of anisotropy in Geomechanics workflow. Sonic logs in deviated wells across shale layer were verticalized using estimated Thomson parameters considering different well path through same layer and core test results. Vertical and horizontal Young's Modulus and Poisson's Ratio were estimated for shale layers with better accuracy. The horizontal tectonic strain was constrained using radial profiles of the three shear moduli obtained from the Stoneley and cross-dipole sonic logs at depth intervals where stress induced anisotropy can be observed in permeable sandstone layer. A rock mechanics model was prepared by history matching borehole failures, drilling events and hydro-frac results in vertical and horizontal wells using updated rock properties. Geomechanical model with corrected sonic data helped to explain the breakouts in shale layer at 60deg-85deg well deviation where the original sonic basic data suggested faster and more competent formation with slight variation in stress profile among shale-sand layer. Considering shear failure, the mud weight to maintain good hole conditions at 80deg should be 0.6ppg-0.8ppg higher than that being used in offset vertical wells. Estimated closure pressure and breakdown pressure showed good match with frac results in deviated wells using new workflow. There was difference of .03psi/ft-0.07psi/ft. in shale layers using this new workflow which helped to explain frac height and containment during pressure history match. This paper elucidates the methodology that provides a reliable and accurate rock mechanics characterization to be used for well engineering applications. The study facilitates in safely and successfully drilling wells with lesser drilling issues and optimized frac stages.
Field X is located in the northern part of Cambay basin, western onshore India. Sand-1 is the main reservoir unit in this field. Primary recovery is low here because Field X is located in the region's heavy oil belt. To increase the recovery factor, thermal EOR technique - Insitu Combustion, has been implemented in various parts of this heavy oil belt. Insitu combustion reduces oil viscosity but at the same time produces residual gases. These residual gases, called "Flue gas??, accumulate as pockets in the reservoir top. The thermally altered low viscous crude can be produced efficiently through horizontal drainholes by maximizing reservoir contact and sweep radius.
Placing a horizontal drainhole in this field is a challenge in itself because the drainhole has to be maintained at a safe distance from the flue gas pockets on top to prevent premature gassing out and also at a safe distance from bottom shale.
As a solution to this challenge, "Distance to Boundary?? (DTB) technology along with LWD was introduced for the first time in Field X in Well X. "DTB?? technology detects the resistivity contrast at a shale-sand interface and maps the shale boundaries while drilling. The well was landed ~10m below reservoir top using LWD measurements to maintain a safe distance from flue gas pockets on top. It was decided to place the drainhole about 3m above reservoir bottom to stay away from bottom shale. The final result was a spectacular success with 311m of drainhole drilled with 100% stay in target reservoir zone. "DTB?? technology tracked lower shale from ~3m and trajectory was maneuvered in conjunction with the structural changes to maintain an average distance of 3m from bottom. LWD data was used to verify sweet zone throughout the drilled interval.
This paper illustrates an exemplary case study which opens new and exciting possibilities for application of LWD and "-DTB-?? technology in field X for further field development plans.
Weirich, John B. (Baker Hughes Inc) | Monroe, Terry D. (BJ Services Company) | Beall, Brian B. (BJ Services Company) | Singh, Amit Kumar (BJ Services Company) | Gupta, D.V. Satya (BJ Services Company) | McBee, Jim (Nippon Oil Exploration U.S.A.)
Chemically impregnated substrates have been successfully used for several years in fracture treatments to achieve long-term inhibition of downhole scale and other precipitates. These solid chemical treatments are gaining wider interest in non-fracture applications. The well designer is challenged to place the substrate in the production flow stream, so as to effectively treat the produced fluid, while at the same time ensuring the integrity of the completion as a whole. The application of a pre-packed well screen to convey the impregnated substrate in a gravel packed well is discussed as well as the evaluations made of the substrate's fines plugging tendencies and the design of the pre-packed screen itself. The work conducted indicates that correctly sizing the substrate in relation to the gravel pack proppant and designing a special, enlarged pre-packed screen can ensure effective delivery of these chemical treatments in a variety of well completions.
