A comprehensive evaluation strategy offers a better return on investment.

Getting the most from existing wells requires making the most of advanced tools and services. Critical evaluation of the potential benefits of advanced technologies in remedial well operations reveals that greater success can perhaps be achieved with a holistic approach than with a disjointed, "penny wise and pound foolish" approach to each phase of operations.

For operator PT Caltex Pacific Indonesia (CPI), applying such a strategy to a fracture stimulation program resulted in a production gain improvement of 190% and a payout time improvement of 33%, compared to previous fracturing jobs. This was accomplished in a mature field PT CPI operated in Indonesia.
Part of the strategy involved focusing on the outcome - the overall value provided - rather than simply the cost of tools and services. An equally important part of the strategy was the selection of a performance-driven, methodical approach using Schlumberger's PowerStim well optimization service to evaluate and implement steps to reach production objectives. Random attempts at "no-kill" remediation and assorted workover approaches such as reperforation, redrilling, sealing selected perforations and installation of various completion components would have proven extremely costly in the long run.

While the PowerStim service required a longer payout time than a conventional workover program and accounted for 88% of total costs, it produced better economic returns. Wells in this 20-year-old field experienced a sustained increase in oil rate from 273 b/d of oil to 932 b/d of oil (evident even after a 30-day producing period), with 100% of risked services paid out within 30 days.

Step-by-step evaluation

A conventional stimulation job involves only two processes: treatment design and onsite execution. The Schlumberger PowerStim service on the other hand, involves seven evaluation processes: geologic assessment, reservoir assessment, well testing, well completion design, treatment design, onsite execution and post-job evaluation.

Geologic assessment. Team members assimilate an understanding of reservoir models, evaluate input to geological models, define structural and stratigraphic plays and interpret the depositional environment.
Reservoir assessment. This step involves analysis of log and core data and offset wells, developing local interpretation models, applying fit-for-purpose technology, developing a 3-D fracture data set and finalizing prefracture reservoir characterization.

Well testing. The team designs and reviews pressure buildup tests, analyzing any flowing pressure and rate data and making performance forecasts.

Well completion design. Designers recommend perforation intervals, optimizing casing, tubulars and artificial lift, fitting appropriate new technologies into the plan.

Treatment design. Next the team pilot-tests fracturing fluids, applying treatment models and expertise to optimize a fracture treatment.

Onsite execution. The team performs quality assurance and quality control, ensures design criteria are met, supervises implementation of the pumping schedule and analyzes diagnostic tests.
Post-job evaluation. Finally, the team analyzes post-treatment data, performs post-treatment production data analysis and designs and analyzes a post-treatment pressure transient test.
These processes are interwoven in two phases of operation.

Two-phase approach

With a typical PowerStim service arrangement, Phase 1 includes development of basin- and reservoir-specific interpretation and completion models, development and documentation of new completion techniques, and a summary report that outlines an implementation plan. Modifications to the conventional completion techniques in this phase might include the recommendation to upgrade from low-tech perforating to a more state-of-the-art perforating program. The reservoir portion of the service could include an assessment of the best way to gather reservoir information - for example, recommendations on proper bit selection to facilitate the acquisition of cleaner log data that can enhance the quality of reservoir data and lead to drilling savings.

Reservoir characterization could involve addressing permeability rather than porosity cutoffs, using magnetic resonance, dipole sonic and selected formation imaging tools. Such adjustments are presented with an idea of the potential for production increases that can be obtained with a new approach.
Phase 2 deliverables include solutions based on the new interpretation and completion models from Phase 1, models and solutions applicable to future development wells and workover candidates, and a completion design, evaluation and execution plan.

Real-time data are used to improve processes designed to stimulate oil and gas well performance. Extensive evaluation of treatment effectiveness provides a feedback mechanism for ongoing improvement of future designs.