Deposition of mineral scales is the root cause of many production problems in oil and gas operations. These scale deposits have resulted in formation damage, production losses, significant rate and pressure reductions, and equipment failure due to corrosion issues. The most commonly encountered mineral scales in the oilfield are carbonates and sulfate-based calcium sulfate, barium sulfate, and strontium sulfate scales. However, a more unusual form of these mineral scales— zinc sulfide—has recently been reported.
This paper focuses on the systematic study of a zinc sulfide scale and the operation that removed it from a well in the Gulf of Mexico. Identifying the scale form and composition, and the factors affecting its dissolution resulted in a treatment that successfully removed the scale, thereby enhancing gas production from the well.
This scale was identified as wurtzite, a form of zinc sulfide scale. Extensive laboratory testing considered acid solubility and other scale-removal issues at downhole temperature and pressure conditions, as compared to the theoretical solubility of zinc sulfide in HCl acid. The study also determined that other factors may affect the real-world dissolution efficiency of the acid: pressure changes, hydrogen sulfide scavenger concentration and type, the ratio of acid volume to scale weight, pre-treatment oxidizer use, and pH values that prevent re-precipitation of dissolved scale.
The paper will describe the pre-job testing process and a field case history of a coiled tubing acid scale treatment that effectively removed the zinc sulfide scale from tubulars and the formation. Data will be presented showing the composition of the acid-flowback samples as well as the treatment and production charts.
In the Gulf of Mexico, momentum is increasing for drilling and completing wells deeper than 25,000 ft and with bottomhole pressures exceeding 20,000 psi. High-density base fluids have become standard components of fracturing or frac-pack completions to achieve working pressures below 15,000 psi at surface due to equipment limitation. Stimulation designs for these deep, high-profile wells aim to achieve long fracture lengths using large treatment volumes. Cleanup and maximum recovery of the high-density fracturing fluid is a necessity to maximize the effective fracture length, and thereby the production potential after these treatments.
Interfacial tension, contact angle and wettability are the key parameters to consider when choosing a surfactant package for maximizing fluid recovery. Historically, the surfactant packages that have been used in conventional fracturing fluids generally focused on water-wetting or non-wetting and lower surface tension results.
This paper presents details of laboratory studies to optimize a surfactant package for high-density base fluids. Fluid recovery studies were done on a sand column along with the measurement of the contact angle and interfacial tension of high-density base fluid with various surfactants. Core flow tests were also performed to evaluate regain permeability and cleanup. The tests with optimized surfactant package resulted in more than 90% regain permeability with a high-density fracturing fluid system and correspond with the results from the fluid recovery sand column testing. Laboratory tests show that the synergetic effects of interfacial tension, contact angle and wettability together are more significant than any one individual parameter and that more surfactant is not always better.
Selecting and optimizing a suitable and compatible surfactant package enhances the recovery and cleanup of a high-density fracturing fluid, which can result in highly conductive and longer effective fracture lengths.
Traditionally, aqueous fluids have been the preferable choice for hydraulic fracturing treatments as well as frac-pack completions. The major reasons for this attractiveness to water are low cost, safety, availability, minimal effect on the environment, ease of handling, etc (Penny, Conway and Briscoe, 1983). The compatibility issues of water in hydrocarbonbearing formations have been identified and investigated in detail by the petroleum industry since its inception.
Advancement in chemical additive systems with continuous research and development has helped to minimize the potential for formation damage from aqueous fluid injection.
A combination of multiple down hole gauges and dual density / tracer logs were utilized to quantitatively evaluate distribution of fluid and proppant across a long perforated interval separated in two lobes and to quantify the annular pack percentage across the entire completion interval during a deepwater frac pack treatment in GoM. It was important to evaluate the achievement of an effective fracture in both lobes and define the annular pack percentage across the entire completion interval to be able to produce the well to its potential.
This technique quantitatively evaluated the entire frac pack process and determined screen out events in separate lobes and annular pack efficiency. The analysis also defined the dynamics of the treatment fluid and proppant slurry movement during the frac pack pumping operation and their final placement.
Several expected as well as unexpected conclusions and observations were identified. In summary, the diagnosis indicated that higher percentage of treatment fluid and proppant was received by the upper sandstone lobe. The exact proppant concentration at lower lobe screen out was identified. A baseline pre-pack value was established, which allowed the annular pack percentage to be calculated across the entire interval. It also provided detailed information on the sequence of events during washout at the crossover tool. All of these allowed the operator to confidently maximize deliverability from the subject well, which is currently producing 110 MMcfd.
The results from this case history and the technique described should result in a step change in frac pack evaluation. Quantitative evaluation eliminates any doubts about the effectiveness of the annular pack and allows operators to produce their assets at maximum deliverability. Additionally, it assists future completion designs and type selection.
A gas well in GoM was drilled with Synthetic Oil-Based Mud (SOBM) to achieve acceptable completion efficiency. During the drilling phase more than 4,200 bbl of SOBM was lost to the pay zones. Wells within near proximity, drilled with SOBM in similar reservoirs had a history of emulsion problems with SOBM, heavy-density completion brines and frac pack fluids. Those wells experienced productivity issues related to high drawdowns due to emulsions that were visibly produced to surface. Remedial treatments were necessary to produce these wells effectively. The results after remedial treatments were effective, but did not maximize production to its full potential. Hence, prevention rather than remedial treatments of the emulsion was desired during planning of the new completion.
This paper examines the completion of a gas well, where efforts were made to prevent the formation of emulsions. Detailed laboratory testing and compatibility studies of the lost SOBM with heavy brine and frac pack fluid systems helped to select suitable chemical and surfactant packages. This emulsion prevention package was pumped ahead of frac pack fluids and was an inherent part of all the fluid systems injected into formation during completion phase.
This approach and application was utilized to complete two zones in this well. Production testing and flow back of both zones indicated the absence of any emulsion issues. Laboratory testing of the recovered fluid samples confirmed the nonappearance of any emulsions. The initial gas production from each zone is more than 5 MMscf/D at a low drawdown at its planned potential. The selection and application of a suitable chemical & surfactant additive system successfully prevented the emulsion problem.
Detailed laboratory studies and pre-planning helped to develop an emulsion prevention package, and its application prevented the formation of emulsions with successful production.
An offshore gas well in Gulf of Mexico was drilled with Synthetic Oil-Based Mud (SOBM). The original hole was drilled with water-based mud, but during the drilling process the drill pipe got stuck. Therefore, the drilling fluid was changed over to 15 ppg SOBM to drill a sidetracked hole. The pay zones of this well are multi-layered, and the lower zones had higher formation pressures. In the process of drilling the lower zones, huge losses of SOBM were experienced due to the mud-induced fractures. In this situation, mud losses occurrs when the mud density is increased to control the increased formation pressure3. In this well scenario, since the mud pressure gradient (15 ppg) exceeded the fracture gradient (14.8 ppg, as measured from mini-frac analysis), fractures were induced and cumulative losses of more than 4,200 bbl of SOBM were experienced.
Earlier, two offshore gas wells in GoM were drilled with 17 ppg SOBM and had experienced some fluid losses to the formation. These wells faced severe influx problems and neither of the two gravel-packed completed zones flowed after completion operations. Both wells experienced severe emulsion problems and also produced emulsion samples that exhibited "peanut butter?? consistency. Successful remedial treatments were performed to address the tendency for emulsions to form between the completion brine and SOBM filtrate5. Both wells' productivity after the remedial treatments showed marked improvement, but production did not reach the wells' expected potential. The lessons learned from the emulsion problems and treatments in these wells were evaluated to formulate a emulsion prevention method for the well discussed in this paper.