Optimizing stimulation treatments requires a step change in delivery of formation evaluation, reservoir characterization and stimulation and completion services. The PowerStim service process relies on a range of advanced technologies, the latest Web-enabled tools and joint oil company-service provider geoscience and engineering teams.

Dusun Field challenges

PT CPI's objectives in this case were to:

• increase productivity in the upper of two sand packages (A) through fracturing;
• identify potential productive layers in a lower sand package (B); and
• optimize artificial lift performance.

An extremely low recovery rate (5%) in the A Sand made this interval an attractive target. At the same time, the B Sand had been producing much of the water and was considered a good candidate for squeezing and selective perforating in order to optimally produce bypassed oil intervals. Success depended on isolating water-producing zones in the B Sand and producing the A Sand after fracturing to improve overall lifting costs.

Several uncertainties existed in the field. There was no core data, no stress analysis, incomplete seismic data and an inability to perform a transient test in the A Sand due to its low productivity. A heightened concern over major problems associated with water breakthrough hampered operations. The cost of water handling and disposal was increasing.

The Caltex-Schlumberger team divided the work into two phases. In the first phase, expert teams used existing field data and detailed analyses to accurately predict key variables and forecast production. These results were used to generate completion and stimulation designs for the project.

In the second phase, the PowerStim team refined the design using newly acquired data to optimize workover operations across the field. Lessons learned were captured during post-workover evaluations to improve future wells. This approach was significantly different than that followed in the past, where fracturing treatments were based on designs developed using limited data, with little or no post-job evaluation.

Well-specific solutions

The operator applied the process to this somewhat complex reservoir with impressive results. Following an evaluation, team members planned to run a Cased Hole Formation Resistivity (CHFR) tool to identify remaining oil zones and a Casing Bond Log/Ultrasonic Imaging Tool to verify cement bond. The ability of these tools to detect and evaluate bypassed hydrocarbons and track fluid movement in the reservoir is fundamental to improving production and increasing reserves. The CHFR tool provides a range of saturation measurements that is a significant improvement over the range of data produced by the pulsed neutron nuclear logging tools typically used for behind-casing evaluation.

Based on the information obtained, the team recommended isolating depleted water-producing zones with a cast iron bridge plug (CIBP) or cement squeeze operations. Potential oil zones were to be reperforated and, in some cases, newly perforated. Fracturing operations to increase the production index were scheduled for the A Sand, and designs called for the A Sand to be individually produced or commingled with an additional interval (2,080-ft, 634-m sand) using a submersible pumping system (SPS). Commingling of the two zones was possible since there was no significant pressure difference between the two sands that would induce crossflow.

The operator reperforated Well No. 1 in the A Sand prior to fracturing due to the inability to establish a rate during the injectivity test. Only the A Sand was produced in this well with a SPS, later replaced with an HPU. A CIBP isolated the B Sand, based on data from the CHFR.

The operator discovered, perforated and fractured a new interval, the A2 Sand, in the second well in the field. In this case, the A1 Sand was fractured separately. In this well the A Sand was produced with a submersible pump, later replaced with a hydraulic pumping unit.

In Well No. 4, the A Sand was fractured, and two oil intervals in the B Sand were reperforated. Production from the A Sand and the B Sand was commingled with an SPS.

Total water production for the three wells decreased from 94% to 68%. Two of the wells had extremely high water cut, which continued to increase, particularly in the high-permeability layers. While the PowerStim approach led to a higher cost per well when compared to conventional fracturing treatments and prior workover programs in the same field, and a slightly higher payout time compared to prior workovers (Figure 1), the service significantly improved the overall oil gain and payout time per well when compared to previous fracturing projects.

Remedial operations in mature fields continue to be some of the most complex, with many options and significant information gaps. In the economic scheme of things, PT CPI's priority of keeping wells that are still producing operating at optimal rates to meet production quotas is a wise move. An approach that recognizes the ultimate economic wisdom of upfront investments to gather and evaluate data that can direct well-specific solutions is an important part of achieving that goal.